0001109357June 30, 2021false2021Q2December 3100011681650000022606000007810000000094660001135971000007973200000278790000008192Cumulative Preferred Security, Series D0000.511110.511110.511110.511110.511110.511110000000000000000000000000000000000010001109357exc:EquitySecuritiesNuclearDecommissioningTrustFundMemberus-gaap:FairValueMeasurementsRecurringMemberus-gaap:FairValueMeasuredAtNetAssetValuePerShareMember2020-12-310001109357us-gaap:FairValueInputsLevel3Memberus-gaap:DerivativeMember2021-06-30
0001109357 exc:GenerationAllOtherSegmentsMember 2020-01-01 2020-06-30 0001109357 exc:BaltimoreGasAndElectricCompanyMember exc:PublicAuthoritiesElectricRailroadsMember us-gaap:ElectricityUsRegulatedMember us-gaap:RegulatedOperationMember 2019-01-01 2019-06-30 0001109357 exc:CommonwealthEdisonCoMember us-gaap:CommercialPaperMember 2020-06-30 0001109357 exc:ExelonGenerationCoLLCMember srt:MaximumMember us-gaap:DerivativeMember us-gaap:FairValueInputsLevel3Member us-gaap:IncomeApproachValuationTechniqueMember 2019-12-31 0001109357 srt:MaximumMember us-gaap:DerivativeMember us-gaap:FairValueInputsLevel3Member exc:OptionModelValuationTechniqueMember 2020-06-30
UNITED STATES SECURITIES AND EXCHANGE COMMISSION
Washington, D.C. 20549
FORM 10-Q
☒QUARTERLY REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934
For the Quarterly Period Ended June 30, 20202021
or
☐TRANSITION REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934
Commission File NumberName 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
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

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  x  No  o

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  x  No  o

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 Filer☐Non-accelerated Filer☐Smaller Reporting Company☐Emerging Growth Company☐
Exelon Generation Company, LLCLarge Accelerated Filer☐Accelerated Filer☐Non-accelerated FilerxSmaller Reporting Company☐Emerging Growth Company☐
Commonwealth Edison CompanyLarge Accelerated Filer☐Accelerated Filer☐Non-accelerated FilerxSmaller Reporting Company☐Emerging Growth Company☐
PECO Energy CompanyLarge Accelerated Filer☐Accelerated Filer☐Non-accelerated FilerxSmaller Reporting Company☐Emerging Growth Company☐
Baltimore Gas and Electric CompanyLarge Accelerated Filer☐Accelerated Filer☐Non-accelerated FilerxSmaller Reporting Company☐Emerging Growth Company☐
Pepco Holdings LLCLarge Accelerated Filer☐Accelerated Filer☐Non-accelerated FilerxSmaller Reporting Company☐Emerging Growth Company☐
Potomac Electric Power CompanyLarge Accelerated Filer☐Accelerated Filer☐Non-accelerated FilerxSmaller Reporting Company☐Emerging Growth Company☐
Delmarva Power & Light CompanyLarge Accelerated Filer☐Accelerated Filer☐Non-accelerated FilerxSmaller Reporting Company☐Emerging Growth Company☐
Atlantic City Electric CompanyLarge Accelerated Filer☐Accelerated Filer☐Non-accelerated FilerxSmaller Reporting Company☐Emerging 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. ☐

Indicate by check mark whether the registrant is a shell company (as defined in Rule 12b-2 of the Act).  Yes  ☐  No  x

The number of shares outstanding of each registrant’s common stock as of June 30, 20202021 was:
Exelon Corporation Common Stock, without par value974,503,895977,832,660
Exelon Generation Company, LLCnot applicable
Commonwealth Edison Company Common Stock, $12.50 par value127,021,354127,021,380
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



TABLE OF CONTENTS

Page No.
4
8
8
8
9
9
Exelon Corporation
Consolidated Statements of Operations and Comprehensive Income
10
Consolidated Statements of Cash Flows
11
Consolidated Balance Sheets
12
Consolidated Statements of Changes in Shareholders’ Equity
14
Exelon Generation Company, LLC
Consolidated Statements of Operations and Comprehensive Income
16
Consolidated Statements of Cash Flows
17
Consolidated Balance Sheets
18
Consolidated Statements of Changes in Equity
20
Commonwealth Edison Company
Consolidated Statements of Operations and Comprehensive Income
21
Consolidated Statements of Cash Flows
22
Consolidated Balance Sheets
23
Consolidated Statements of Changes in Shareholders' Equity
25
PECO Energy Company
Consolidated Statements of Operations and Comprehensive Income
26
Consolidated Statements of Cash Flows
27
Consolidated Balance Sheets
28
Consolidated Statements of Changes in Shareholder's Equity
30
Baltimore Gas and Electric Company
Statements of Operations and Comprehensive Income
31
Statements of Cash Flows
32
Balance Sheets
33
Statements of Changes in Shareholder's Equity
35
Pepco Holdings LLC
Consolidated Statements of Operations and Comprehensive Income
36
Consolidated Statements of Cash Flows
37
Consolidated Balance Sheets
38
Consolidated Statements of Changes in Member's Equity
40
1




Page No.
Potomac Electric Power Company
Statements of Operations and Comprehensive Income
41
Statements of Cash Flows
42
Balance Sheets
43
Statements of Changes in Shareholder's Equity
45
Delmarva Power & Light Company
Statements of Operations and Comprehensive Income
46
Statements of Cash Flows
47
Balance Sheets
48
Statements of Changes in Shareholder’s Equity
50
Atlantic City Electric Company
Consolidated Statements of Operations and Comprehensive Income
51
Consolidated Statements of Cash Flows
52
Consolidated Balance Sheets
53
Consolidated Statements of Changes in Shareholder’s Equity
55
Combined Notes to Consolidated Financial Statements
1. Significant Accounting Policies
56
2. Mergers, Acquisitions and Dispositions
57
3. Regulatory Matters
58
4. Revenue from Contracts with Customers
66
5. Segment Information
69
6. Accounts Receivable
84
7. Early Plant Retirements
89
8. Nuclear Decommissioning
93
9. Asset Impairments
94
10. Income Taxes
95
11. Retirement Benefits
98
12. Derivative Financial Instruments
100
13. Debt and Credit Agreements
107
14. Fair Value of Financial Assets and Liabilities
110
15. Commitments and Contingencies
121
16. Changes in Accumulated Other Comprehensive Income
130
17. Variable Interest Entities
131
18. Supplemental Financial Information
136
19. Related Party Transactions
142
20. Planned Separation
145
2




Page No.
Page No.
FILING FORMAT
8
CAUTIONARY STATEMENTS REGARDING FORWARD-LOOKING INFORMATION
8
WHERE TO FIND MORE INFORMATION
8
PART I.
FINANCIAL INFORMATION
9
ITEM 1.
FINANCIAL STATEMENTS
9
Exelon Corporation
Consolidated Statements of Operations and Comprehensive Income
10
Consolidated Statements of Cash Flows
11
Consolidated Balance Sheets
12
Consolidated Statements of Changes in Shareholders’ Equity
14
Exelon Generation Company, LLC
Consolidated Statements of Operations and Comprehensive Income
16
Consolidated Statements of Cash Flows
17
Consolidated Balance Sheets
18
Consolidated Statements of Changes in Equity
20
Commonwealth Edison Company
Consolidated Statements of Operations and Comprehensive Income
21
Consolidated Statements of Cash Flows
22
Consolidated Balance Sheets
23
Consolidated Statements of Changes in Shareholders' Equity
25
PECO Energy Company
Consolidated Statements of Operations and Comprehensive Income
26
Consolidated Statements of Cash Flows
27
Consolidated Balance Sheets
28
Consolidated Statements of Changes in Shareholder's Equity
30
Baltimore Gas and Electric Company
Statements of Operations and Comprehensive Income
31
Statements of Cash Flows
32
Balance Sheets
33
Statements of Changes in Shareholder's Equity
35
Pepco Holdings LLC
Consolidated Statements of Operations and Comprehensive Income
36
Consolidated Statements of Cash Flows
37
Consolidated Balance Sheets
38
Consolidated Statements of Changes in Equity
40

Page No.
Potomac Electric Power Company
Statements of Operations and Comprehensive Income
41
Statements of Cash Flows
42
Balance Sheets
43
Statements of Changes in Shareholder's Equity
45
Delmarva Power & Light Company
Statements of Operations and Comprehensive Income
46
Statements of Cash Flows
47
Balance Sheets
48
Statements of Changes in Shareholder’s Equity
50
Atlantic City Electric Company
Consolidated Statements of Operations and Comprehensive Income
51
Consolidated Statements of Cash Flows
52
Consolidated Balance Sheets
53
Consolidated Statements of Changes in Shareholder’s Equity
55
Combined Notes to Consolidated Financial Statements
1. Significant Accounting Policies
56
2. Regulatory Matters
58
3. Revenue from Contracts with Customers
64
4. Segment Information
66
5. Accounts Receivable
81
6. Early Plant Retirements
84
7. Nuclear Decommissioning
87
8. Asset Impairments
88
9. Income Taxes
89
10. Retirement Benefits
93
11. Derivative Financial Instruments
95
12. Debt and Credit Agreements
101
13. Fair Value of Financial Assets and Liabilities
104
14. Commitments and Contingencies
117
15. Changes in Accumulated Other Comprehensive Income
125
16. Variable Interest Entities
126
17. Supplemental Financial Information
131
18. Related Party Transactions
137
19. Subsequent Events
140

Page No.
ITEM 2.
MANAGEMENT’S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS
141146
Exelon Corporation
141146
Executive Overview
141146
Financial Results of Operations
143146
Significant 20202021 Transactions and Developments
147151
Other Key Business Drivers and Management Strategies
149154
Critical Accounting Policies and Estimates
151156
Results of Operations By Registrant
151156
Exelon Generation Company, LLC
152157
Commonwealth Edison Company
159164
PECO Energy Company
162167
Baltimore Gas and Electric Company
166171
Pepco Holdings LLC
169174
Potomac Electric Power Company
170175
Delmarva Power & Light Company
173178
Atlantic City Electric Company
177182
Liquidity and Capital Resources
181185
Contractual Obligations and Off-Balance Sheet Arrangements
188193
189194
194198
194199
194199
194199
195199
195199
200
203
203
204
205
206
207
208
209
210
211
3



Table of Contents
GLOSSARY OF TERMS AND ABBREVIATIONS
Exelon Corporation and Related Entities
ExelonExelon Corporation
199
Generation
Exelon Generation Company, LLC
200
ComEd
Commonwealth Edison Company
201
PECO
PECO Energy Company
202
BGE
Baltimore Gas and Electric Company
203
Pepco Holdings or PHI
Pepco Holdings LLC
204
Pepco
Potomac Electric Power Company
205
DPL
Delmarva Power & Light Company
206
ACE
Atlantic City Electric Company
207

Registrants
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 PHIPepco Holdings LLC (formerly Pepco Holdings, Inc.)
PepcoPotomac Electric Power Company
DPLDelmarva Power & Light Company
ACEAtlantic City Electric Company
RegistrantsExelon, Generation, ComEd, PECO, BGE, PHI, Pepco, DPL, and ACE, collectively
Utility RegistrantsComEd, PECO, BGE, Pepco, DPL, and ACE, collectively
ACE Funding or ATFAtlantic City Electric Transition Funding LLC
Antelope ValleyAntelope Valley Solar Ranch One
BSC
BSCExelon Business Services Company, LLC
CENGConstellation Energy Nuclear Group, LLC
ConstellationConstellation Energy Group, Inc.
EGR IVExGen Renewables IV, LLC
EGRPExGen Renewables Partners, LLC
Exelon CorporateExelon in its corporate capacity as a holding company
FitzPatrickJames A. FitzPatrick nuclear generating station
NERNewEnergy Receivables LLC
PCIPotomac Capital Investment Corporation and its subsidiaries
PECO Trust IIIPECO Energy Capital Trust III
PECO Trust IVPECO Energy Capital Trust IV
Pepco Energy ServicesPepco Energy Services, Inc. and its subsidiaries
PHI CorporatePHI in its corporate capacity as a holding company
PHISCOPHI Service Company
SolGenRPGSolGen, LLCRenewable Power Generation
TMISolGenSolGen, LLC
TMIThree Mile Island nuclear facility

4



Table of Contents
GLOSSARY OF TERMS AND ABBREVIATIONS
Other Terms and Abbreviations
Note "—"- of the 20192020 Form 10-KReference to specific Combined Note to Consolidated Financial Statements within Exelon’s 2019Exelon's 2020 Annual Report on Form 10-K
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
AMI
AMIAdvanced Metering Infrastructure
AOCI
AOCIAccumulated Other Comprehensive Income (Loss)
ARCAsset Retirement Cost
AROAsset Retirement Obligation
BGS
BGSBasic Generation Service
CBA
CBACollective Bargaining Agreement

CERCLAComprehensive Environmental Response, Compensation, and Liability Act of 1980, as amended
CESClean Energy Standard
Clean Water ActFederal Water Pollution Control Amendments of 1972, as amended
CODMChief operating decision maker(s)
D.C. Circuit CourtUnited States Court of Appeals for the District of Columbia Circuit
DC PLUGDistrict of Columbia Power Line Undergrounding Initiative
DCPSCPublic Service Commission of the District of Columbia
DOE
DOEUnited States Department of Energy
DOEEDistrict of Columbia Department of Energy & Environment
DOJUnited States Department of Justice
DPPDeferred Purchase Price
DPSCDelaware Public Service Commission
EDF
EDFElectricite de France SA and its subsidiaries
EIMA
EIMAEnergy Infrastructure Modernization Act (Illinois Senate Bill 1652 and Illinois House Bill 3036)
EPA
EPAUnited States Environmental Protection Agency
ERCOT
ERCOTElectric Reliability Council of Texas
FASBFinancial Accounting Standards Board
FEJA
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
GCRGas Cost Rate
GSAGHGGreenhouse Gas
GSAGeneration Supply Adjustment
IBEW
International Brotherhood of Electrical Workers

ICCIllinois Commerce Commission
ICEIntercontinental Exchange

GLOSSARY OF TERMS AND ABBREVIATIONSIBEWInternational Brotherhood of Electrical Workers
Other Terms and AbbreviationsICCIllinois Commerce Commission
IPAICEIntercontinental Exchange
IPAIllinois Power Agency
IRCInternal Revenue Code
IRSInternal Revenue Service
ISOIndependent System Operator
ISO-NEIndependent System Operator New England Inc.
LIBOR
5



Table of Contents
GLOSSARY OF TERMS AND ABBREVIATIONS
Other Terms and Abbreviations
LIBORLondon Interbank Offered Rate
MDE
MDEMaryland Department of the Environment
MDPSCMaryland Public Service Commission
MGPManufactured Gas Plant
MISOMidcontinent Independent System Operator, Inc.
mmcfMillion Cubic Feet
MOPR
MOPRMinimum Offer Price Rule
MWMegawatt
MWhMPSCMegawatt hourMissouri Public Service Commission
NDTMWMegawatt
MWhMegawatt hour
NAVNet Asset Value
N/ANot applicable
NDTNuclear Decommissioning Trust
NERC
NERCNorth American Electric Reliability Corporation
NGXNatural Gas Exchange
NJBPUNew Jersey Board of Public Utilities
Non-Regulatory AgreementsAgreement UnitsNuclear generating units or portions thereof whose decommissioning-related activities are not subject to contractual elimination under regulatory accounting
NOSANuclear Operating Services Agreement
NPNS
NPNSNormal Purchase Normal Sale scope exception
NRCNPSNational Park Service
NRCNuclear Regulatory Commission
NYISO
NYISONew York Independent System Operator Inc.
NYMEXNew York Mercantile Exchange
NYPSCNew York Public Service Commission
OCIOther Comprehensive Income
OIESOOntario Independent Electricity System Operator
OPEB
OPEBOther Postretirement Employee Benefits
PAPUC
PAPUCPennsylvania Public Utility Commission
PGC
PGCPurchased Gas Cost Clause
PG&EPacific Gas and Electric Company
PJMPJM Interconnection, LLC
POLRProvider of Last Resort
PPA
PPAPower Purchase Agreement
PPEProperty, plant and equipment
Price-Anderson ActPrice-Anderson Nuclear Industries Indemnity Act of 1957
PRP
PRPPotentially Responsible Parties
PSDARPost-Shutdown Decommissioning Activities Report
PSEGPublic Service Enterprise Group Incorporated
REC
PUCTPublic Utility Commission of Texas
RECRenewable Energy Credit which is issued for each megawatt hour of generation from a qualified renewable energy source

GLOSSARY OF TERMS AND ABBREVIATIONS
Other Terms and Abbreviations
RNFRevenues Net of Purchased Power and Fuel Expense
Regulatory Agreement UnitsNuclear generating units or portions thereof whose decommissioning-related activities are subject to contractual elimination under regulatory accounting
RFP
RFPRequest for Proposal
RiderReconcilable Surcharge Recovery Mechanism
RMCRisk Management Committee
6



Table of Contents
ROEGLOSSARY OF TERMS AND ABBREVIATIONS
Other Terms and Abbreviations
RNFRevenues Net of Purchased Power and Fuel Expense
ROEReturn on equity
ROURight-of-use
RTO
RTORegional Transmission Organization
S&PStandard & Poor’s Ratings Services
SECUnited States Securities and Exchange Commission
SERC
SERCSERC Reliability Corporation (formerly Southeast Electric Reliability Council)
SNF
SNFSpent Nuclear Fuel
SOSStandard Offer Service
SPFPA
International Union, Security, Police and Fire Professionals of America

TCJATax Cuts and Jobs Act
STRIDEMaryland Strategic Infrastructure Development and Enhancement Program
Transition BondsTransition Bonds issued by ACE Funding
VIE
UGSOAUnited Government Security Officers of America
VIEVariable Interest Entity
WECCWestern Electric Coordinating Council
ZECZero Emission Credit, or Zero Emission Certificate
ZESZero Emission Standard

7



Table of Contents
FILING FORMAT
This combined Form 10-Q 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 orbenefits associated with the potential impactseparation of the novel coronavirus (COVID-19) pandemic,Exelon’s competitive power generation and the related responses of various governmentscustomer-facing energy business from its six regulated electric and regulatory bodies, our customers, and the company, on our business, financial condition and results of operations; any such forward-looking statements, whether concerning the COVID-19 pandemic or otherwise, involve risks, assumptions and uncertainties.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, as well as the items discussed in (1) the Registrants' combined 20192020 Annual Report on Form 10-K 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, and (c) Part II, ITEM 8. Financial Statements and Supplementary Data: Note 18,19, Commitments and Contingencies; (2) this Quarterly Report on Form 10-Q in (a) Part II, ITEM 1A. Risk Factors;Factors, (b) Part I, ITEM 2. Management’s Discussion and Analysis of Financial Condition and Results of Operations, and (c) Part I, ITEM 1. Financial Statements: Note 14,15, Commitments and Contingencies; and (3) other factors discussed in filings with the SEC by the Registrants.
Investors are cautioned not to place undue reliance on these forward-looking statements, whether written or oral, 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.

8



Table of Contents
PART I. FINANCIAL INFORMATION
ItemITEM 1. Financial StatementsFINANCIAL STATEMENTS

9



Table of Contents

EXELON CORPORATION AND SUBSIDIARY COMPANIES
CONSOLIDATED STATEMENTS OF OPERATIONS AND COMPREHENSIVE INCOME
(Unaudited)
Three Months Ended
June 30,		 Six Months Ended
June 30,		Three Months Ended
June 30,		Six Months Ended
June 30,
(In millions, except per share data)2020 2019 2020 2019(In millions, except per share data)2021202020212020
Operating revenues       Operating revenues
Competitive businesses revenues$3,611
 $3,959
 $8,014
 $8,938
Competitive businesses revenues$3,900 $3,612 $9,165 $8,016 
Rate-regulated utility revenues3,832
 3,743
 8,108
 8,247
Rate-regulated utility revenues3,968 3,832 8,464 8,108 
Revenues from alternative revenue programs(122) (13) (55) (19)Revenues from alternative revenue programs47 (122)176 (55)
Operating revenue from affiliates1
 —
 2
 —
Total operating revenues7,322
 7,689
 16,069
 17,166
Total operating revenues7,915 7,322 17,805 16,069 
Operating expenses       Operating expenses
Competitive businesses purchased power and fuel1,945
 2,289
 4,655
 5,493
Competitive businesses purchased power and fuel1,952 1,945 6,562 4,655 
Rate-regulated utility purchased power and fuel979
 936
 2,136
 2,285
Rate-regulated utility purchased power and fuel1,064 979 2,422 2,136 
Operating and maintenance2,433
 2,159
 4,637
 4,347
Operating and maintenance2,447 2,433 4,426 4,637 
Depreciation and amortization1,001
 1,079
 2,023
 2,154
Depreciation and amortization1,666 1,001 3,363 2,023 
Taxes other than income taxes411
 418
 847
 863
Taxes other than income taxes432 411 870 847 
Total operating expenses6,769

6,881

14,298

15,142
Total operating expenses7,561 6,769 17,643 14,298 
Gain on sales of assets and businesses12
 33
 13
 36
Gain on sales of assets and businesses12 12 83 13 
Operating income565

841

1,784

2,060
Operating income366 565 245 1,784 
Other income and (deductions)    
 
Other income and (deductions)
Interest expense, net(421) (403) (824) (800)Interest expense, net(390)(421)(770)(824)
Interest expense to affiliates(6) (6) (13) (13)Interest expense to affiliates(6)(6)(13)(13)
Other, net656
 212
 (68) 679
Other, net581 656 806 (68)
Total other income and (deductions)229

(197)
(905)
(134)Total other income and (deductions)185 229 23 (905)
Income before income taxes794
 644
 879
 1,926
Income before income taxes551 794 268 879 
Income taxes219
 144
 (75) 454
Income taxes74 219 55 (75)
Equity in losses of unconsolidated affiliates(1) (6) (4) (12)Equity in losses of unconsolidated affiliates(1)(1)(2)(4)
Net income574

494

950

1,460
Net income476 574 211 950 
Net income (loss) attributable to noncontrolling interests53
 10
 (153) 69
Net income (loss) attributable to noncontrolling interests75 53 99 (153)
Net income attributable to common shareholders$521

$484

$1,103

$1,391
Net income attributable to common shareholders$401 $521 $112 $1,103 
Comprehensive income, net of income taxes       Comprehensive income, net of income taxes
Net income$574
 $494
 $950
 $1,460
Net income$476 $574 $211 $950 
Other comprehensive income (loss), net of income taxes       Other comprehensive income (loss), net of income taxes
Pension and non-pension postretirement benefit plans:       Pension and non-pension postretirement benefit plans:
Prior service benefit reclassified to periodic benefit cost(10) (16) (20) (32)Prior service benefit reclassified to periodic benefit cost(1)(10)(2)(20)
Actuarial loss reclassified to periodic benefit cost47
 36
 94
 74
Actuarial loss reclassified to periodic benefit cost56 47 112 94 
Pension and non-pension postretirement benefit plan valuation adjustment2
 —
 (5) (39)Pension and non-pension postretirement benefit plan valuation adjustment0 2 (2)(5)
Unrealized loss on cash flow hedges—
 —
 (1) —
Unrealized loss on cash flow hedges0 0 0 (1)
Unrealized loss on investments in unconsolidated affiliates—
 (2) —
 (4)
Unrealized gain (loss) on foreign currency translation2
 3
 (6) 4
Unrealized gain (loss) on foreign currency translation2 2 3 (6)
Other comprehensive income41

21

62

3
Other comprehensive income57 41 111 62 
Comprehensive income615

515

1,012

1,463
Comprehensive income533 615 322 1,012 
Comprehensive income (loss) attributable to noncontrolling interests53
 9
 (153) 67
Comprehensive income (loss) attributable to noncontrolling interests75 53 99 (153)
Comprehensive income attributable to common shareholders$562
 $506
 $1,165
 $1,396
Comprehensive income attributable to common shareholders$458 $562 $223 $1,165 
       
Average shares of common stock outstanding:       Average shares of common stock outstanding:
Basic976
 972
 975
 972
Basic978 976 978 975 
Assumed exercise and/or distributions of stock-based awards—
 2
 1
 1
Assumed exercise and/or distributions of stock-based awards1 0 1 1 
Diluted(a)
976
 974
 976
 973
979 976 979 976 
       
Earnings per average common share:       
Earnings per average common shareEarnings per average common share
Basic$0.53
 $0.50
 $1.13
 $1.43
Basic$0.41 $0.53 $0.11 $1.13 
Diluted(a)$0.53
 $0.50
 $1.13
 $1.43
DilutedDiluted$0.41 $0.53 $0.11 $1.13 
__________
(a)The number of stock options not included in the calculation of diluted common shares outstanding due to their antidilutive effect was approximately 1 million and immaterial for the three and six months ended June 30, 2020, respectively, and immaterial for the three and six months ended June 30, 2019.

(a)The number of stock options not included in the calculation of diluted common shares outstanding due to their antidilutive effect was zero for the three and six months ended June 30, 2021 and 1 million and less than 1 million for the three and six months ended June 30, 2020, respectively.
See the Combined Notes to Consolidated Financial Statements
10



Table of Contents
EXELON CORPORATION AND SUBSIDIARY COMPANIES
CONSOLIDATED STATEMENTS OF CASH FLOWS
(Unaudited)
Six Months Ended
June 30,
(In millions)20212020
Cash flows from operating activities
Net income$211 $950 
Adjustments to reconcile net income to net cash flows provided by operating activities:
Depreciation, amortization, and accretion, including nuclear fuel and energy contract amortization4,180 2,741 
Asset impairments500 33 
Gain on sales of assets and businesses(83)(13)
Deferred income taxes and amortization of investment tax credits(163)33 
Net fair value changes related to derivatives(490)(194)
Net realized and unrealized (gains) losses on NDT funds(376)196 
Net unrealized gains on equity investments(96)0 
Other non-cash operating activities(331)671 
Changes in assets and liabilities:
Accounts receivable(16)1,318 
Inventories1 (14)
Accounts payable and accrued expenses(87)(798)
Option premiums received (paid), net2 (102)
Collateral received, net957 340 
Income taxes190 (114)
Pension and non-pension postretirement benefit contributions(559)(558)
Other assets and liabilities(2,702)(1,809)
Net cash flows provided by operating activities1,138 2,680 
Cash flows from investing activities
Capital expenditures(4,040)(3,773)
Proceeds from NDT fund sales4,438 2,488 
Investment in NDT funds(4,538)(2,540)
Collection of DPP2,209 1,102 
Proceeds from sales of assets and businesses724 0 
Other investing activities17 4 
Net cash flows used in investing activities(1,190)(2,719)
Cash flows from financing activities
Changes in short-term borrowings(666)(751)
Proceeds from short-term borrowings with maturities greater than 90 days500 500 
Issuance of long-term debt2,455 6,526 
Retirement of long-term debt(630)(3,894)
Dividends paid on common stock(747)(746)
Proceeds from employee stock plans47 46 
Other financing activities(64)(84)
Net cash flows provided by financing activities895 1,597 
Increase in cash, restricted cash, and cash equivalents843 1,558 
Cash, restricted cash, and cash equivalents at beginning of period1,166 1,122 
Cash, restricted cash, and cash equivalents at end of period$2,009 $2,680 
Supplemental cash flow information
Decrease in capital expenditures not paid$(313)$(105)
Increase in DPP1,958 1,754 
See the Combined Notes to Consolidated Financial Statements
11



 Six Months Ended
June 30,
(In millions)2020 2019
Cash flows from operating activities   
Net income$950
 $1,460
Adjustments to reconcile net income to net cash flows provided by operating activities:   
Depreciation, amortization and accretion, including nuclear fuel and energy contract amortization2,741
 2,922
Asset impairments33
 9
Gain on sales of assets and businesses(13) (33)
Deferred income taxes and amortization of investment tax credits33
 284
Net fair value changes related to derivatives(194) 107
Net realized and unrealized losses (gains) on NDT funds196
 (404)
Other non-cash operating activities671
 277
Changes in assets and liabilities:   
Accounts receivable1,318
 618
Inventories(14) 19
Accounts payable and accrued expenses(798) (924)
Option premiums (paid) received, net(102) 48
Collateral received (posted), net340
 (311)
Income taxes(114) 151
Pension and non-pension postretirement benefit contributions(558) (355)
Other assets and liabilities(1,809) (970)
Net cash flows provided by operating activities2,680

2,898
Cash flows from investing activities   
Capital expenditures(3,773) (3,572)
Proceeds from NDT fund sales2,488
 6,920
Investment in NDT funds(2,540) (6,847)
Collection of DPP1,102
 —
Proceeds from sales of assets and businesses—
 14
Other investing activities4
 26
Net cash flows used in investing activities(2,719)
(3,459)
Cash flows from financing activities   
Changes in short-term borrowings(751) 470
Proceeds from short-term borrowings with maturities greater than 90 days500
 —
Repayments on short-term borrowings with maturities greater than 90 days—
 (125)
Issuance of long-term debt6,526
 850
Retirement of long-term debt(3,894) (574)
Dividends paid on common stock(746) (704)
Proceeds from employee stock plans46
 75
Other financing activities(84) (34)
Net cash flows provided by (used in) financing activities1,597

(42)
Increase (decrease) in cash, cash equivalents and restricted cash1,558
 (603)
Cash, cash equivalents and restricted cash at beginning of period1,122
 1,781
Cash, cash equivalents and restricted cash at end of period$2,680

$1,178
    
Supplemental cash flow information   
Decrease in capital expenditures not paid$(105) $(133)
Increase in DPP1,754
 —
Increase in PPE related to ARO update—
 301

Table of Contents
EXELON CORPORATION AND SUBSIDIARY COMPANIES
CONSOLIDATED BALANCE SHEETS
(Unaudited)
(In millions)June 30, 2021December 31, 2020
ASSETS
Current assets
Cash and cash equivalents$1,578 $663 
Restricted cash and cash equivalents379 438 
Accounts receivable
Customer accounts receivable3,5333,597
Customer allowance for credit losses(395)(366)
Customer accounts receivable, net3,138 3,231 
Other accounts receivable1,4261,469
Other allowance for credit losses(72)(71)
Other accounts receivable, net1,354 1,398 
Mark-to-market derivative assets749 644 
Unamortized energy contract assets37 38 
Inventories, net
Fossil fuel and emission allowances259 297 
Materials and supplies1,443 1,425 
Regulatory assets1,252 1,228 
Renewable energy credits368 633 
Assets held for sale11 958 
Other1,780 1,609 
Total current assets12,348 12,562 
Property, plant, and equipment (net of accumulated depreciation and amortization of $28,783 and $26,727 as of June 30, 2021 and December 31, 2020, respectively)82,120 82,584 
Deferred debits and other assets
Regulatory assets8,745 8,759 
Nuclear decommissioning trust funds15,400 14,464 
Investments421 440 
Goodwill6,677 6,677 
Mark-to-market derivative assets443 555 
Unamortized energy contract assets278 294 
Other2,964 2,982 
Total deferred debits and other assets34,928 34,171 
Total assets(a)
$129,396 $129,317 
See the Combined Notes to Consolidated Financial Statements
12



(In millions)June 30, 2020 December 31, 2019
ASSETS   
Current assets   
Cash and cash equivalents$2,129
 $587
Restricted cash and cash equivalents373
 358
Accounts receivable   
Customer accounts receivable3,075 4,835
Customer allowance for credit losses(261) (243)
Customer accounts receivable, net2,814
 4,592
Other accounts receivable1,549 1,631
Other allowance for credit losses(61) (48)
Other accounts receivable, net1,488
 1,583
Mark-to-market derivative assets573
 679
Unamortized energy contract assets43
 47
Inventories, net   
Fossil fuel and emission allowances273
 312
Materials and supplies1,508
 1,456
Regulatory assets1,193
 1,170
Other2,139
 1,253
Total current assets12,533

12,037
Property, plant and equipment (net of accumulated depreciation and amortization of $24,798 and $23,979 as of June 30, 2020 and December 31, 2019, respectively)81,748
 80,233
Deferred debits and other assets   
Regulatory assets8,313
 8,335
Nuclear decommissioning trust funds12,730
 13,190
Investments424
 464
Goodwill6,677
 6,677
Mark-to-market derivative assets466
 508
Unamortized energy contract assets321
 336
Other3,101
 3,197
Total deferred debits and other assets32,032

32,707
Total assets(a)
$126,313

$124,977
Table of Contents

EXELON CORPORATION AND SUBSIDIARY COMPANIES
CONSOLIDATED BALANCE SHEETS
(Unaudited)
(In millions)June 30, 2020 December 31, 2019(In millions)June 30, 2021December 31, 2020
LIABILITIES AND SHAREHOLDERS’ EQUITY   LIABILITIES AND SHAREHOLDERS’ EQUITY
Current liabilities   Current liabilities
Short-term borrowings$1,119
 $1,370
Short-term borrowings$1,865 $2,031 
Long-term debt due within one year2,514
 4,710
Long-term debt due within one year3,633 1,819 
Accounts payable3,047
 3,560
Accounts payable3,547 3,562 
Accrued expenses1,616
 1,981
Accrued expenses1,719 2,078 
Payables to affiliates5
 5
Payables to affiliates5 5 
Regulatory liabilities495
 406
Regulatory liabilities686 581 
Mark-to-market derivative liabilities204
 247
Mark-to-market derivative liabilities719 295 
Unamortized energy contract liabilities113
 132
Unamortized energy contract liabilities95 100 
Renewable energy credit obligation478
 443
Renewable energy credit obligation509 661 
Liabilities held for saleLiabilities held for sale2 375 
Other1,474
 1,331
Other1,139 1,264 
Total current liabilities11,065
 14,185
Total current liabilities13,919 12,771 
Long-term debt36,112
 31,329
Long-term debt35,077 35,093 
Long-term debt to financing trusts390
 390
Long-term debt to financing trusts390 390 
Deferred credits and other liabilities   Deferred credits and other liabilities
Deferred income taxes and unamortized investment tax credits12,720
 12,351
Deferred income taxes and unamortized investment tax credits13,194 13,035 
Asset retirement obligations11,059
 10,846
Asset retirement obligations12,502 12,300 
Pension obligations3,659
 4,247
Pension obligations3,880 4,503 
Non-pension postretirement benefit obligations2,121
 2,076
Non-pension postretirement benefit obligations1,983 2,011 
Spent nuclear fuel obligation1,206
 1,199
Spent nuclear fuel obligation1,209 1,208 
Regulatory liabilities9,414
 9,986
Regulatory liabilities9,148 9,485 
Mark-to-market derivative liabilities440
 393
Mark-to-market derivative liabilities554 473 
Unamortized energy contract liabilities292
 338
Unamortized energy contract liabilities192 238 
Other2,964
 3,064
Other2,848 2,942 
Total deferred credits and other liabilities43,875
 44,500
Total deferred credits and other liabilities45,510 46,195 
Total liabilities(a)
91,442

90,404
Total liabilities(a)
94,896 94,449 
Commitments and contingencies

 

Commitments and contingencies00
Shareholders’ equity   Shareholders’ equity
Common stock (No par value, 2,000 shares authorized, 975 shares and 973 shares outstanding at June 30, 2020 and December 31, 2019, respectively)19,336
 19,274
Treasury stock, at cost (2 shares at June 30, 2020 and December 31, 2019)(123) (123)
Common stock (NaN par value, 2,000 shares authorized, 978 shares and 976 shares outstanding at June 30, 2021 and December 31, 2020, respectively)Common stock (NaN par value, 2,000 shares authorized, 978 shares and 976 shares outstanding at June 30, 2021 and December 31, 2020, respectively)19,454 19,373 
Treasury stock, at cost (2 shares at June 30, 2021 and December 31, 2020)Treasury stock, at cost (2 shares at June 30, 2021 and December 31, 2020)(123)(123)
Retained earnings16,622
 16,267
Retained earnings16,098 16,735 
Accumulated other comprehensive loss, net(3,132) (3,194)Accumulated other comprehensive loss, net(3,289)(3,400)
Total shareholders’ equity32,703

32,224
Total shareholders’ equity32,140 32,585 
Noncontrolling interests2,168
 2,349
Noncontrolling interests2,360 2,283 
Total equity34,871

34,573
Total equity34,500 34,868 
Total liabilities and shareholders’ equity$126,313

$124,977
Total liabilities and shareholders’ equity$129,396 $129,317 
__________
(a)Exelon’s consolidated assets include $9,937 million and $9,532 million at June 30, 2020 and December 31, 2019, respectively, of certain VIEs that can only be used to settle the liabilities of the VIE. Exelon’s consolidated liabilities include $3,542 million and $3,473 million at June 30, 2020 and December 31, 2019, respectively, of certain VIEs for which the VIE creditors do not have recourse to Exelon. See Note 16 — Variable Interest Entities for additional information.

(a)Exelon’s consolidated assets include $10,093 million and $10,200 million at June 30, 2021 and December 31, 2020, respectively, of certain VIEs that can only be used to settle the liabilities of the VIE. Exelon’s consolidated liabilities include $3,578 million and $3,598 million at June 30, 2021 and December 31, 2020, respectively, of certain VIEs for which the VIE creditors do not have recourse to Exelon. See Note 17 — Variable Interest Entities for additional information.
See the Combined Notes to Consolidated Financial Statements
13



Table of Contents
EXELON CORPORATION AND SUBSIDIARY COMPANIES
CONSOLIDATED STATEMENTS OF CHANGES IN SHAREHOLDERS’ EQUITY
(Unaudited)
Six Months Ended June 30, 2021
(In millions, shares
in thousands)		Issued
Shares		Common
Stock		Treasury
Stock		Retained
Earnings		Accumulated
Other
Comprehensive
Loss, net		Noncontrolling
Interests		Total Shareholders'
Equity
Balance, December 31, 2020977,466 $19,373 $(123)$16,735 $(3,400)$2,283 $34,868 
Net (loss) income— — — (289)— 25 (264)
Long-term incentive plan activity640 5 — — — — 5 
Employee stock purchase plan issuances902 34 — — — — 34 
Changes in equity of noncontrolling interests— — — — — (10)(10)
Common stock dividends
($0.38/common share)
— — — (374)— — (374)
Other comprehensive income, net of income taxes— — — — 54 — 54 
Balance, March 31, 2021979,008 $19,412 $(123)$16,072 $(3,346)$2,298 $34,313 
Net income— — — 401 — 75 476 
Long-term incentive plan activity237 24 — — — — 24 
Employee stock purchase plan issuances420 18 — — — — 18 
Changes in equity of noncontrolling interests— — — — — (13)(13)
Common stock dividends
($0.38/common share)
— — — (375)— — (375)
Other comprehensive income, net of income taxes— — — — 57 — 57 
Balance, June 30, 2021979,665 $19,454 $(123)$16,098 $(3,289)$2,360 $34,500 























See the Combined Notes to Consolidated Financial Statements
14



 Six Months Ended June 30, 2020
(In millions, shares
in thousands)
Issued
Shares
 
Common
Stock
 
Treasury
Stock
 
Retained
Earnings
 
Accumulated
Other
Comprehensive
Loss, net
 
Noncontrolling
Interests
 
Total Shareholders'
Equity
Balance, December 31, 2019974,416
 $19,274
 $(123) $16,267
 $(3,194) $2,349
 $34,573
Net income (loss)—
 —
 —
 582
 —
 (206) 376
Long-term incentive plan activity1,354
 (4) —
 —
 —
 —
 (4)
Employee stock purchase plan issuances470
 31
 —
 —
 —
 —
 31
Changes in equity of noncontrolling interests—
 —
 —
 —
 —
 (9) (9)
Sale of noncontrolling interests—
 2
 —
 —
 —
 —
 2
Common stock dividends
($0.38/common share)
—
 —
 —
 (374) —
 —
 (374)
Other comprehensive income, net of income taxes—
 —
 —
 —
 21
 —
 21
Balance, March 31, 2020976,240

$19,303

$(123)
$16,475

$(3,173)
$2,134

$34,616
Net income—
 —
 —
 521
 —
 53
 574
Long-term incentive plan activity148
 17
 —
 —
 —
 —
 17
Employee stock purchase plan issuances(51) 15
 —
 —
 —
 —
 15
Changes in equity of noncontrolling interests—
 —
 —
 —
 —
 (19) (19)
Sale of noncontrolling interests—
 1
 —
 —
 —
 —
 1
Common stock dividends
($0.38/common share)		—
 —
 —
 (374) —
 —
 (374)
Other comprehensive income, net of income taxes—
 —
 —
 —
 41
 —
 41
Balance, June 30, 2020976,337
 $19,336
 $(123) $16,622
 $(3,132) $2,168
 $34,871
Table of Contents





















EXELON CORPORATION AND SUBSIDIARY COMPANIES
CONSOLIDATED STATEMENTS OF CHANGES IN SHAREHOLDERS’ EQUITY
(Unaudited)

Six Months Ended June 30, 2020
(In millions, shares
in thousands)		Issued
Shares		Common
Stock		Treasury
Stock		Retained
Earnings		Accumulated
Other
Comprehensive
Loss, net		Noncontrolling
Interests		Total Shareholders'
Equity
Balance, December 31, 2019974,416 $19,274 $(123)$16,267 $(3,194)$2,349 $34,573 
Net income (loss)— — — 582 — (206)376 
Long-term incentive plan activity1,354 (4)— — — — (4)
Employee stock purchase plan issuances470 31 — — — — 31 
Changes in equity of noncontrolling interests— — — — — (9)(9)
Sale of noncontrolling interests— 2 — — — — 2 
Common stock dividends
($0.38/common share)
— — — (374)— — (374)
Other comprehensive income, net of income taxes— — — — 21 — 21 
Balance, March 31, 2020976,240 $19,303 $(123)$16,475 $(3,173)$2,134 $34,616 
Net income— — — 521 — 53 574 
Long-term incentive plan activity148 17 — — — — 17 
Employee stock purchase plan issuances(51)15 — — — — 15 
Changes in equity of noncontrolling interests— — — — — (19)(19)
Sale of noncontrolling interests— 1 — — — — 1 
Common stock dividends
($0.38/common share)
— — — (374)— — (374)
Other comprehensive income, net of income taxes— — — — 41 — 41 
Balance, June 30, 2020976,337 $19,336 $(123)$16,622 $(3,132)$2,168 $34,871 
See the Combined Notes to Consolidated Financial Statements
15



 Six Months Ended June 30, 2019
(In millions, shares
in thousands)
Issued
Shares
 
Common
Stock
 
Treasury
Stock
 
Retained
Earnings
 
Accumulated
Other
Comprehensive
Loss, net
 
Noncontrolling
Interests
 
Total Shareholders'
Equity
Balance, December 31, 2018970,020
 $19,116
 $(123) $14,766
 $(2,995) $2,306
 $33,070
Net income—
 —
 —
 907
 —
 59
 966
Long-term incentive plan activity2,446
 (3) —
 —
 —
 —
 (3)
Employee stock purchase plan issuances320
 51
 —
 —
 —
 —
 51
Changes in equity of noncontrolling interests—
 —
 —
 —
 —
 (17) (17)
Sale of noncontrolling interests—
 7
 —
 —
 —
 —
 7
Common stock dividends
($0.36/common share)
—
 —
 —
 (352) —
 —
 (352)
Other comprehensive loss, net of income taxes—
 —
 —
 —
 (17) (1) (18)
Balance, March 31, 2019972,786
 $19,171
 $(123) $15,321
 $(3,012) $2,347
 $33,704
Net income—
 —
 —
 484
 —
 10
 494
Long-term incentive plan activity320
 14
 —
 —
 —
 —
 14
Employee stock purchase plan issuances311
 24
 —
 —
 —
 —
 24
Changes in equity of noncontrolling interests—
 —
 —
 —
 —
 3
 3
Common stock dividends
($0.36/common share)		—
 —
 —
 (353) —
 —
 (353)
Other comprehensive income, net of income taxes—
 —
 —
 —
 22
 (1) 21
Balance, June 30, 2019973,417
 $19,209
 $(123) $15,452
 $(2,990) $2,359
 $33,907
Table of Contents


EXELON GENERATION COMPANY, LLC AND SUBSIDIARY COMPANIES
CONSOLIDATED STATEMENTS OF OPERATIONS AND COMPREHENSIVE INCOME
(Unaudited)
Three Months Ended
June 30,		Six Months Ended
June 30,
(In millions)2021202020212020
Operating revenues
Operating revenues$3,899 $3,609 $9,163 $8,012 
Operating revenues from affiliates254 271 549 601 
Total operating revenues4,153 3,880 9,712 8,613 
Operating expenses
Purchased power and fuel1,952 1,945 6,562 4,655 
Purchased power and fuel from affiliates(5)(3)(5)(9)
Operating and maintenance1,337 1,053 2,194 2,174 
Operating and maintenance from affiliates137 136 282 277 
Depreciation and amortization930 300 1,869 604 
Taxes other than income taxes118 116 239 246 
Total operating expenses4,469 3,547 11,141 7,947 
Gain on sales of assets and businesses8 12 79 12 
Operating (loss) income(308)345 (1,350)678 
Other income and (deductions)
Interest expense, net(72)(78)(140)(179)
Interest expense to affiliates(4)(9)(8)(18)
Other, net508 602 675 (168)
Total other income and (deductions)432 515 527 (365)
Income (loss) before income taxes124 860 (823)313 
Income taxes110 329 (70)(59)
Equity in losses of unconsolidated affiliates(1)(2)(3)(4)
Net income (loss)13 529 (756)368 
Net income (loss) attributable to noncontrolling interests74 53 98 (153)
Net (loss) income attributable to membership interest$(61)$476 $(854)$521 
Comprehensive income, net of income taxes
Net income (loss)$13 $529 $(756)$368 
Other comprehensive income (loss), net of income taxes
Unrealized loss on cash flow hedges0 0 0 (1)
Unrealized gain (loss) on foreign currency translation2 2 3 (6)
Other comprehensive income (loss), net of income taxes2 2 3 (7)
Comprehensive income (loss)15 531 (753)361 
Comprehensive income (loss) attributable to noncontrolling interests74 53 98 (153)
Comprehensive (loss) income attributable to membership interest$(59)$478 $(851)$514 
See the Combined Notes to Consolidated Financial Statements
16



 Three Months Ended
June 30,		 Six Months Ended
June 30,
(In millions)2020 2019 2020 2019
Operating revenues       
Operating revenues$3,609
 $3,958
 $8,012
 $8,937
Operating revenues from affiliates271
 252
 601
 569
Total operating revenues3,880

4,210

8,613

9,506
Operating expenses       
Purchased power and fuel1,945
 2,289
 4,655
 5,493
Purchased power and fuel from affiliates(3) 3
 (9) 4
Operating and maintenance1,053
 1,117
 2,174
 2,185
Operating and maintenance from affiliates136
 149
 277
 299
Depreciation and amortization300
 409
 604
 814
Taxes other than income taxes116
 129
 246
 264
Total operating expenses3,547

4,096

7,947

9,059
Gain on sales of assets and businesses12
 33
 12
 33
Operating income345

147

678

480
Other income and (deductions)       
Interest expense, net(78) (107) (179) (209)
Interest expense to affiliates(9) (9) (18) (18)
Other, net602
 171
 (168) 601
Total other income and (deductions)515

55

(365)
374
Income before income taxes860
 202
 313
 854
Income taxes329
 78
 (59) 301
Equity in losses of unconsolidated affiliates(2) (6) (4) (13)
Net income529

118

368

540
Net income (loss) attributable to noncontrolling interests53
 10
 (153) 68
Net income attributable to membership interest$476

$108

$521

$472
Comprehensive income, net of income taxes       
Net income$529
 $118
 $368
 $540
Other comprehensive income (loss), net of income taxes       
Unrealized loss on cash flow hedges—
 (1) (1) —
Unrealized loss on investments in unconsolidated affiliates—
 (2) —
 (4)
Unrealized gain (loss) on foreign currency translation2
 2
 (6) 4
Other comprehensive income (loss)2

(1)
(7)
—
Comprehensive income531

117

361

540
Comprehensive income (loss) attributable to noncontrolling interests53
 9
 (153) 66
Comprehensive income attributable to membership interest$478
 $108
 $514
 $474

Table of Contents
EXELON GENERATION COMPANY, LLC AND SUBSIDIARY COMPANIES
CONSOLIDATED STATEMENTS OF CASH FLOWS
(Unaudited)
Six Months Ended
June 30,
(In millions)20212020
Cash flows from operating activities
Net (loss) income$(756)$368 
Adjustments to reconcile net (loss) income to net cash flows provided by operating activities:
Depreciation, amortization, and accretion, including nuclear fuel and energy contract amortization2,686 1,320 
Asset impairments493 18 
Gain on sales of assets and businesses(79)(12)
Deferred income taxes and amortization of investment tax credits(142)(54)
Net fair value changes related to derivatives(490)(193)
Net realized and unrealized (gains) losses on NDT funds(376)196 
Net unrealized gains on equity investments(96)0 
Other non-cash operating activities(421)136 
Changes in assets and liabilities:
Accounts receivable(90)1,443 
Receivables from and payables to affiliates, net43 68 
Inventories4 (34)
Accounts payable and accrued expenses154 (666)
Option premiums received (paid), net2 (102)
Collateral received, net955 342 
Income taxes(1)26 
Pension and non-pension postretirement benefit contributions(212)(243)
Other assets and liabilities(2,031)(1,332)
Net cash flows (used in) provided by operating activities(357)1,281 
Cash flows from investing activities
Capital expenditures(719)(930)
Proceeds from NDT fund sales4,438 2,488 
Investment in NDT funds(4,538)(2,540)
Collection of DPP2,209 1,102 
Proceeds from sales of assets and businesses724 0 
Other investing activities(8)6 
Net cash flows provided by investing activities2,106 126 
Cash flows from financing activities
Changes in short-term borrowings(340)(220)
Proceeds from short-term borrowings with maturities greater than 90 days0 500 
Issuance of long-term debt151 2,403 
Retirement of long-term debt(56)(2,936)
Changes in Exelon intercompany money pool(285)0 
Distributions to member(916)(937)
Other financing activities(29)(30)
Net cash flows used in financing activities(1,475)(1,220)
Increase in cash, restricted cash, and cash equivalents274 187 
Cash, restricted cash, and cash equivalents at beginning of period327 449 
Cash, restricted cash, and cash equivalents at end of period$601 $636 
Supplemental cash flow information
Decrease in capital expenditures not paid$(66)$(108)
Increase in DPP1,958 1,754 
 Six Months Ended
June 30,
(In millions)2020 2019
Cash flows from operating activities   
Net income$368
 $540
Adjustments to reconcile net income to net cash flows provided by operating activities:   
Depreciation, amortization and accretion, including nuclear fuel and energy contract amortization1,320
 1,580
Asset impairments18
 9
Gain on sales of assets and businesses(12) (33)
Deferred income taxes and amortization of investment tax credits(54) 151
Net fair value changes related to derivatives(193) 114
Net realized and unrealized losses (gains) on NDT funds196
 (404)
Other non-cash operating activities136
 (50)
Changes in assets and liabilities:
 
Accounts receivable1,443
 472
Receivables from and payables to affiliates, net68
 (18)
Inventories(34) 32
Accounts payable and accrued expenses(666) (507)
Option premiums (paid) received, net(102) 48
Collateral posted, net342
 (318)
Income taxes26
 321
Pension and non-pension postretirement benefit contributions(243) (158)
Other assets and liabilities(1,332) (351)
Net cash flows provided by operating activities1,281

1,428
Cash flows from investing activities   
Capital expenditures(930) (890)
Proceeds from NDT fund sales2,488
 6,920
Investment in NDT funds(2,540) (6,847)
Collection of DPP1,102
 —
Proceeds from sales of assets and businesses—
 14
Changes in Exelon intercompany money pool—
 (179)
Other investing activities6
 8
Net cash flows provided by (used in) investing activities126

(974)
Cash flows from financing activities   
Changes in short-term borrowings(220) —
Proceeds from short-term borrowings with maturities greater than 90 days500
 —
Issuance of long-term debt2,403
 40
Retirement of long-term debt(2,936) (130)
Changes in Exelon intercompany money pool—
 (100)
Distributions to member(937) (449)
Other financing activities(30) (21)
Net cash flows used in financing activities(1,220)
(660)
Increase (decrease) in cash, cash equivalents and restricted cash187
 (206)
Cash, cash equivalents and restricted cash at beginning of period449
 903
Cash, cash equivalents and restricted cash at end of period$636

$697
    
Supplemental cash flow information   
Decrease in capital expenditures not paid$(108) $(30)
Increase in DPP1,754
 —
Increase in PPE related to ARO update—
 301
See the Combined Notes to Consolidated Financial Statements
17




Table of Contents
EXELON GENERATION COMPANY, LLC AND SUBSIDIARY COMPANIES
CONSOLIDATED BALANCE SHEETS
(Unaudited)
(In millions)June 30, 2021December 31, 2020
ASSETS
Current assets
Cash and cash equivalents$542 $226 
Restricted cash and cash equivalents59 89 
Accounts receivable
Customer accounts receivable1,4101,330
Customer allowance for credit losses(75)(32)
Customer accounts receivable, net1,335 1,298 
Other accounts receivable476352
Other allowance for credit losses(1)0
Other accounts receivable, net475 352 
Mark-to-market derivative assets749 644 
Receivables from affiliates117 153 
Unamortized energy contract assets37 38 
Inventories, net
Fossil fuel and emission allowances204 233 
Materials and supplies986 978 
Renewable energy credits341 621 
Assets held for sale11 958 
Other1,353 1,357 
Total current assets6,209 6,947 
Property, plant, and equipment (net of accumulated depreciation and amortization of $15,024 and $13,370 as of June 30, 2021 and December 31, 2020, respectively)19,837 22,214 
Deferred debits and other assets
Nuclear decommissioning trust funds15,400 14,464 
Investments157 184 
Goodwill47 47 
Mark-to-market derivative assets441 555 
Prepaid pension asset1,713 1,558 
Unamortized energy contract assets278 293 
Deferred income taxes14 6 
Other1,725 1,826 
Total deferred debits and other assets19,775 18,933 
Total assets(a)
$45,821 $48,094 
See the Combined Notes to Consolidated Financial Statements
18



(In millions)June 30, 2020 December 31, 2019
ASSETS   
Current assets   
Cash and cash equivalents$483
 $303
Restricted cash and cash equivalents153
 146
Accounts receivable   
Customer accounts receivable1,117 2,973
Customer allowance for credit losses(33) (80)
Customer accounts receivable, net1,084
 2,893
Other accounts receivable360 619
Other accounts receivable, net360
 619
Mark-to-market derivative assets570
 675
Receivables from affiliates118
 190
Unamortized energy contract assets44
 47
Inventories, net   
Fossil fuel and emission allowances220
 236
Materials and supplies1,075
 1,026
Renewable energy credits399
 336
Other1,343
 605
Total current assets5,849

7,076
Property, plant and equipment (net of accumulated depreciation and amortization of $12,051 and $12,017 as of June 30, 2020 and December 31, 2019, respectively)23,954
 24,193
Deferred debits and other assets   
Nuclear decommissioning trust funds12,730
 13,190
Investments192
 235
Goodwill47
 47
Mark-to-market derivative assets466
 508
Prepaid pension asset1,613
 1,438
Unamortized energy contract assets320
 336
Deferred income taxes11
 12
Other1,821
 1,960
Total deferred debits and other assets17,200

17,726
Total assets(a)
$47,003

$48,995
Table of Contents

EXELON GENERATION COMPANY, LLC AND SUBSIDIARY COMPANIES
CONSOLIDATED BALANCE SHEETS
(Unaudited)
(In millions)June 30, 2020 December 31, 2019(In millions)June 30, 2021December 31, 2020
LIABILITIES AND EQUITY   LIABILITIES AND EQUITY
Current liabilities   Current liabilities
Short-term borrowings$600
 $320
Short-term borrowings$500 $840 
Long-term debt due within one year785
 2,624
Long-term debt due within one year1,229 197 
Long-term debt to affiliates due within one year554
 558
Accounts payable1,075
 1,692
Accounts payable1,489 1,253 
Accrued expenses621
 786
Accrued expenses654 788 
Payables to affiliates113
 117
Payables to affiliates119 107 
Borrowings from Exelon intercompany money poolBorrowings from Exelon intercompany money pool0 285 
Mark-to-market derivative liabilities173
 215
Mark-to-market derivative liabilities695 262 
Unamortized energy contract liabilities9
 17
Unamortized energy contract liabilities4 7 
Renewable energy credit obligation478
 443
Renewable energy credit obligation508 661 
Liabilities held for saleLiabilities held for sale2 375 
Other430
 517
Other313 444 
Total current liabilities4,838
 7,289
Total current liabilities5,513 5,219 
Long-term debt5,768
 4,464
Long-term debt4,627 5,566 
Long-term debt to affiliates326
 328
Long-term debt to affiliates322 324 
Deferred credits and other liabilities   Deferred credits and other liabilities
Deferred income taxes and unamortized investment tax credits3,701
 3,752
Deferred income taxes and unamortized investment tax credits3,460 3,656 
Asset retirement obligations10,819
 10,603
Asset retirement obligations12,257 12,054 
Non-pension postretirement benefit obligations868
 878
Non-pension postretirement benefit obligations857 858 
Spent nuclear fuel obligation1,206
 1,199
Spent nuclear fuel obligation1,209 1,208 
Payables to affiliates2,751
 3,103
Payables to affiliates3,011 3,017 
Mark-to-market derivative liabilities154
 123
Mark-to-market derivative liabilities311 205 
Unamortized energy contract liabilities10
 11
Unamortized energy contract liabilities3 3 
Other1,335
 1,415
Other1,266 1,308 
Total deferred credits and other liabilities20,844
 21,084
Total deferred credits and other liabilities22,374 22,309 
Total liabilities(a)
31,776
 33,165
Total liabilities(a)
32,836 33,418 
Commitments and contingencies

 

Commitments and contingencies00
Equity   Equity
Member’s equity   Member’s equity
Membership interest9,569
 9,566
Membership interest9,624 9,624 
Undistributed earnings3,534
 3,950
Undistributed earnings1,035 2,805 
Accumulated other comprehensive loss, net(39) (32)Accumulated other comprehensive loss, net(27)(30)
Total member’s equity13,064
 13,484
Total member’s equity10,632 12,399 
Noncontrolling interests2,163
 2,346
Noncontrolling interests2,353 2,277 
Total equity15,227
 15,830
Total equity12,985 14,676 
Total liabilities and equity$47,003
 $48,995
Total liabilities and equity$45,821 $48,094 
__________
(a)Generation’s consolidated assets include $9,916 million and $9,512 million at June 30, 2020 and December 31, 2019, respectively, of certain VIEs that can only be used to settle the liabilities of the VIE. Generation’s consolidated liabilities include $3,505 million and $3,429 million at June 30, 2020 and December 31, 2019, respectively, of certain VIEs for which the VIE creditors do not have recourse to Generation. See Note 16 — Variable Interest Entities for additional information.

(a)Generation’s consolidated assets include $10,077 million and $10,182 million at June 30, 2021 and December 31, 2020, respectively, of certain VIEs that can only be used to settle the liabilities of the VIE. Generation’s consolidated liabilities include $3,563 million and $3,572 million at June 30, 2021 and December 31, 2020, respectively, of certain VIEs for which the VIE creditors do not have recourse to Generation. See Note 17 — Variable Interest Entities for additional information.
See the Combined Notes to Consolidated Financial Statements
19



Table of Contents
EXELON GENERATION COMPANY, LLC AND SUBSIDIARY COMPANIES
CONSOLIDATED STATEMENTS OF CHANGES IN EQUITY
(Unaudited)
Six Months Ended June 30, 2021
Member’s Equity
(In millions)Membership
Interest		Undistributed
Earnings		Accumulated
Other
Comprehensive
Loss, net		Noncontrolling
Interests		Total Equity
Balance, December 31, 2020$9,624 $2,805 $(30)$2,277 $14,676 
Net (loss) income— (793)— 24 (769)
Changes in equity of noncontrolling interests— — — (10)(10)
Distributions to member— (458)— — (458)
Other comprehensive income, net of income taxes— 0 1 0 1 
Balance, March 31, 2021$9,624 $1,554 $(29)$2,291 $13,440 
Net (loss) income— (61)— 74 13 
Changes in equity of noncontrolling interests— — — (12)(12)
Distributions to member— (458)— — (458)
Other comprehensive income, net of income taxes— 0 2 0 2 
Balance, June 30, 2021$9,624 $1,035 $(27)$2,353 $12,985 

Six Months Ended June 30, 2020
Member’s Equity
(In millions)Membership
Interest		Undistributed
Earnings		Accumulated
Other
Comprehensive
Loss, net		Noncontrolling
Interests		Total Equity
Balance, December 31, 2019$9,566 $3,950 $(32)$2,346 $15,830 
Net income (loss)— 45 — (206)(161)
Changes in equity of noncontrolling interests— — — (11)(11)
Sale of noncontrolling interests2 — — — 2 
Distributions to member— (468)— — (468)
Other comprehensive loss, net of income taxes— 0 (9)0 (9)
Balance, March 31, 2020$9,568 $3,527 $(41)$2,129 $15,183 
Net income— 476 — 53 529 
Changes in equity of noncontrolling interests— — — (19)(19)
Sale of noncontrolling interests1 — — — 1 
Distributions to member— (469)— — (469)
Other comprehensive income, net of income taxes— 0 2 0 2 
Balance, June 30, 2020$9,569 $3,534 $(39)$2,163 $15,227 

See the Combined Notes to Consolidated Financial Statements
20



 Six Months Ended June 30, 2020
 Member’s Equity    
(In millions)
Membership
Interest
 
Undistributed
Earnings
 
Accumulated
Other
Comprehensive
Loss, net
 
Noncontrolling
Interests
 Total Equity
Balance, December 31, 2019$9,566
 $3,950
 $(32) $2,346
 $15,830
Net income (loss)—
 45
 —
 (206) (161)
Changes in equity of noncontrolling interests—
 —
 —
 (11) (11)
Sale of noncontrolling interests2
 —
 —
 —
 2
Distributions to member—
 (468) —
 —
 (468)
Other comprehensive loss, net of income taxes—
 —
 (9) —
 (9)
Balance, March 31, 2020$9,568

$3,527

$(41)
$2,129

$15,183
Net income—
 476
 —
 53
 529
Changes in equity of noncontrolling interests—
 —
 —
 (19) (19)
Sale of noncontrolling interests1
 —
 —
 —
 1
Distributions to member—
 (469) —
 —
 (469)
Other comprehensive income, net of income taxes—
 —
 2
 —
 2
Balance, June 30, 2020$9,569
 $3,534
 $(39) $2,163
 $15,227

Table of Contents
 Six Months Ended June 30, 2019
 Member’s Equity    
(In millions)
Membership
Interest
 
Undistributed
Earnings
 
Accumulated
Other
Comprehensive
Loss, net
 
Noncontrolling
Interests
 Total Equity
Balance, December 31, 2018$9,518
 $3,724
 $(38) $2,304
 $15,508
Net income—
 363
 —
 59
 422
Changes in equity of noncontrolling interests—
 —
 —
 (17) (17)
Sale of noncontrolling interests7
 —
 —
 —
 7
Distributions to member—
 (225) —
 —
 (225)
Other comprehensive income, net of income taxes—
 —
 2
 (1) 1
Balance, March 31, 2019$9,525
 $3,862
 $(36) $2,345
 $15,696
Net income—
 108
 —
 10
 118
Changes in equity of noncontrolling interests—
 —
 —
 3
 3
Distributions to member—
 (224) —
 —
 (224)
Other comprehensive loss, net of income taxes—
 —
 —
 (1) (1)
Balance, June 30, 2019$9,525
 $3,746
 $(36) $2,357
 $15,592


COMMONWEALTH EDISON COMPANY AND SUBSIDIARY COMPANIES
CONSOLIDATED STATEMENTS OF OPERATIONS AND COMPREHENSIVE INCOME
(Unaudited)
Three Months Ended
June 30,		Six Months Ended
June 30,
(In millions)2021202020212020
Operating revenues
Electric operating revenues$1,503 $1,431 $2,977 $2,853 
Revenues from alternative revenue programs9 (25)64 (13)
Operating revenues from affiliates5 11 11 16 
Total operating revenues1,517 1,417 3,052 2,856 
Operating expenses
Purchased power421 380 862 770 
Purchased power from affiliate79 84 163 181 
Operating and maintenance250 469 495 713 
Operating and maintenance from affiliates73 67 144 140 
Depreciation and amortization296 274 589 547 
Taxes other than income taxes77 71 153 146 
Total operating expenses1,196 1,345 2,406 2,497 
Operating income321 72 646 359 
Other income and (deductions)
Interest expense, net(95)(95)(187)(186)
Interest expense to affiliates(3)(3)(6)(6)
Other, net15 11 22 22 
Total other income and (deductions)(83)(87)(171)(170)
Income (loss) before income taxes238 (15)475 189 
Income taxes46 46 85 82 
Net income (loss)$192 $(61)$390 $107 
Comprehensive income (loss)$192 $(61)$390 $107 

21



 Three Months Ended
June 30,		 Six Months Ended
June 30,
(In millions)2020 2019 2020 2019
Operating revenues       
Electric operating revenues$1,431
 $1,360
 $2,853
 $2,792
Revenues from alternative revenue programs(25) (14) (13) (42)
Operating revenues from affiliates11
 5
 16
 9
Total operating revenues1,417

1,351

2,856

2,759
Operating expenses       
Purchased power380
 316
 770
 705
Purchased power from affiliate84
 91
 181
 187
Operating and maintenance469
 245
 713
 504
Operating and maintenance from affiliate67
 60
 140
 122
Depreciation and amortization274
 257
 547
 508
Taxes other than income taxes71
 71
 146
 148
Total operating expenses1,345

1,040

2,497

2,174
Gain on sales of assets—
 —
 —
 3
Operating income72

311

359

588
Other income and (deductions)       
Interest expense, net(95) (86) (186) (171)
Interest expense to affiliates(3) (3) (6) (7)
Other, net11
 10
 22
 19
Total other income and (deductions)(87)
(79)
(170)
(159)
(Loss) income before income taxes(15) 232
 189
 429
Income taxes46
 46
 82
 85
Net (loss) income$(61)
$186

$107

$344
Comprehensive (loss) income$(61) $186
 $107
 $344

Table of Contents

COMMONWEALTH EDISON COMPANY AND SUBSIDIARY COMPANIES
CONSOLIDATED STATEMENTS OF CASH FLOWS
(Unaudited)
Six Months Ended
June 30,
(In millions)20212020
Cash flows from operating activities
Net income$390 $107 
Adjustments to reconcile net income to net cash flows provided by operating activities:
Depreciation and amortization589 547 
Asset impairments0 15 
Deferred income taxes and amortization of investment tax credits143 129 
Other non-cash operating activities23 283 
Changes in assets and liabilities:
Accounts receivable(48)(92)
Receivables from and payables to affiliates, net5 (6)
Inventories(2)(7)
Accounts payable and accrued expenses(45)4 
Collateral received (posted), net2 (3)
Income taxes(34)(90)
Pension and non-pension postretirement benefit contributions(173)(144)
Other assets and liabilities(292)(245)
Net cash flows provided by operating activities558 498 
Cash flows from investing activities
Capital expenditures(1,162)(1,029)
Other investing activities12 (4)
Net cash flows used in investing activities(1,150)(1,033)
Cash flows from financing activities
Changes in short-term borrowings(290)(130)
Issuance of long-term debt700 1,000 
Dividends paid on common stock(253)(249)
Contributions from parent395 249 
Other financing activities(11)(14)
Net cash flows provided by financing activities541 856 
(Decrease) increase in cash, restricted cash, and cash equivalents(51)321 
Cash, restricted cash, and cash equivalents at beginning of period405 403 
Cash, restricted cash, and cash equivalents at end of period$354 $724 
Supplemental cash flow information
(Decrease) increase in capital expenditures not paid$(93)$18 
See the Combined Notes to Consolidated Financial Statements
22



 Six Months Ended
June 30,
(In millions)2020 2019
Cash flows from operating activities   
Net income$107
 $344
Adjustments to reconcile net income to net cash flows provided by operating activities:   
Depreciation, amortization and accretion547
 508
Asset impairments15
 —
Deferred income taxes and amortization of investment tax credits129
 64
Other non-cash operating activities283
 87
Changes in assets and liabilities:   
Accounts receivable(92) 56
Receivables from and payables to affiliates, net(6) (16)
Inventories(7) (5)
Accounts payable and accrued expenses4
 (121)
Collateral received (posted), net(3) 11
Income taxes(90) 43
Pension and non-pension postretirement benefit contributions(144) (68)
Other assets and liabilities(245) (236)
Net cash flows provided by operating activities498

667
Cash flows from investing activities   
Capital expenditures(1,029) (961)
Other investing activities(4) 17
Net cash flows used in investing activities(1,033)
(944)
Cash flows from financing activities   
Changes in short-term borrowings(130) 303
Issuance of long-term debt1,000
 400
Retirement of long-term debt—
 (300)
Dividends paid on common stock(249) (254)
Contributions from parent249
 124
Other financing activities(14) (10)
Net cash flows provided by financing activities856

263
Increase (decrease) in cash, cash equivalents and restricted cash321
 (14)
Cash, cash equivalents and restricted cash at beginning of period403
 330
Cash, cash equivalents and restricted cash at end of period$724

$316
    
Supplemental cash flow information   
Increase (decrease) in capital expenditures not paid$18
 $(77)

COMMONWEALTH EDISON COMPANY AND SUBSIDIARY COMPANIES
CONSOLIDATED BALANCE SHEETS
(Unaudited)
(In millions)June 30, 2021December 31, 2020
ASSETS
Current assets
   Cash and cash equivalents$71 $83 
   Restricted cash and cash equivalents240 279 
   Accounts receivable
   Customer accounts receivable687656
   Customer allowance for credit losses(89)(97)
       Customer accounts receivable, net598 559 
   Other accounts receivable257239
   Other allowance for credit losses(18)(21)
       Other accounts receivable, net239 218 
   Receivables from affiliates22 22 
   Inventories, net170 170 
   Regulatory assets298 279 
   Other77 49 
   Total current assets1,715 1,659 
Property, plant, and equipment (net of accumulated depreciation and amortization of $5,885 and $5,672 as of June 30, 2021 and December 31, 2020, respectively)25,170 24,557 
Deferred debits and other assets
   Regulatory assets1,846 1,749 
   Investments6 6 
   Goodwill2,625 2,625 
   Receivables from affiliates2,439 2,541 
   Prepaid pension asset1,138 1,022 
   Other385 307 
   Total deferred debits and other assets8,439 8,250 
Total assets$35,324 $34,466 
See the Combined Notes to Consolidated Financial Statements
23



(In millions)June 30, 2020 December 31, 2019
ASSETS   
Current assets   
   Cash and cash equivalents$403
 $90
   Restricted cash and cash equivalents155
 150
   Accounts receivable   
   Customer accounts receivable706 604
   Customer allowance for credit losses(72) (59)
       Customer accounts receivable, net634
 545
   Other accounts receivable361 306
   Other allowance for credit losses(22) (20)
       Other accounts receivable, net339
 286
   Receivables from affiliates23
 28
   Inventories, net166
 159
   Regulatory assets271
 281
   Other59
 44
   Total current assets2,050

1,583
Property, plant and equipment (net of accumulated depreciation and amortization of $5,424 and $5,168 as of June 30, 2020 and December 31, 2019, respectively)23,717
 23,107
Deferred debits and other assets   
   Regulatory assets1,610
 1,480
   Investments6
 6
   Goodwill2,625
 2,625
   Receivables from affiliates2,374
 2,622
   Prepaid pension asset1,079
 995
   Other435
 347
   Total deferred debits and other assets8,129

8,075
Total assets$33,896

$32,765

COMMONWEALTH EDISON COMPANY AND SUBSIDIARY COMPANIES
CONSOLIDATED BALANCE SHEETS
(Unaudited)
(In millions)June 30, 2021December 31, 2020
LIABILITIES AND SHAREHOLDERS’ EQUITY
Current liabilities
   Short-term borrowings$33 $323 
   Long-term debt due within one year350 350 
   Accounts payable575 683 
   Accrued expenses346 390 
   Payables to affiliates102 96 
   Customer deposits90 86 
   Regulatory liabilities419 289 
   Mark-to-market derivative liabilities23 33 
   Other147 143 
   Total current liabilities2,085 2,393 
Long-term debt9,325 8,633 
Long-term debt to financing trust205 205 
Deferred credits and other liabilities
   Deferred income taxes and unamortized investment tax credits4,531 4,341 
   Asset retirement obligations128 126 
   Non-pension postretirement benefits obligations180 173 
   Regulatory liabilities6,181 6,403 
   Mark-to-market derivative liabilities242 268 
   Other587 595 
   Total deferred credits and other liabilities11,849 11,906 
   Total liabilities23,464 23,137 
Commitments and contingencies00
Shareholders’ equity
   Common stock1,588 1,588 
   Other paid-in capital8,680 8,285 
   Retained deficit unappropriated(1,639)(1,639)
   Retained earnings appropriated3,231 3,095 
   Total shareholders’ equity11,860 11,329 
Total liabilities and shareholders’ equity$35,324 $34,466 
See the Combined Notes to Consolidated Financial Statements
24



(In millions)June 30, 2020 December 31, 2019
LIABILITIES AND SHAREHOLDERS’ EQUITY   
Current liabilities   
   Short-term borrowings$—
 $130
   Long-term debt due within one year500
 500
   Accounts payable579
 527
   Accrued expenses330
 385
   Payables to affiliates92
 103
   Customer deposits116
 118
   Regulatory liabilities175
 200
   Mark-to-market derivative liabilities31
 32
   Deferred Prosecution Agreement payments200
 —
   Other122
 122
   Total current liabilities2,145
 2,117
Long-term debt8,980
 7,991
Long-term debt to financing trust205
 205
Deferred credits and other liabilities   
   Deferred income taxes and unamortized investment tax credits4,201
 4,021
   Asset retirement obligations127
 128
   Non-pension postretirement benefits obligations177
 180
   Regulatory liabilities6,309
 6,542
   Mark-to-market derivative liabilities287
 269
   Other681
 635
   Total deferred credits and other liabilities11,782
 11,775
   Total liabilities23,112
 22,088
Commitments and contingencies

 

Shareholders’ equity   
   Common stock1,588
 1,588
   Other paid-in capital7,821
 7,572
   Retained deficit unappropriated(1,700) (1,639)
   Retained earnings appropriated3,075
 3,156
   Total shareholders’ equity10,784
 10,677
Total liabilities and shareholders’ equity$33,896
 $32,765

COMMONWEALTH EDISON COMPANY AND SUBSIDIARY COMPANIES
CONSOLIDATED STATEMENTS OF CHANGES IN SHAREHOLDERS’ EQUITY
(Unaudited)
Six Months Ended June 30, 2021
(In millions)Common
Stock		Other
Paid-In
Capital		Retained Deficit
Unappropriated		Retained
Earnings
Appropriated		Total
Shareholders’
Equity
Balance, December 31, 2020$1,588 $8,285 $(1,639)$3,095 $11,329 
Net income— — 197 — 197 
Appropriation of retained earnings for future dividends— — (197)197 0 
Common stock dividends— — — (127)(127)
Contributions from parent— 198 — — 198 
Balance, March 31, 2021$1,588 $8,483 $(1,639)$3,165 $11,597 
Net income— — 192 — 192 
Appropriation of retained earnings for future dividends— — (192)192 0 
Common stock dividends— — — (126)(126)
Contributions from parent— 197 — — 197 
Balance, June 30, 2021$1,588 $8,680 $(1,639)$3,231 $11,860 
Six Months Ended June 30, 2020
(In millions)Common
Stock		Other
Paid-In
Capital		Retained Deficit
Unappropriated		Retained
Earnings
Appropriated		Total
Shareholders’
Equity
Balance, December 31, 2019$1,588 $7,572 $(1,639)$3,156 $10,677 
Net income— — 168 — 168 
Appropriation of retained earnings for future dividends— — (168)168 0 
Common stock dividends— — — (125)(125)
Contributions from parent— 125 — — 125 
Balance, March 31, 2020$1,588 $7,697 $(1,639)$3,199 $10,845 
Net loss— — (61)— (61)
Common stock dividends— — — (124)(124)
Contributions from parent— 124 — — 124 
Balance, June 30, 2020$1,588 $7,821 $(1,700)$3,075 $10,784 
See the Combined Notes to Consolidated Financial Statements
25



 Six Months Ended June 30, 2020
(In millions)
Common
Stock
 
Other
Paid-In
Capital
 
Retained Deficit
Unappropriated
 
Retained
Earnings
Appropriated
 
Total
Shareholders’
Equity
Balance, December 31, 2019$1,588
 $7,572
 $(1,639) $3,156
 $10,677
Net income—
 —
 168
 —
 168
Appropriation of retained earnings for future dividends—
 —
 (168) 168
 —
Common stock dividends—
 —
 —
 (125) (125)
Contributions from parent—
 125
 —
 —
 125
Balance, March 31, 2020$1,588
 $7,697
 $(1,639) $3,199
 $10,845
Net loss—
 —
 (61) —
 (61)
Common stock dividends—
 —
 —
 (124) (124)
Contributions from parent—
 124
 —
 —
 124
Balance, June 30, 2020$1,588
 $7,821
 $(1,700) $3,075
 $10,784
          
 Six Months Ended June 30, 2019
(In millions)
Common
Stock
 
Other
Paid-In
Capital
 
Retained Deficit
Unappropriated
 
Retained
Earnings
Appropriated
 
Total
Shareholders’
Equity
Balance, December 31, 2018$1,588
 $7,322
 $(1,639) $2,976
 $10,247
Net income—
 —
 157
 —
 157
Appropriation of retained earnings for future dividends—
 —
 (157) 157
 —
Common stock dividends—
 —
 —
 (127) (127)
Contributions from parent—
 63
 —
 —
 63
Balance, March 31, 2019$1,588
 $7,385
 $(1,639) $3,006
 $10,340
Net income—
 —
 186
 —
 186
Appropriation of retained earnings for future dividends—
 —
 (186) 186
 —
Common stock dividends—
 —
 —
 (127) (127)
Contributions from parent—
 61
 —
 —
 61
Balance, June 30, 2019$1,588
 $7,446
 $(1,639) $3,065
 $10,460


PECO ENERGY COMPANY AND SUBSIDIARY COMPANIES
CONSOLIDATED STATEMENTS OF OPERATIONS AND COMPREHENSIVE INCOME
(Unaudited)
 Three Months Ended
June 30,		Six Months Ended
June 30,
(In millions)2021202020212020
Operating revenues
Electric operating revenues$602 $580 $1,251 $1,180 
Natural gas operating revenues82 95 310 304 
Revenues from alternative revenue programs7 4 17 5 
Operating revenues from affiliates2 2 4 4 
Total operating revenues693 681 1,582 1,493 
Operating expenses
Purchased power145 142 334 306 
Purchased fuel22 34 108 117 
Purchased power from affiliate40 40 81 76 
Operating and maintenance166 235 360 414 
Operating and maintenance from affiliates43 40 83 78 
Depreciation and amortization87 88 173 173 
Taxes other than income taxes49 39 92 78 
Total operating expenses552 618 1,231 1,242 
Operating income141 63 351 251 
Other income and (deductions)
Interest expense, net(39)(33)(74)(65)
Interest expense to affiliates(3)(3)(6)(6)
Other, net7 5 12 7 
Total other income and (deductions)(35)(31)(68)(64)
Income before income taxes106 32 283 187 
Income taxes2 (7)12 9 
Net income$104 $39 $271 $178 
Comprehensive income$104 $39 $271 $178 
See the Combined Notes to Consolidated Financial Statements
26



 Three Months Ended
June 30,		 Six Months Ended
June 30,
(In millions)2020 2019 2020 2019
Operating revenues       
Electric operating revenues$580
 $567
 $1,180
 $1,188
Natural gas operating revenues95
 89
 304
 369
Revenues from alternative revenue programs4
 (3) 5
 (6)
Operating revenues from affiliates2
 2
 4
 3
Total operating revenues681

655

1,493

1,554
Operating expenses       
Purchased power142
 124
 306
 275
Purchased fuel34
 32
 117
 166
Purchased power from affiliate40
 35
 76
 79
Operating and maintenance235
 162
 414
 349
Operating and maintenance from affiliates40
 37
 78
 75
Depreciation and amortization88
 83
 173
 164
Taxes other than income taxes39
 37
 78
 79
Total operating expenses618

510

1,242

1,187
Operating income63

145

251

367
Other income and (deductions)       
Interest expense, net(33) (30) (65) (61)
Interest expense to affiliates(3) (3) (6) (6)
Other, net5
 3
 7
 7
Total other income and (deductions)(31)
(30)
(64)
(60)
Income before income taxes32
 115
 187

307
Income taxes(7) 13
 9
 37
Net income$39

$102

$178

$270
Comprehensive income$39
 $102
 $178
 $270

PECO ENERGY COMPANY AND SUBSIDIARY COMPANIES
CONSOLIDATED STATEMENTS OF CASH FLOWS
(Unaudited)
Six Months Ended
June 30,
(In millions)20212020
Cash flows from operating activities
Net income$271 $178 
Adjustments to reconcile net income to net cash flows provided by operating activities:
Depreciation and amortization173 173 
Deferred income taxes and amortization of investment tax credits21 6 
Other non-cash operating activities(5)25 
Changes in assets and liabilities:
Accounts receivable86 22 
Receivables from and payables to affiliates, net2 3 
Inventories3 10 
Accounts payable and accrued expenses(46)27 
Income taxes24 15 
Pension and non-pension postretirement benefit contributions(15)(18)
Other assets and liabilities(140)(48)
Net cash flows provided by operating activities374 393 
Cash flows from investing activities
Capital expenditures(577)(512)
Changes in Exelon intercompany money pool0 68 
Other investing activities4 3 
Net cash flows used in investing activities(573)(441)
Cash flows from financing activities
Issuance of long-term debt375 350 
Changes in Exelon intercompany money pool(40)0 
Dividends paid on common stock(169)(170)
Contributions from parent395 231 
Other financing activities(4)(3)
Net cash flows provided by financing activities557 408 
Increase in cash, restricted cash, and cash equivalents358 360 
Cash, restricted cash, and cash equivalents at beginning of period26 27 
Cash, restricted cash, and cash equivalents at end of period$384 $387 
Supplemental cash flow information
(Decrease) increase in capital expenditures not paid$(16)$42 
See the Combined Notes to Consolidated Financial Statements
27



 Six Months Ended
June 30,
(In millions)2020 2019
Cash flows from operating activities   
Net income$178
 $270
Adjustments to reconcile net income to net cash flows provided by operating activities:   
Depreciation and amortization173
 164
Deferred income taxes and amortization of investment tax credits6
 8
Other non-cash operating activities25
 15
Changes in assets and liabilities:   
Accounts receivable22
 39
Receivables from and payables to affiliates, net3
 (4)
Inventories10
 12
Accounts payable and accrued expenses27
 (31)
Income taxes15
 (11)
Pension and non-pension postretirement benefit contributions(18) (27)
Other assets and liabilities(48) (117)
Net cash flows provided by operating activities393

318
Cash flows from investing activities   
Capital expenditures(512) (447)
Changes in Exelon intercompany money pool68
 —
Other investing activities3
 4
Net cash flows used in investing activities(441)
(443)
Cash flows from financing activities   
Issuance of long-term debt350
 —
Changes in Exelon intercompany money pool—
 52
Dividends paid on common stock(170) (180)
Contributions from parent231
 145
Other financing activities(3) (1)
Net cash flows provided by financing activities408

16
Increase (decrease) in cash, cash equivalents and restricted cash360
 (109)
Cash, cash equivalents and restricted cash at beginning of period27
 135
Cash, cash equivalents and restricted cash at end of period$387

$26
    
Supplemental cash flow information   
Increase in capital expenditures not paid$42
 $33

PECO ENERGY COMPANY AND SUBSIDIARY COMPANIES
CONSOLIDATED BALANCE SHEETS
(Unaudited)
(In millions)June 30, 2021December 31, 2020
ASSETS
Current assets
Cash and cash equivalents$376 $19 
Restricted cash and cash equivalents8 7 
Accounts receivable
Customer accounts receivable419511
Customer allowance for credit losses(111)(116)
Customer accounts receivable, net308 395 
Other accounts receivable106130
Other allowance for credit losses(7)(8)
Other accounts receivable, net99 122 
Receivables from affiliates0 2 
Inventories, net
Fossil fuel25 33 
Materials and supplies42 38 
Prepaid utility taxes76 0 
Regulatory assets30 25 
Other37 21 
Total current assets1,001 662 
Property, plant, and equipment (net of accumulated depreciation and amortization of $3,906 and $3,843 as of June 30, 2021 and December 31, 2020, respectively)10,581 10,181 
Deferred debits and other assets
Regulatory assets866 776 
Investments32 30 
Receivables from affiliates571 475 
Prepaid pension asset387 375 
Other53 32 
Total deferred debits and other assets1,909 1,688 
Total assets$13,491 $12,531 
See the Combined Notes to Consolidated Financial Statements
28



(In millions)June 30, 2020 December 31, 2019
ASSETS   
Current assets   
Cash and cash equivalents$380
 $21
Restricted cash and cash equivalents7
 6
Accounts receivable   
Customer accounts receivable379 412
Customer allowance for credit losses(71) (55)
Customer accounts receivable, net308
 357
Other accounts receivable128 145
Other allowance for credit losses(7) (7)
Other accounts receivable, net121
 138
Receivables from affiliates—
 1
Receivable from Exelon intercompany money pool—
 68
Inventories, net   
Fossil fuel26
 36
Materials and supplies35
 35
Prepaid utility taxes76
 —
Regulatory assets46
 41
Other21
 19
Total current assets1,020

722
Property, plant and equipment (net of accumulated depreciation and amortization of $3,782 and $3,718 as of June 30, 2020 and December 31, 2019, respectively)9,688
 9,292
Deferred debits and other assets   
Regulatory assets604
 554
Investments27
 27
Receivables from affiliates376
 480
Prepaid pension asset379
 365
Other26
 29
Total deferred debits and other assets1,412

1,455
Total assets$12,120

$11,469

PECO ENERGY COMPANY AND SUBSIDIARY COMPANIES
CONSOLIDATED BALANCE SHEETS
(Unaudited)
(In millions)June 30, 2021December 31, 2020
LIABILITIES AND SHAREHOLDER'S EQUITY
Current liabilities
Long-term debt due within one year$300 $300 
Accounts payable436 479 
Accrued expenses125 129 
Payables to affiliates50 50 
Borrowings from Exelon intercompany money pool0 40 
Customer deposits50 59 
Regulatory liabilities109 121 
Other29 30 
Total current liabilities1,099 1,208 
Long-term debt3,825 3,453 
Long-term debt to financing trusts184 184 
Deferred credits and other liabilities
Deferred income taxes and unamortized investment tax credits2,345 2,242 
Asset retirement obligations29 29 
Non-pension postretirement benefits obligations287 286 
Regulatory liabilities600 503 
Other92 93 
Total deferred credits and other liabilities3,353 3,153 
Total liabilities8,461 7,998 
Commitments and contingencies00
Shareholder’s equity
Common stock3,409 3,014 
Retained earnings1,621 1,519 
Total shareholder’s equity5,030 4,533 
Total liabilities and shareholder's equity$13,491 $12,531 
See the Combined Notes to Consolidated Financial Statements
29



(In millions)June 30, 2020 December 31, 2019
LIABILITIES AND SHAREHOLDER'S EQUITY   
Current liabilities   
Accounts payable$463
 $387
Accrued expenses92
 101
Payables to affiliates57
 55
Customer deposits67
 69
Regulatory liabilities116
 91
Other29
 19
Total current liabilities824
 722
Long-term debt3,752
 3,405
Long-term debt to financing trusts184
 184
Deferred credits and other liabilities   
Deferred income taxes and unamortized investment tax credits2,139
 2,080
Asset retirement obligations26
 28
Non-pension postretirement benefits obligations287
 288
Regulatory liabilities404
 510
Other86
 74
Total deferred credits and other liabilities2,942
 2,980
Total liabilities7,702
 7,291
Commitments and contingencies

 

Shareholder’s equity   
Common stock2,997
 2,766
Retained earnings1,421
 1,412
Total shareholder’s equity4,418
 4,178
Total liabilities and shareholder's equity$12,120
 $11,469

PECO ENERGY COMPANY AND SUBSIDIARY COMPANIES
CONSOLIDATED STATEMENTS OF CHANGES IN SHAREHOLDER’S EQUITY
(Unaudited)
Six Months Ended June 30, 2021
(In millions)Common
Stock		Retained
Earnings		Total
Shareholder's
Equity
Balance, December 31, 2020$3,014 $1,519 $4,533 
Net income— 167 167 
Common stock dividends— (85)(85)
Balance, March 31, 2021$3,014 $1,601 $4,615 
Net income— 104 104 
Common stock dividends— (84)(84)
Contributions from parent395 — 395 
Balance, June 30, 2021$3,409 $1,621 $5,030 
Six Months Ended June 30, 2020
(In millions)Common
Stock		Retained
Earnings		Total
Shareholder's
Equity
Balance, December 31, 2019$2,766 $1,412 $4,178 
Net income— 140 140 
Common stock dividends— (85)(85)
Contributions from parent231 — 231 
Balance, March 31, 2020$2,997 $1,467 $4,464 
Net income— 39 39 
Common stock dividends— (85)(85)
Balance, June 30, 2020$2,997 $1,421 $4,418 
 Six months ended June 30, 2020
(In millions)
Common
Stock
 
Retained
Earnings
 
Total
Shareholder's
Equity
Balance, December 31, 2019$2,766
 $1,412
 $4,178
Net income—
 140
 140
Common stock dividends—
 (85) (85)
Contributions from parent231
 —
 231
Balance, March 31, 2020$2,997
 $1,467
 $4,464
Net income—
 39
 39
Common stock dividends—
 (85) (85)
Balance, June 30, 2020$2,997
 $1,421
 $4,418
      
 Six months ended June 30, 2019
(In millions)Common
Stock		 Retained
Earnings		 Total
Shareholder's
Equity
Balance, December 31, 2018$2,578
 $1,242
 $3,820
Net income—
 168
 168
Common stock dividends—
 (90) (90)
Contributions from parent145
 —
 145
Balance, March 31, 2019$2,723
 $1,320
 $4,043
Net income—
 102
 102
Common stock dividends—
 (90) (90)
Balance, June 30, 2019$2,723
 $1,332
 $4,055
See the Combined Notes to Consolidated Financial Statements
30





BALTIMORE GAS AND ELECTRIC COMPANY
STATEMENTS OF OPERATIONS AND COMPREHENSIVE INCOME
(Unaudited)
Three Months Ended
June 30,		Six Months Ended
June 30,
(In millions)2021202020212020
Operating revenues
Electric operating revenues$560 $530 $1,180 $1,125 
Natural gas operating revenues125 119 455 419 
Revenues from alternative revenue programs(10)(37)8 0 
Operating revenues from affiliates7 4 13 10 
Total operating revenues682 616 1,656 1,554 
Operating expenses
Purchased power133 107 295 221 
Purchased fuel27 18 126 95 
Purchased power and fuel from affiliate59 69 129 167 
Operating and maintenance147 146 299 293 
Operating and maintenance from affiliates46 41 91 83 
Depreciation and amortization141 129 293 272 
Taxes other than income taxes67 63 139 132 
Total operating expenses620 573 1,372 1,263 
Operating income62 43 284 291 
Other income and (deductions)
Interest expense, net(34)(32)(67)(64)
Other, net9 6 16 10 
Total other income and (deductions)(25)(26)(51)(54)
Income before income taxes37 17 233 237 
Income taxes(8)(22)(21)18 
Net income$45 $39 $254 $219 
Comprehensive income$45 $39 $254 $219 
See the Combined Notes to Consolidated Financial Statements
31



 Three Months Ended
June 30,		 Six Months Ended
June 30,
(In millions)2020 2019 2020 2019
Operating revenues       
Electric operating revenues$530
 $540
 $1,125
 $1,191
Natural gas operating revenues119
 97
 419
 405
Revenues from alternative revenue programs(37) 6
 —
 17
Operating revenues from affiliates4
 6
 10
 12
Total operating revenues616

649

1,554

1,625
Operating expenses       
Purchased power107
 131
 221
 322
Purchased fuel18
 21
 95
 116
Purchased power and fuel from affiliate69
 56
 167
 132
Operating and maintenance146
 142
 293
 294
Operating and maintenance from affiliates41
 40
 83
 78
Depreciation and amortization129
 117
 272
 252
Taxes other than income taxes63
 62
 132
 131
Total operating expenses573

569

1,263

1,325
Operating income43

80

291

300
Other income and (deductions)       
Interest expense, net(32) (29) (64) (58)
Other, net6
 5
 10
 11
Total other income and (deductions)(26)
(24)
(54)
(47)
Income before income taxes17
 56
 237

253
Income taxes(22) 11
 18
 47
Net income$39

$45

$219

$206
Comprehensive income$39
 $45
 $219
 $206

BALTIMORE GAS AND ELECTRIC COMPANY
STATEMENTS OF CASH FLOWS
(Unaudited)
Six Months Ended
June 30,
(In millions)20212020
Cash flows from operating activities
Net income$254 $219 
Adjustments to reconcile net income to net cash flows provided by operating activities:
Depreciation and amortization293 272 
Deferred income taxes and amortization of investment tax credits11 22 
Other non-cash operating activities28 50 
Changes in assets and liabilities:
Accounts receivable73 19 
Receivables from and payables to affiliates, net(19)(26)
Inventories(9)10 
Accounts payable and accrued expenses(51)(15)
Collateral posted, net2 0 
Income taxes(27)26 
Pension and non-pension postretirement benefit contributions(71)(68)
Other assets and liabilities(96)(5)
Net cash flows provided by operating activities388 504 
Cash flows from investing activities
Capital expenditures(620)(548)
Other investing activities10 (4)
Net cash flows used in investing activities(610)(552)
Cash flows from financing activities
Changes in short-term borrowings0 (76)
Issuance of long-term debt600 400 
Dividends paid on common stock(146)(123)
Contributions from parent0 26 
Other financing activities(6)(8)
Net cash flows provided by financing activities448 219 
Increase in cash, restricted cash, and cash equivalents226 171 
Cash, restricted cash, and cash equivalents at beginning of period145 25 
Cash, restricted cash, and cash equivalents at end of period$371 $196 
Supplemental cash flow information
Decrease in capital expenditures not paid$(71)$(14)
See the Combined Notes to Consolidated Financial Statements
32



 Six Months Ended
June 30,
(In millions)2020 2019
Cash flows from operating activities   
Net income$219
 $206
Adjustments to reconcile net income to net cash flows provided by operating activities:   
Depreciation and amortization272
 252
Deferred income taxes and amortization of investment tax credits22
 47
Other non-cash operating activities50
 41
Changes in assets and liabilities:   
Accounts receivable19
 85
Receivables from and payables to affiliates, net(26) (14)
Inventories10
 5
Accounts payable and accrued expenses(15) (73)
Collateral posted, net—
 (5)
Income taxes26
 (29)
Pension and non-pension postretirement benefit contributions(68) (42)
Other assets and liabilities(5) (21)
Net cash flows provided by operating activities504

452
Cash flows from investing activities   
Capital expenditures(548) (542)
Other investing activities(4) 4
Net cash flows used in investing activities(552)
(538)
Cash flows from financing activities   
Changes in short-term borrowings(76) 194
Issuance of long-term debt400
 —
Dividends paid on common stock(123) (112)
Contributions from parent26
 —
Other financing activities(8) —
Net cash flows provided by financing activities219

82
Increase (decrease) in cash, cash equivalents and restricted cash171
 (4)
Cash, cash equivalents and restricted cash at beginning of period25
 13
Cash, cash equivalents and restricted cash at end of period$196

$9
    
Supplemental cash flow information   
(Decrease) increase in capital expenditures not paid$(14) $24

BALTIMORE GAS AND ELECTRIC COMPANY
BALANCE SHEETS
(Unaudited)
(In millions)June 30, 2021December 31, 2020
ASSETS
Current assets
Cash and cash equivalents$368 $144 
Restricted cash and cash equivalents3 1 
Accounts receivable
Customer accounts receivable398487
Customer allowance for credit losses(27)(35)
    Customer accounts receivable, net371 452 
Other accounts receivable146117
Other allowance for credit losses(8)(9)
     Other accounts receivable, net138 108 
Receivables from affiliates0 3 
Inventories, net
Fossil fuel27 25 
Materials and supplies48 41 
Regulatory assets177 168 
Other9 6 
Total current assets1,141 948 
Property, plant, and equipment (net of accumulated depreciation and amortization of $4,151 and $4,034 as of June 30, 2021 and December 31, 2020, respectively)10,200 9,872 
Deferred debits and other assets
Regulatory assets473 481 
Investments13 10 
Prepaid pension asset302 270 
Other57 69 
Total deferred debits and other assets845 830 
Total assets$12,186 $11,650 
See the Combined Notes to Consolidated Financial Statements
33



(In millions)June 30, 2020 December 31, 2019
ASSETS   
Current assets   
Cash and cash equivalents$195
 $24
Restricted cash and cash equivalents1
 1
Accounts receivable   
Customer accounts receivable318 329
Customer allowance for credit losses(23) (12)
    Customer accounts receivable, net295
 317
Other accounts receivable121 152
Other allowance for credit losses(6) (5)
     Other accounts receivable, net115
 147
Receivables from affiliates—
 1
Inventories, net   
Fossil fuel22
 30
Materials and supplies44
 46
Prepaid utility taxes—
 78
Regulatory assets177
 183
Other6
 6
Total current assets855

833
Property, plant and equipment (net of accumulated depreciation and amortization of $3,906 and $3,834 as of June 30, 2020 and December 31, 2019, respectively)9,332
 8,990
Deferred debits and other assets   
Regulatory assets464
 454
Investments10
 7
Prepaid pension asset295
 264
Other71
 86
Total deferred debits and other assets840

811
Total assets$11,027

$10,634

BALTIMORE GAS AND ELECTRIC COMPANY
BALANCE SHEETS
(Unaudited)
(In millions)June 30, 2021December 31, 2020
LIABILITIES AND SHAREHOLDER'S EQUITY
Current liabilities
Long-term debt due within one year$300 $300 
Accounts payable287 346 
Accrued expenses138 205 
Payables to affiliates41 61 
Customer deposits101 110 
Regulatory liabilities32 30 
Other87 91 
Total current liabilities986 1,143 
Long-term debt3,959 3,364 
Deferred credits and other liabilities
Deferred income taxes and unamortized investment tax credits1,643 1,521 
Asset retirement obligations24 23 
Non-pension postretirement benefits obligations179 189 
Regulatory liabilities998 1,109 
Other92 104 
Total deferred credits and other liabilities2,936 2,946 
Total liabilities7,881 7,453 
Commitments and contingencies00
Shareholder's equity
Common stock2,318 2,318 
Retained earnings1,987 1,879 
Total shareholder's equity4,305 4,197 
Total liabilities and shareholder's equity$12,186 $11,650 
(In millions)June 30, 2020 December 31, 2019
LIABILITIES AND SHAREHOLDER'S EQUITY   
Current liabilities   
Short-term borrowings$—
 $76
Accounts payable244
 243
Accrued expenses120
 152
Payables to affiliates41
 66
Customer deposits118
 120
Regulatory liabilities44
 33
Other63
 63
Total current liabilities630
 753
Long-term debt3,663
 3,270
Deferred credits and other liabilities   
Deferred income taxes and unamortized investment tax credits1,480
 1,396
Asset retirement obligations22
 22
Non-pension postretirement benefits obligations193
 199
Regulatory liabilities1,131
 1,195
Other103
 116
Total deferred credits and other liabilities2,929
 2,928
Total liabilities7,222
 6,951
Commitments and contingencies

 

Shareholder's equity   
Common stock1,933
 1,907
Retained earnings1,872
 1,776
Total shareholder's equity3,805
 3,683
Total liabilities and shareholder's equity$11,027
 $10,634


See the Combined Notes to Consolidated Financial Statements

34



BALTIMORE GAS AND ELECTRIC COMPANY
STATEMENTS OF CHANGES IN SHAREHOLDER'S EQUITY
(Unaudited)
Six Months Ended June 30, 2021
(In millions)Common
Stock		Retained
Earnings		Total
Shareholder's
Equity
Balance, December 31, 2020$2,318 $1,879 $4,197 
Net income— 209 209 
Common stock dividends— (74)(74)
Balance, March 31, 2021$2,318 $2,014 $4,332 
Net income— 45 45 
Common stock dividends— (72)(72)
Balance, June 30, 2021$2,318 $1,987 $4,305 
Six Months Ended June 30, 2020
(In millions)Common
Stock		Retained
Earnings		Total
Shareholder's
Equity
Balance, December 31, 2019$1,907 $1,776 $3,683 
Net income— 181 181 
Common stock dividends— (62)(62)
Balance, March 31, 2020$1,907 $1,895 $3,802 
Net income— 39 39 
Common stock dividends— (62)(62)
Contributions from parent26 — 26 
Balance, June 30, 2020$1,933 $1,872 $3,805 
See the Combined Notes to Consolidated Financial Statements
35



 Six Months Ended June 30, 2020
(In millions)
Common
Stock
 
Retained
Earnings
 
Total
Shareholder's
Equity
Balance, December 31, 2019$1,907
 $1,776
 $3,683
Net income—
 181
 181
Common stock dividends—
 (62) (62)
Balance, March 31, 2020$1,907
 $1,895
 $3,802
Net income—
 39
 39
Common stock dividends—
 (62) (62)
Contributions from parent26
 —
 26
Balance, June 30, 2020$1,933

$1,872
 $3,805
      
 Six Months Ended June 30, 2019
(In millions)
Common
Stock
 
Retained
Earnings
 
Total
Shareholder's
Equity
Balance, December 31, 2018$1,714
 $1,640
 $3,354
Net income—
 160
 160
Common stock dividends—
 (56) (56)
Balance, March 31, 2019$1,714
 $1,744
 $3,458
Net income—
 45
 45
Common stock dividends—
 (55) (55)
Balance, June 30, 2019$1,714
 $1,734
 $3,448



PEPCO HOLDINGS LLC AND SUBSIDIARY COMPANIES
CONSOLIDATED STATEMENTS OF OPERATIONS AND COMPREHENSIVE INCOME
(Unaudited)
Three Months Ended
June 30,		Six Months Ended
June 30,
(In millions)2021202020212020
Operating revenues
Electric operating revenues$1,071 $1,047 $2,195 $2,133 
Natural gas operating revenues24 30 94 94 
Revenues from alternative revenue programs41 (64)88 (47)
Operating revenues from affiliates4 3 7 7 
Total operating revenues1,140 1,016 2,384 2,187 
Operating expenses
Purchased power308 286 656 586 
Purchased fuel9 11 41 42 
Purchased power from affiliates79 78 177 182 
Operating and maintenance217 245 434 464 
Operating and maintenance from affiliates39 36 79 74 
Depreciation and amortization194 191 404 385 
Taxes other than income taxes109 109 222 222 
Total operating expenses955 956 2,013 1,955 
Gain on sales of assets0 0 0 2 
Operating income185 60 371 234 
Other income and (deductions)
Interest expense, net(67)(67)(134)(134)
Other, net20 14 36 26 
Total other income and (deductions)(47)(53)(98)(108)
Income before income taxes138 7 273 126 
Income taxes(3)(87)5 (76)
Equity in earnings of unconsolidated affiliate0 0 1 0 
Net income$141 $94 $269 $202 
Comprehensive income$141 $94 $269 $202 
See the Combined Notes to Consolidated Financial Statements
36



 Three Months Ended
June 30,		 Six Months Ended
June 30,
(In millions)2020 2019 2020 2019
Operating revenues       
Electric operating revenues$1,047
 $1,067
 $2,133
 $2,205
Natural gas operating revenues30
 24
 94
 95
Revenues from alternative revenue programs(64) (3) (47) 12
Operating revenues from affiliates3
 3
 7
 7
Total operating revenues1,016
 1,091
 2,187
 2,319
Operating expenses       
Purchased power286
 303
 586
 658
Purchased fuel11
 9
 42
 43
Purchased power from affiliates78
 70
 182
 171
Operating and maintenance245
 213
 464
 452
Operating and maintenance from affiliates36
 35
 74
 68
Depreciation and amortization191
 188
 385
 369
Taxes other than income taxes109
 108
 222
 220
Total operating expenses956
 926
 1,955
 1,981
Gain on sales of assets—
 —
 2
 —
Operating income60
 165

234
 338
Other income and (deductions)       
Interest expense, net(67) (67) (134) (131)
Other, net14
 14
 26
 27
Total other income and (deductions)(53) (53) (108) (104)
Income before income taxes7
 112
 126
 234
Income taxes(87) 6
 (76) 11
Net income$94
 $106
 $202
 $223
Comprehensive income$94
 $106
 $202
 $223

PEPCO HOLDINGS LLC AND SUBSIDIARY COMPANIES
CONSOLIDATED STATEMENTS OF CASH FLOWS
(Unaudited)
Six Months Ended
June 30,
(In millions)20212020
Cash flows from operating activities
Net income$269 $202 
Adjustments to reconcile net income to net cash flows from operating activities:
Depreciation and amortization404 385 
Deferred income taxes and amortization of investment tax credits10 (74)
Other non-cash operating activities(50)107 
Changes in assets and liabilities:
Accounts receivable(30)(64)
Receivables from and payables to affiliates, net(22)(22)
Inventories3 6 
Accounts payable and accrued expenses(35)14 
Income taxes(1)(30)
Pension and non-pension postretirement benefit contributions(40)(31)
Other assets and liabilities(131)(146)
Net cash flows provided by operating activities377 347 
Cash flows from investing activities
Capital expenditures(889)(686)
Other investing activities(2)2 
Net cash flows used in investing activities(891)(684)
Cash flows from financing activities
Changes in short-term borrowings(36)(189)
Issuance of long-term debt625 373 
Retirement of long-term debt(249)(35)
Changes in Exelon intercompany money pool(12)10 
Distributions to member(414)(268)
Contributions from member560 359 
Other financing activities(8)(8)
Net cash flows provided by financing activities466 242 
Decrease in cash, restricted cash, and cash equivalents(48)(95)
Cash, restricted cash, and cash equivalents at beginning of period160 181 
Cash, restricted cash, and cash equivalents at end of period$112 $86 
Supplemental cash flow information
Decrease in capital expenditures not paid$(41)$(24)
See the Combined Notes to Consolidated Financial Statements
37



 Six Months Ended
June 30,
(In millions)2020 2019
Cash flows from operating activities  
Net income$202
 $223
Adjustments to reconcile net income to net cash flows provided by operating activities:   
Depreciation and amortization385
 369
Deferred income taxes and amortization of investment tax credits(74) 2
Other non-cash operating activities107
 54
Changes in assets and liabilities:   
Accounts receivable(64) (34)
Receivables from and payables to affiliates, net(22) (8)
Inventories6
 (25)
Accounts payable and accrued expenses14
 (25)
Income taxes(30) (12)
Pension and non-pension postretirement benefit contributions(31) (11)
Other assets and liabilities(146) (114)
Net cash flows provided by operating activities347
 419
Cash flows from investing activities   
Capital expenditures(686) (698)
Other investing activities2
 2
Net cash flows used in investing activities(684)
(696)
Cash flows from financing activities   
Changes in short-term borrowings(189) (27)
Repayments of short-term borrowings with maturities greater than 90 days—
 (125)
Issuance of long-term debt373
 410
Retirement of long-term debt(35) (125)
Changes in Exelon intercompany money pool10
 3
Distributions to member(268) (216)
Contributions from member359
 283
Other financing activities(8) (4)
Net cash flows provided by financing activities242
 199
Decrease in cash, cash equivalents and restricted cash(95) (78)
Cash, cash equivalents and restricted cash at beginning of period181
 186
Cash, cash equivalents and restricted cash at end of period$86
 $108
    
Supplemental cash flow information   
Decrease in capital expenditures not paid$(24) $(74)

PEPCO HOLDINGS LLC AND SUBSIDIARY COMPANIES
CONSOLIDATED BALANCE SHEETS
(Unaudited)
(In millions)June 30, 2021December 31, 2020
ASSETS
Current assets
Cash and cash equivalents$61 $111 
Restricted cash and cash equivalents42 39 
Accounts receivable
Customer accounts receivable617611
Customer allowance for credit losses(93)(86)
Customer accounts receivable, net524 525 
Other accounts receivable286260
Other allowance for credit losses(38)(33)
Other accounts receivable, net248 227 
Receivables from affiliates1 8 
Inventories, net
Fossil fuel5 6 
Materials and supplies196 198 
Regulatory assets431 440 
Other77 45 
Total current assets1,585 1,599 
Property, plant, and equipment (net of accumulated depreciation and amortization of $1,827 and $1,811 as of June 30, 2021 and December 31, 2020, respectively)15,927 15,377 
Deferred debits and other assets
Regulatory assets1,898 1,933 
Investments145 140 
Goodwill4,005 4,005 
Prepaid pension asset370 365 
Deferred income taxes10 10 
Other295 307 
Total deferred debits and other assets6,723 6,760 
Total assets(a)
$24,235 $23,736 
See the Combined Notes to Consolidated Financial Statements
38



(In millions)June 30, 2020 December 31, 2019
ASSETS   
Current assets   
Cash and cash equivalents$39
 $131
Restricted cash and cash equivalents36
 36
Accounts receivable   
Customer accounts receivable554 516
Customer allowance for credit losses(62) (37)
Customer accounts receivable, net492
 479
Other accounts receivable234 190
Other allowance for credit losses(26) (16)
Other accounts receivable, net208
 174
Receivables from affiliates1
 1
Inventories, net   
Fossil fuel5
 8
Materials and supplies187
 190
Regulatory assets449
 412
Other75
 49
Total current assets1,492

1,480
Property, plant and equipment (net of accumulated depreciation and amortization of $1,591 and $1,213 as of June 30, 2020 and December 31, 2019, respectively)14,692
 14,296
Deferred debits and other assets   
Regulatory assets1,962
 2,061
Investments135
 135
Goodwill4,005
 4,005
Prepaid pension asset396
 406
Deferred income taxes13
 13
Other309
 323
Total deferred debits and other assets6,820

6,943
Total assets(a)
$23,004

$22,719

PEPCO HOLDINGS LLC AND SUBSIDIARY COMPANIES
CONSOLIDATED BALANCE SHEETS
(Unaudited)
(In millions)June 30, 2020 December 31, 2019(In millions)June 30, 2021December 31, 2020
LIABILITIES AND MEMBER'S EQUITY   LIABILITIES AND MEMBER'S EQUITY
Current liabilities   Current liabilities
Short-term borrowings$19
 $208
Short-term borrowings$332 $368 
Long-term debt due within one year350
 103
Long-term debt due within one year300 347 
Accounts payable486
 462
Accounts payable517 539 
Accrued expenses238
 296
Accrued expenses246 299 
Payables to affiliates76
 98
Payables to affiliates75 104 
Borrowings from Exelon intercompany money pool22
 12
Borrowings from Exelon intercompany money pool9 21 
Customer deposits115
 117
Customer deposits89 106 
Regulatory liabilities148
 70
Regulatory liabilities123 137 
Unamortized energy contract liabilities103
 115
Unamortized energy contract liabilities92 92 
Other128
 131
Other131 141 
Total current liabilities1,685
 1,612
Total current liabilities1,914 2,154 
Long-term debt6,540
 6,460
Long-term debt7,069 6,659 
Deferred credits and other liabilities   Deferred credits and other liabilities
Deferred income taxes and unamortized investment tax credits2,350
 2,278
Deferred income taxes and unamortized investment tax credits2,541 2,439 
Asset retirement obligations57
 57
Asset retirement obligations59 59 
Non-pension postretirement benefit obligations87
 93
Non-pension postretirement benefit obligations75 86 
Regulatory liabilities1,553
 1,707
Regulatory liabilities1,338 1,438 
Unamortized energy contract liabilities282
 327
Unamortized energy contract liabilities190 235 
Other549
 577
Other590 622 
Total deferred credits and other liabilities4,878
 5,039
Total deferred credits and other liabilities4,793 4,879 
Total liabilities(a)
13,103
 13,111
Total liabilities(a)
13,776 13,692 
Commitments and contingencies

 

Commitments and contingencies00
Member's equity   Member's equity
Membership interest9,977
 9,618
Membership interest10,672 10,112 
Undistributed losses(76) (10)Undistributed losses(213)(68)
Total member's equity9,901

9,608
Total member's equity10,459 10,044 
Total liabilities and member's equity$23,004

$22,719
Total liabilities and member's equity$24,235 $23,736 
__________
(a)PHI’s consolidated total assets include $21 million and $20 million at June 30, 2020 and December 31, 2019, respectively, of PHI's consolidated VIE that can only be used to settle the liabilities of the VIE. PHI’s consolidated total liabilities include $37 million and $44 million at June 30, 2020 and December 31, 2019, respectively, of PHI's consolidated VIE for which the VIE creditors do not have recourse to PHI. See Note 16 — Variable Interest Entities for additional information.

(a)PHI’s consolidated total assets include $16 million and $18 million at June 30, 2021 and December 31, 2020, respectively, of PHI's consolidated VIE that can only be used to settle the liabilities of the VIE. PHI’s consolidated total liabilities include $15 million and $26 million at June 30, 2021 and December 31, 2020, respectively, of PHI's consolidated VIE for which the VIE creditors do not have recourse to PHI. See Note 17 — Variable Interest Entities for additional information.
See the Combined Notes to Consolidated Financial Statements
39



PEPCO HOLDINGS LLC AND SUBSIDIARY COMPANIES
CONSOLIDATED STATEMENTS OF CHANGES IN MEMBER'S EQUITY
(Unaudited)
Six Months Ended June 30, 2021
(In millions)Membership InterestUndistributed (Losses)/EarningsTotal Member's Equity
Balance, December 31, 2020$10,112 $(68)$10,044 
Net income— 128 128 
Distributions to member— (81)(81)
Contributions from member560 — 560 
Balance, March 31, 2021$10,672 $(21)$10,651 
Net income— 141 141 
Distributions to member— (333)(333)
Balance, June 30, 2021$10,672 $(213)$10,459 

Six Months Ended June 30, 2020
(In millions)Membership InterestUndistributed (Losses)/EarningsTotal Member's Equity
Balance, December 31, 2019$9,618 $(10)$9,608 
Net income— 108 108 
Distributions to member— (134)(134)
Contributions from member144 — 144 
Balance, March 31, 2020$9,762 $(36)$9,726 
Net income— 94 94 
Distributions to member— (134)(134)
Contributions from member215 — 215 
Balance, June 30, 2020$9,977 $(76)$9,901 
See the Combined Notes to Consolidated Financial Statements
40



 Six Months Ended June 30, 2020
(In millions)Membership Interest Undistributed Earnings (Losses) Member's Equity
Balance, December 31, 2019$9,618
 $(10) $9,608
Net income—
 108
 108
Distributions to member—
 (134) (134)
Contributions from member144
 —
 144
Balance, March 31, 2020$9,762
 $(36) $9,726
Net income—
 94
 94
Distributions to member—
 (134) (134)
Contributions from member215
 —
 215
Balance, June 30, 2020$9,977
 $(76) $9,901
 Six Months Ended June 30, 2019
(In millions)Membership Interest Undistributed Earnings (Losses) Member's Equity
Balance, December 31, 2018$9,220
 $62
 $9,282
Net income—
 117
 117
Distributions to member—
 (128) (128)
Contributions from member19
 —
 19
Balance, March 31, 2019$9,239
 $51
 $9,290
Net income—
 106
 106
Distributions to member—
 (88) (88)
Contributions from member264
 —
 264
Balance, June 30, 2019$9,503
 $69
 $9,572


POTOMAC ELECTRIC POWER COMPANY
STATEMENTS OF OPERATIONS AND COMPREHENSIVE INCOME
(Unaudited)
Three Months Ended
June 30,		Six Months Ended
June 30,
(In millions)2021202020212020
Operating revenues
Electric operating revenues$503 $506 $1,027 $1,034 
Revenues from alternative revenue programs19 (13)46 2 
Operating revenues from affiliates1 1 3 3 
Total operating revenues523 494 1,076 1,039 
Operating expenses
Purchased power76 78 168 164 
Purchased power from affiliate57 60 130 139 
Operating and maintenance62 67 118 128 
Operating and maintenance from affiliates51 52 103 103 
Depreciation and amortization96 92 199 186 
Taxes other than income taxes87 87 177 179 
Total operating expenses429 436 895 899 
Operating income94 58 181 140 
Other income and (deductions)
Interest expense, net(35)(34)(69)(68)
Other, net13 9 25 18 
Total other income and (deductions)(22)(25)(44)(50)
Income before income taxes72 33 137 90 
Income taxes(3)(24)3 (19)
Net income$75 $57 $134 $109 
Comprehensive income$75 $57 $134 $109 
See the Combined Notes to Consolidated Financial Statements
41



 Three Months Ended
June 30,		 Six Months Ended
June 30,
(In millions)2020
2019 2020 2019
Operating revenues       
Electric operating revenues$506
 $531
 $1,034
 $1,090
Revenues from alternative revenue programs(13) (1) 2
 13
Operating revenues from affiliates1
 1
 3
 3
Total operating revenues494
 531
 1,039
 1,106
Operating expenses       
Purchased power78
 92
 164
 209
Purchased power from affiliate60
 52
 139
 122
Operating and maintenance67
 59
 128
 123
Operating and maintenance from affiliates52
 52
 103
 107
Depreciation and amortization92
 93
 186
 186
Taxes other than income taxes87
 90
 179
 182
Total operating expenses436
 438
 899
 929
Operating income58
 93
 140
 177
Other income and (deductions)       
Interest expense, net(34) (34) (68) (68)
Other, net9
 7
 18
 14
Total other income and (deductions)(25) (27) (50) (54)
Income before income taxes33
 66
 90
 123
Income taxes(24) 2
 (19) 4
Net income$57
 $64
 $109
 $119
Comprehensive income$57
 $64
 $109
 $119

POTOMAC ELECTRIC POWER COMPANY
STATEMENTS OF CASH FLOWS
(Unaudited)
Six Months Ended
June 30,
(In millions)20212020
Cash flows from operating activities
Net income$134 $109 
Adjustments to reconcile net income to net cash flows provided by operating activities:
Depreciation and amortization199 186 
Deferred income taxes and amortization of investment tax credits10 (22)
Other non-cash operating activities(43)11 
Changes in assets and liabilities:
Accounts receivable(23)(45)
Receivables from and payables to affiliates, net(11)(22)
Inventories1 3 
Accounts payable and accrued expenses(26)11 
Income taxes(20)(18)
Pension and non-pension postretirement benefit contributions(7)(6)
Other assets and liabilities(79)(52)
Net cash flows provided by operating activities135 155 
Cash flows from investing activities
Capital expenditures(439)(324)
Other investing activities(2)(3)
Net cash flows used in investing activities(441)(327)
Cash flows from financing activities
Changes in short-term borrowings119 (68)
Issuance of long-term debt150 150 
Retirement of long-term debt0 (1)
Changes in PHI intercompany money pool9 50 
Dividends paid on common stock(123)(101)
Contributions from parent138 137 
Other financing activities(2)(6)
Net cash flows provided by financing activities291 161 
Decrease in cash, restricted cash, and cash equivalents(15)(11)
Cash, restricted cash, and cash equivalents at beginning of period65 63 
Cash, restricted cash, and cash equivalents at end of period$50 $52 
Supplemental cash flow information
Decrease in capital expenditures not paid$(15)$(28)
See the Combined Notes to Consolidated Financial Statements
42



 Six Months Ended
June 30,
(In millions)2020 2019
Cash flows from operating activities   
Net income$109
 $119
Adjustments to reconcile net income to net cash flows provided by operating activities:   
Depreciation and amortization186
 186
Deferred income taxes and amortization of investment tax credits(22) 10
Other non-cash operating activities11
 8
Changes in assets and liabilities:   
Accounts receivable(45) (36)
Receivables from and payables to affiliates, net(22) 4
Inventories3
 (20)
Accounts payable and accrued expenses11
 (25)
Income taxes(18) (23)
Pension and non-pension postretirement benefit contributions(6) (6)
Other assets and liabilities(52) (40)
Net cash flows provided by operating activities155
 177
Cash flows from investing activities   
Capital expenditures(324) (298)
Changes in PHI intercompany money pool—
 (38)
Other investing activities(3) 1
Net cash flows used in investing activities(327) (335)
Cash flows from financing activities   
Changes in short-term borrowings(68) (40)
Issuance of long-term debt150
 260
Retirement of long-term debt(1) (117)
Changes in PHI intercompany money pool50
 —
Dividends paid on common stock(101) (72)
Contributions from parent137
 129
Other financing activities(6) (3)
Net cash flows provided by financing activities161
 157
Decrease in cash, cash equivalents and restricted cash(11) (1)
Cash, cash equivalents and restricted cash at beginning of period63
 53
Cash, cash equivalents and restricted cash at end of period$52
 $52
    
Supplemental cash flow information   
Decrease in capital expenditures not paid$(28) $(18)

POTOMAC ELECTRIC POWER COMPANY
BALANCE SHEETS
(Unaudited)
(In millions)June 30, 2021December 31, 2020
ASSETS
Current assets
Cash and cash equivalents$17 $30 
Restricted cash and cash equivalents33 35 
Accounts receivable
Customer accounts receivable290279
Customer allowance for credit losses(38)(32)
Customer accounts receivable, net252 247 
Other accounts receivable155131
Other allowance for credit losses(16)(13)
Other accounts receivable, net139 118 
Receivables from affiliates0 2 
Inventories, net110 111 
Regulatory assets215 214 
Other13 13 
Total current assets779 770 
Property, plant, and equipment (net of accumulated depreciation and amortization of $3,782 and $3,697 as of June 30, 2021 and December 31, 2020, respectively)7,771 7,456 
Deferred debits and other assets
Regulatory assets571 570 
Investments118 115 
Prepaid pension asset282 284 
Other67 69 
Total deferred debits and other assets1,038 1,038 
Total assets$9,588 $9,264 
See the Combined Notes to Consolidated Financial Statements
43



(In millions)June 30, 2020
December 31, 2019
ASSETS   
Current assets   
Cash and cash equivalents$19
 $30
Restricted cash and cash equivalents33
 33
Accounts receivable   
Customer accounts receivable272 244
Customer allowance for credit losses(24) (13)
Customer accounts receivable, net248
 231
Other accounts receivable121 98
Other allowance for credit losses(11) (7)
Other accounts receivable, net110
 91
Receivables from affiliates2
 —
Inventories, net109
 112
Regulatory assets215
 188
Other11
 11
Total current assets747

696
Property, plant and equipment (net of accumulated depreciation and amortization of $3,604 and $3,517 as of June 30, 2020 and December 31, 2019, respectively)7,102
 6,909
Deferred debits and other assets   
Regulatory assets556
 584
Investments111
 110
Prepaid pension asset290
 296
Other63
 66
Total deferred debits and other assets1,020

1,056
Total assets$8,869

$8,661

POTOMAC ELECTRIC POWER COMPANY
BALANCE SHEETS
(Unaudited)
(In millions)June 30, 2021December 31, 2020
LIABILITIES AND SHAREHOLDER'S EQUITY
Current liabilities
Short-term borrowings$154 $35 
Long-term debt due within one year204 3 
Accounts payable215 226 
Accrued expenses123 164 
Payables to affiliates42 55 
Borrowings from PHI intercompany money pool9 0 
Customer deposits41 51 
Regulatory liabilities38 46 
Merger related obligation29 33 
Current portion of DC PLUG obligation30 30 
Other29 31 
Total current liabilities914 674 
Long-term debt3,114 3,162 
Deferred credits and other liabilities
Deferred income taxes and unamortized investment tax credits1,244 1,189 
Asset retirement obligations39 39 
Non-pension postretirement benefit obligations7 13 
Regulatory liabilities599 644 
Other319 340 
Total deferred credits and other liabilities2,208 2,225 
Total liabilities6,236 6,061 
Commitments and contingencies00
Shareholder's equity
Common stock2,196 2,058 
Retained earnings1,156 1,145 
Total shareholder's equity3,352 3,203 
Total liabilities and shareholder's equity$9,588 $9,264 
See the Combined Notes to Consolidated Financial Statements
44



(In millions)June 30, 2020 December 31, 2019
LIABILITIES AND SHAREHOLDER'S EQUITY   
Current liabilities   
Short-term borrowings$14
 $82
Long-term debt due within one year3
 2
Accounts payable195
 195
Accrued expenses123
 156
Payables to affiliates46
 66
Borrowings from PHI intercompany money pool50
 —
Customer deposits57
 57
Regulatory liabilities48
 8
Merger related obligation39
 39
Current portion of DC PLUG obligation30
 30
Other16
 22
Total current liabilities621

657
Long-term debt3,010
 2,862
Deferred credits and other liabilities   
Deferred income taxes and unamortized investment tax credits1,168
 1,131
Asset retirement obligations41
 41
Non-pension postretirement benefit obligations15
 20
Regulatory liabilities686
 746
Other276
 297
Total deferred credits and other liabilities2,186

2,235
Total liabilities5,817

5,754
Commitments and contingencies

 

Shareholder's equity   
Common stock1,933
 1,796
Retained earnings1,119
 1,111
Total shareholder's equity3,052
 2,907
Total liabilities and shareholder's equity$8,869
 $8,661

POTOMAC ELECTRIC POWER COMPANY
STATEMENTS OF CHANGES IN SHAREHOLDER'S EQUITY
(Unaudited)
Six Months Ended June 30, 2021
(In millions)Common StockRetained EarningsTotal Shareholder's Equity
Balance, December 31, 2020$2,058 $1,145 $3,203 
Net income— 59 59 
Common stock dividends— (28)(28)
Contributions from parent138 — 138 
Balance, March 31, 2021$2,196 $1,176 $3,372 
Net income— 75 75 
Common stock dividends— (95)(95)
Balance, June 30, 2021$2,196 $1,156 $3,352 

Six Months Ended June 30, 2020
(In millions)Common StockRetained EarningsTotal Shareholder's Equity
Balance, December 31, 2019$1,796 $1,111 $2,907 
Net income— 52 52 
Common stock dividends— (28)(28)
Contributions from parent137 — 137 
Balance, March 31, 2020$1,933 $1,135 $3,068 
Net income— 57 57 
Common stock dividends— (73)(73)
Balance, June 30, 2020$1,933 $1,119 $3,052 

See the Combined Notes to Consolidated Financial Statements
45



 Six Months Ended June 30, 2020
(In millions)Common Stock Retained Earnings Total Shareholder's Equity
Balance, December 31, 2019$1,796
 $1,111
 $2,907
Net income—
 52
 52
Common stock dividends—
 (28) (28)
Contributions from parent137
 —
 137
Balance, March 31, 2020$1,933
 $1,135
 $3,068
Net income—
 57
 57
Common stock dividends—
 (73) (73)
Balance, June 30, 2020$1,933
 $1,119
 $3,052
 Six Months Ended June 30, 2019
(In millions)Common Stock Retained Earnings Total Shareholder's Equity
Balance, December 31, 2018$1,636
 $1,104
 $2,740
Net income—
 55
 55
Common stock dividends—
 (24) (24)
Contributions from parent14
 —
 14
Balance, March 31, 2019$1,650
 $1,135
 $2,785
Net income—
 64
 64
Common stock dividends—
 (48) (48)
Contributions from parent115
 —
 115
Balance, June 30, 2019$1,765
 $1,151
 $2,916



DELMARVA POWER & LIGHT COMPANY
STATEMENTS OF OPERATIONS AND COMPREHENSIVE INCOME
(Unaudited)
Three Months Ended
June 30,		Six Months Ended
June 30,
(In millions)2021202020212020
Operating revenues
Electric operating revenues$262 $260 $562 $543 
Natural gas operating revenues24 30 95 94 
Revenues from alternative revenue programs10 (25)19 (24)
Operating revenues from affiliates2 2 4 4 
Total operating revenues298 267 680 617 
Operating expenses
Purchased power82 80 185 169 
Purchased fuel9 11 41 42 
Purchased power from affiliates17 16 37 38 
Operating and maintenance41 54 85 97 
Operating and maintenance from affiliates39 38 79 75 
Depreciation and amortization51 47 104 94 
Taxes other than income taxes16 17 33 32 
Total operating expenses255 263 564 547 
Operating income43 4 116 70 
Other income and (deductions)
Interest expense, net(16)(15)(30)(31)
Other, net4 2 6 5 
Total other income and (deductions)(12)(13)(24)(26)
Income (loss) before income taxes31 (9)92 44 
Income taxes1 (28)6 (20)
Net income$30 $19 $86 $64 
Comprehensive income$30 $19 $86 $64 
See the Combined Notes to Consolidated Financial Statements
46



 Three Months Ended
June 30,
Six Months Ended
June 30,
(In millions)2020
2019
2020
2019
Operating revenues       
Electric operating revenues$260
 $261
 $543
 $568
Natural gas operating revenues30
 24
 94
 95
Revenues from alternative revenue programs(25) —
 (24) 1
Operating revenues from affiliates2
 2
 4
 3
Total operating revenues267

287

617

667
Operating expenses       
Purchased power80
 86
 169
 193
Purchased fuel11
 9
 42
 43
Purchased power from affiliates16
 12
 38
 35
Operating and maintenance54
 39
 97
 84
Operating and maintenance from affiliates38
 38
 75
 76
Depreciation and amortization47
 45
 94
 91
Taxes other than income taxes17
 14
 32
 28
Total operating expenses263

243

547

550
Operating income4

44

70

117
Other income and (deductions)       
Interest expense, net(15) (15) (31) (30)
Other, net2
 5
 5
 7
Total other income and (deductions)(13)
(10)
(26)
(23)
(Loss) income before income taxes(9) 34
 44
 94
Income taxes(28) 4
 (20) 11
Net income$19

$30

$64

$83
Comprehensive income$19
 $30
 $64
 $83

DELMARVA POWER & LIGHT COMPANY
STATEMENTS OF CASH FLOWS
(Unaudited)
Six Months Ended
June 30,
(In millions)20212020
Cash flows from operating activities
Net income$86 $64 
Adjustments to reconcile net income to net cash flows provided by operating activities:
Depreciation and amortization104 94 
Deferred income taxes and amortization of investment tax credits4 (19)
Other non-cash operating activities(12)40 
Changes in assets and liabilities:
Accounts receivable24 6 
Receivables from and payables to affiliates, net(12)(2)
Accounts payable and accrued expenses7 3 
Income taxes14 (12)
Other assets and liabilities(22)(21)
Net cash flows provided by operating activities193 153 
Cash flows from investing activities
Capital expenditures(211)(184)
Changes in PHI intercompany money pool(9)(55)
Other investing activities1 (3)
Net cash flows used in investing activities(219)(242)
Cash flows from financing activities
Changes in short-term borrowings(146)(56)
Issuance of long-term debt125 100 
Retirement of long-term debt0 (1)
Dividends paid on common stock(63)(66)
Contributions from parent120 106 
Other financing activities(3)(1)
Net cash flows provided by financing activities33 82 
Increase (decrease) in cash, restricted cash, and cash equivalents7 (7)
Cash, restricted cash, and cash equivalents at beginning of period15 13 
Cash, restricted cash, and cash equivalents at end of period$22 $6 
Supplemental cash flow information
Decrease in capital expenditures not paid$(14)$(4)
See the Combined Notes to Consolidated Financial Statements
47



 Six Months Ended
June 30,
(In millions)2020
2019
Cash flows from operating activities   
Net income$64
 $83
Adjustments to reconcile net income to net cash flows provided by operating activities:   
Depreciation and amortization94
 91
Deferred income taxes and amortization of investment tax credits(19) (5)
Other non-cash operating activities40
 11
Changes in assets and liabilities:   
Accounts receivable6
 15
Receivables from and payables to affiliates, net(2) (11)
Inventories—
 (3)
Accounts payable and accrued expenses3
 6
Income taxes(12) 11
Pension and non-pension postretirement benefit contributions—
 (1)
Other assets and liabilities(21) (26)
Net cash flows provided by operating activities153

171
Cash flows from investing activities   
Capital expenditures(184) (160)
Changes in PHI intercompany money pool(55) —
Other investing activities(3) 1
Net cash flows used in investing activities(242)
(159)
Cash flows from financing activities   
Changes in short-term borrowings(56) —
Issuance of long-term debt100
 —
Retirement of long-term debt(1) —
Changes in PHI intercompany money pool—
 38
Dividends paid on common stock(66) (70)
Contributions from parent106
 —
Other financing activities(1) —
Net cash flows provided by (used in) financing activities82

(32)
Decrease in cash, cash equivalents and restricted cash(7) (20)
Cash, cash equivalents and restricted cash at beginning of period13
 24
Cash, cash equivalents and restricted cash at end of period$6

$4
    
Supplemental cash flow information   
Decrease in capital expenditures not paid$(4) $(17)

DELMARVA POWER & LIGHT COMPANY
BALANCE SHEETS
(Unaudited)
(In millions)June 30, 2021December 31, 2020
ASSETS
Current assets
Cash and cash equivalents$17 $15 
Restricted cash and cash equivalents5 0 
Accounts receivable
Customer accounts receivable139176
Customer allowance for credit losses(19)(22)
Customer accounts receivable, net120 154 
Other accounts receivable6268
Other allowance for credit losses(9)(9)
Other accounts receivable, net53 59 
Receivables from affiliates0 1 
Receivable from PHI intercompany pool9 0 
Inventories, net
Fossil fuel5 6 
Materials and supplies52 51 
Prepaid utility taxes0 11 
Regulatory assets70 58 
Renewable energy credits18 10 
Other3 3 
Total current assets352 368 
Property, plant, and equipment (net of accumulated depreciation and amortization of $1,571 and $1,533 as of June 30, 2021 and December 31, 2020, respectively)4,425 4,314 
Deferred debits and other assets
Regulatory assets223 222 
Goodwill8 8 
Prepaid pension asset159 162 
Other62 66 
Total deferred debits and other assets452 458 
Total assets$5,229 $5,140 
See the Combined Notes to Consolidated Financial Statements
48



(In millions)June 30, 2020 December 31, 2019
ASSETS   
Current assets   
Cash and cash equivalents$6
 $13
Accounts receivable   
Customer accounts receivable145 152
Customer allowance for credit losses(18) (11)
Customer accounts receivable, net127
 141
Other accounts receivable48 42
Other allowance for credit losses(7) (4)
Other accounts receivable, net41
 38
Receivables from affiliates1
 —
Receivable from PHI intercompany pool55
 —
Inventories, net   
Fossil fuel5
 8
Materials and supplies47
 44
Prepaid utility taxes2
 18
Regulatory assets55
 52
Renewable energy credits21
 9
Other3
 2
Total current assets363

325
Property, plant and equipment (net of accumulated depreciation and amortization of $1,476 and $1,425 as of June 30, 2020 and December 31, 2019, respectively)4,143
 4,035
Deferred debits and other assets   
Regulatory assets222
 222
Goodwill8
 8
Prepaid pension asset166
 171
Other64
 69
Total deferred debits and other assets460

470
Total assets$4,966

$4,830

DELMARVA POWER & LIGHT COMPANY
BALANCE SHEETS
(Unaudited)
(In millions)June 30, 2021December 31, 2020
LIABILITIES AND SHAREHOLDER'S EQUITY
Current liabilities
Short-term borrowings$0 $146 
Long-term debt due within one year82 82 
Accounts payable125 126 
Accrued expenses40 46 
Payables to affiliates23 36 
Customer deposits28 32 
Regulatory liabilities46 47 
Other14 20 
Total current liabilities358 535 
Long-term debt1,722 1,595 
Deferred credits and other liabilities
Deferred income taxes and unamortized investment tax credits745 715 
Asset retirement obligations14 14 
Non-pension postretirement benefits obligations13 15 
Regulatory liabilities462 493 
Other96 97 
Total deferred credits and other liabilities1,330 1,334 
Total liabilities3,410 3,464 
Commitments and contingencies00
Shareholder's equity
Common stock1,209 1,089 
Retained earnings610 587 
Total shareholder's equity1,819 1,676 
Total liabilities and shareholder's equity$5,229 $5,140 
See the Combined Notes to Consolidated Financial Statements
49



(In millions)June 30, 2020 December 31, 2019
LIABILITIES AND SHAREHOLDER'S EQUITY   
Current liabilities   
Short-term borrowings$—
 $56
Long-term debt due within one year81
 80
Accounts payable113
 112
Accrued expenses34
 46
Payables to affiliates27
 32
Customer deposits35
 36
Regulatory liabilities60
 37
Other17
 15
Total current liabilities367
 414
Long-term debt1,594
 1,487
Deferred credits and other liabilities   
Deferred income taxes and unamortized investment tax credits680
 655
Non-pension postretirement benefits obligations15
 16
Regulatory liabilities526
 574
Other100
 104
Total deferred credits and other liabilities1,321

1,349
Total liabilities3,282

3,250
Commitments and contingencies

 

Shareholder's equity   
Common stock1,083
 977
Retained earnings601
 603
Total shareholder's equity1,684

1,580
Total liabilities and shareholder's equity$4,966

$4,830

DELMARVA POWER & LIGHT COMPANY
STATEMENTS OF CHANGES IN SHAREHOLDER'S EQUITY
(Unaudited)
Six Months Ended June 30, 2021
(In millions)Common StockRetained EarningsTotal Shareholder's Equity
Balance, December 31, 2020$1,089 $587 $1,676 
Net income— 56 56 
Common stock dividends— (40)(40)
Contributions from parent120 — 120 
Balance, March 31, 2021$1,209 $603 $1,812 
Net income— 30 30 
Common stock dividends— (23)(23)
Balance, June 30, 2021$1,209 $610 $1,819 

Six Months Ended June 30, 2020
(In millions)Common StockRetained EarningsTotal Shareholder's Equity
Balance, December 31, 2019$977 $603 $1,580 
Net income— 45 45 
Common stock dividends— (52)(52)
Contributions from parent6 — 6 
Balance, March 31, 2020$983 $596 $1,579 
Net income— 19 19 
Common stock dividends— (14)(14)
Contributions from parent100 — 100 
Balance, June 30, 2020$1,083 $601 $1,684 

See the Combined Notes to Consolidated Financial Statements
50



 Six Months Ended June 30, 2020
(In millions)Common Stock Retained Earnings Total Shareholder's Equity
Balance, December 31, 2019$977
 $603
 $1,580
Net income—
 45
 45
Common stock dividends—
 (52) (52)
Contributions from parent6
 —
 6
Balance, March 31, 2020983
 596
 1,579
Net income—
 19
 19
Common stock dividends—
 (14) (14)
Contributions from parent100
 —
 100
Balance, June 30, 2020$1,083
 $601
 $1,684

 Six Months Ended June 30, 2019
(In millions)Common Stock Retained Earnings Total Shareholder's Equity
Balance, December 31, 2018$914
 $595
 $1,509
Net income—
 53
 53
Common stock dividends—
 (41) (41)
Balance, March 31, 2019914
 607
 1,521
Net income—
 30
 30
Common stock dividends—
 (29) (29)
Balance, June 30, 2019$914
 $608
 $1,522



ATLANTIC CITY ELECTRIC COMPANY AND SUBSIDIARY COMPANY
CONSOLIDATED STATEMENTS OF OPERATIONS AND COMPREHENSIVE INCOME
(Unaudited)
Three Months Ended
June 30,		Six Months Ended
June 30,
(In millions)2021202020212020
Operating revenues
Electric operating revenues$306 $281 $605 $556 
Revenues from alternative revenue programs12 (26)23 (25)
Operating revenues from affiliates1 1 1 1 
Total operating revenues319 256 629 532 
Operating expenses
Purchased power149 128 302 254 
Purchased power from affiliate5 2 9 5 
Operating and maintenance39 48 82 94 
Operating and maintenance from affiliates34 34 68 66 
Depreciation and amortization40 44 87 86 
Taxes other than income taxes2 2 4 4 
Total operating expenses269 258 552 509 
Gain on sale of assets0 0 0 2 
Operating income (loss)50 (2)77 25 
Other income and (deductions)
Interest expense, net(14)(15)(29)(29)
Other, net0 2 2 3 
Total other income and (deductions)(14)(13)(27)(26)
Income (loss) before income taxes36 (15)50 (1)
Income taxes(1)(33)(1)(32)
Net income$37 $18 $51 $31 
Comprehensive income$37 $18 $51 $31 
See the Combined Notes to Consolidated Financial Statements
51



 Three Months Ended
June 30,		 Six Months Ended
June 30,
(In millions)2020 2019 2020 2019
Operating revenues       
Electric operating revenues$281
 $275
 $556
 $547
Revenues from alternative revenue programs(26) (2) (25) (1)
Operating revenues from affiliates1
 1
 1
 1
Total operating revenues256
 274
 532
 547
Operating expenses       
Purchased power128
 125
 254
 257
Purchased power from affiliate2
 6
 5
 13
Operating and maintenance48
 41
 94
 88
Operating and maintenance from affiliates34
 33
 66
 67
Depreciation and amortization44
 40
 86
 71
Taxes other than income taxes2
 1
 4
 2
Total operating expenses258
 246
 509
 498
Gain on sale of assets—
 —
 2
 —
Operating (loss) income(2)
28
 25
 49
Other income and (deductions)       
Interest expense, net(15) (15) (29) (28)
Other, net2
 1
 3
 4
Total other income and (deductions)(13) (14) (26) (24)
(Loss) income before income taxes(15) 14
 (1) 25
Income taxes(33) —
 (32) 1
Net income$18

$14
 $31
 $24
Comprehensive income$18
 $14
 $31
 $24

ATLANTIC CITY ELECTRIC COMPANY AND SUBSIDIARY COMPANY
CONSOLIDATED STATEMENTS OF CASH FLOWS
(Unaudited)
Six Months Ended
June 30,
(In millions)20212020
Cash flows from operating activities
Net income$51 $31 
Adjustments to reconcile net income to net cash flows provided by operating activities:
Depreciation and amortization87 86 
Deferred income taxes and amortization of investment tax credits(2)(30)
Other non-cash operating activities(14)34 
Changes in assets and liabilities:
Accounts receivable(30)(23)
Receivables from and payables to affiliates, net4 9 
Inventories2 2 
Accounts payable and accrued expenses(2)17 
Income taxes2 2 
Pension and non-pension postretirement benefit contributions(3)(2)
Other assets and liabilities(25)(68)
Net cash flows provided by operating activities70 58 
Cash flows from investing activities
Capital expenditures(239)(178)
Other investing activities0 5 
Net cash flows used in investing activities(239)(173)
Cash flows from financing activities
Changes in short-term borrowings(9)(65)
Issuance of long-term debt350 123 
Retirement of long-term debt(249)(34)
Changes in PHI intercompany money pool0 5 
Dividends paid on common stock(229)(35)
Contributions from parent303 116 
Other financing activities(4)(1)
Net cash flows provided by financing activities162 109 
Decrease in cash, restricted cash, and cash equivalents(7)(6)
Cash, restricted cash, and cash equivalents at beginning of period30 28 
Cash, restricted cash, and cash equivalents at end of period$23 $22 
Supplemental cash flow information
(Decrease) increase in capital expenditures not paid$(13)$7 
See the Combined Notes to Consolidated Financial Statements
52



 Six Months Ended
June 30,
(In millions)2020
2019
Cash flows from operating activities   
Net income$31
 $24
Adjustments to reconcile net income to net cash flows provided by operating activities:   
Depreciation and amortization86
 71
Deferred income taxes and amortization of investment tax credits(30) 2
Other non-cash operating activities34
 7
Changes in assets and liabilities:   
Accounts receivable(23) (11)
Receivables from and payables to affiliates, net9
 (9)
Inventories2
 (1)
Accounts payable and accrued expenses17
 16
Income taxes2
 6
Pension and non-pension postretirement benefit contributions(2) —
Other assets and liabilities(68) (44)
Net cash flows provided by operating activities58
 61
Cash flows from investing activities   
Capital expenditures(178) (227)
Other investing activities5
 —
Net cash flows used in investing activities(173) (227)
Cash flows from financing activities   
Changes in short-term borrowings(65) 13
Repayments of short-term borrowings with maturities greater than 90 days—
 (125)
Issuance of long-term debt123
 150
Retirement of long-term debt(34) (9)
Changes in PHI intercompany money pool5

—
Dividends paid on common stock(35) (24)
Contributions from parent116
 155
Other financing activities(1) (1)
Net cash flows provided by financing activities109
 159
Decrease in cash, cash equivalents and restricted cash(6) (7)
Cash, cash equivalents and restricted cash at beginning of period28
 30
Cash, cash equivalents and restricted cash at end of period$22

$23
    
Supplemental cash flow information   
Increase (decrease) in capital expenditures not paid$7
 $(35)

ATLANTIC CITY ELECTRIC COMPANY AND SUBSIDIARY COMPANY
CONSOLIDATED BALANCE SHEETS
(Unaudited)
(In millions)June 30, 2021December 31, 2020
ASSETS
Current assets
Cash and cash equivalents$11 $17 
Restricted cash and cash equivalents3 3 
Accounts receivable
Customer accounts receivable188156
Customer allowance for credit losses(36)(32)
Customer accounts receivable, net152 124 
Other accounts receivable6972
Other allowance for credit losses(13)(11)
Other accounts receivable, net56 61 
Receivables from affiliates1 6 
Inventories, net35 37 
Prepaid utility taxes37 0 
Regulatory assets53 75 
Other5 3 
Total current assets353 326 
Property, plant, and equipment (net of accumulated depreciation and amortization of $1,358 and $1,303 as of June 30, 2021 and December 31, 2020, respectively)3,614 3,475 
Deferred debits and other assets
Regulatory assets422 395 
Prepaid pension asset35 40 
Other49 50 
Total deferred debits and other assets506 485 
Total assets(a)
$4,473 $4,286 
See the Combined Notes to Consolidated Financial Statements
53



(In millions)June 30, 2020 December 31, 2019
ASSETS   
Current assets   
Cash and cash equivalents$8
 $12
Restricted cash and cash equivalents3
 2
Accounts receivable   
Customer accounts receivable137 121
Customer allowance for credit losses(20) (13)
Customer accounts receivable, net117
 108
Other accounts receivable59 53
Other allowance for credit losses(8) (5)
Other accounts receivable, net51
 48
Receivables from affiliates1
 4
Inventories, net32
 34
Prepaid utility taxes34
 —
Regulatory assets71
 57
Other4
 5
Total current assets321
 270
Property, plant and equipment (net of accumulated depreciation and amortization of $1,261 and $1,210 as of June 30, 2020 and December 31, 2019, respectively)3,302
 3,190
Deferred debits and other assets   
Regulatory assets369
 368
Prepaid pension asset47
 52
Other50
 53
Total deferred debits and other assets466
 473
Total assets(a)
$4,089
 $3,933

ATLANTIC CITY ELECTRIC COMPANY AND SUBSIDIARY COMPANY
CONSOLIDATED BALANCE SHEETS
(Unaudited)

(In millions)June 30, 2020 December 31, 2019(In millions)June 30, 2021December 31, 2020
LIABILITIES AND SHAREHOLDER'S EQUITY   LIABILITIES AND SHAREHOLDER'S EQUITY
Current liabilities   Current liabilities
Short-term borrowings$5
 $70
Short-term borrowings$178 $187 
Long-term debt due within one year260
 20
Long-term debt due within one year13 261 
Accounts payable170
 144
Accounts payable170 177 
Accrued expenses39
 42
Accrued expenses38 46 
Payables to affiliates31
 25
Payables to affiliates30 31 
Borrowings from PHI intercompany money pool

5
 —
Customer deposits24
 25
Customer deposits20 23 
Regulatory liabilities40
 25
Regulatory liabilities39 44 
Other8
 9
Other11 11 
Total current liabilities582
 360
Total current liabilities499 780 
Long-term debt1,160
 1,307
Long-term debt1,502 1,152 
Deferred credits and other liabilities   Deferred credits and other liabilities
Deferred income taxes and unamortized investment tax credits590
 577
Deferred income taxes and unamortized investment tax credits643 624 
Non-pension postretirement benefit obligations17
 17
Non-pension postretirement benefit obligations14 17 
Regulatory liabilities312
 357
Regulatory liabilities252 274 
Other40
 39
Other47 48 
Total deferred credits and other liabilities959
 990
Total deferred credits and other liabilities956 963 
Total liabilities(a)
2,701
 2,657
Total liabilities(a)
2,957 2,895 
Commitments and contingencies

 

Commitments and contingencies00
Shareholder's equity   Shareholder's equity
Common stock1,270
 1,154
Common stock1,574 1,271 
Retained earnings118
 122
Retained (deficit) earningsRetained (deficit) earnings(58)120 
Total shareholder's equity1,388

1,276
Total shareholder's equity1,516 1,391 
Total liabilities and shareholder's equity$4,089

$3,933
Total liabilities and shareholder's equity$4,473 $4,286 
__________
(a)ACE’s consolidated total assets include $14 million and $17 million at June 30, 2020 and December 31, 2019, respectively, of ACE's consolidated VIE that can only be used to settle the liabilities of the VIE. ACE’s consolidated total liabilities include $31 million and $41 million at June 30, 2020 and December 31, 2019, respectively, of ACE's consolidated VIE for which the VIE creditors do not have recourse to ACE. See Note 16 — Variable Interest Entities for additional information.

(a)ACE’s consolidated total assets include $12 million and $13 million at June 30, 2021 and December 31, 2020, respectively, of ACE's consolidated VIE that can only be used to settle the liabilities of the VIE. ACE’s consolidated total liabilities include $11 million and $21 million at June 30, 2021 and December 31, 2020, respectively, of ACE's consolidated VIE for which the VIE creditors do not have recourse to ACE. See Note 17 — Variable Interest Entities for additional information.
See the Combined Notes to Consolidated Financial Statements
54



ATLANTIC CITY ELECTRIC COMPANY AND SUBSIDIARY COMPANY
CONSOLIDATED STATEMENTS OF CHANGES IN SHAREHOLDER'S EQUITY
(Unaudited)
Six Months Ended June 30, 2021
(In millions)Common StockRetained Earnings (Deficit)Total Shareholder's Equity
Balance, December 31, 2020$1,271 $120 $1,391 
Net income— 14 14 
Common stock dividends— (14)(14)
Contributions from parent303 — 303 
Balance, March 31, 2021$1,574 $120 $1,694 
Net income— 37 37 
Common stock dividends— (215)(215)
Balance, June 30, 2021$1,574 $(58)$1,516 
 Six Months Ended June 30, 2020
(In millions)Common Stock Retained Earnings Total Shareholder's Equity
Balance, December 31, 2019$1,154
 $122
 $1,276
Net income—
 13
 13
Common stock dividends—
 (23) (23)
Contributions from parent1
 —
 1
Balance, March 31, 20201,155
 112
 1,267
Net income—
 18
 18
Common stock dividends—
 (12) (12)
Contributions from parent115
 —
 115
Balance, June 30, 2020$1,270

$118
 $1,388


Six Months Ended June 30, 2020
(In millions)Common StockRetained EarningsTotal Shareholder's Equity
Balance, December 31, 2019$1,154 $122 $1,276 
Net income— 13 13 
Common stock dividends— (23)(23)
Contributions from parent1 — 1 
Balance, March 31, 2020$1,155 $112 $1,267 
Net income— 18 18 
Common stock dividends— (12)(12)
Contributions from parent115— 115 
Balance, June 30, 2020$1,270 $118 $1,388 

 Six Months Ended June 30, 2019
(In millions)Common Stock Retained Earnings Total Shareholder's Equity
Balance, December 31, 2018$979
 $147
 $1,126
Net income—
 10
 10
Common stock dividends—
 (12) (12)
Contributions from parent5
 —
 5
Balance, March 31, 2019984
 145
 1,129
Net income—
 14
 14
Common stock dividends—
 (12) (12)
Contributions from parent150
 —
 150
Balance, June 30, 2019$1,134

$147
 $1,281


See the Combined Notes to Consolidated Financial Statements
55



Table of Contents
COMBINED NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
(Dollars in millions, except per share data, unless otherwise noted)

Note 1 — Significant Accounting Policies


1. Significant Accounting Policies (All Registrants)
Description of Business (All Registrants)
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 RegistrantBusinessService 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 electricityDistrict of Columbia, and major portions of Montgomery and Prince George’s Counties, Maryland
Transmission and distribution of electricity to retail customers
Delmarva Power &

Light Company
Purchase 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

Basis of Presentation (All Registrants)
This is a combined quarterly report of all Registrants. The Notes to the Consolidated Financial Statements apply to the Registrants as indicated parenthetically next to each corresponding disclosure. When appropriate, the Registrants are named specifically for their related activities and disclosures. Each of the Registrant’s Consolidated Financial Statements includes the accounts of its subsidiaries. All intercompany transactions have been eliminated.
Through its business services subsidiary, BSC, Exelon provides its subsidiaries with a variety of support services at cost, including legal, human resources, financial, information technology, and supply management services. 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.
The accompanying consolidated financial statements as of June 30, 2020 and December 31, 20192021 and for the three and six months ended June 30, 20202021 and 20192020 are unaudited but, in the opinion of the management of each Registrant include all adjustments that are considered necessary for a fair statement of the Registrants’ respective financial statements in accordance with GAAP. All adjustments are of a normal, recurring nature, except as otherwise
56



COMBINED NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
(Dollars in millions, except per share data, unless otherwise noted)

Note 1 — Significant Accounting Policies
disclosed. The December 31, 20192020 Consolidated Balance Sheets were derived from audited financial statements. Financial results for interim periods are not necessarily indicative of results that may be expected for any other

56
Table of Contents
COMBINED NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
(Dollars in millions, except per share data, unless otherwise noted)

Note 1 — Significant Accounting Policies

interim period or for the fiscal year ending December 31, 2020.2021. These Combined Notes to Consolidated Financial Statements have been prepared pursuant to the rules and regulations of the SEC for Quarterly Reports on Form 10-Q. Certain information and note disclosures normally included in financial statements prepared in accordance with GAAP have been condensed or omitted pursuant to such rules and regulations.
COVID-19 (All Registrants)
The Registrants have taken steps2. Mergers, Acquisitions, and Dispositions (Exelon and Generation)
CENG Put Option (Exelon and Generation)
Generation owns 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 mitigatean 82% undivided ownership interest in Nine Mile Point Unit 2. CENG is 100% consolidated in Exelon's and Generation's financial statements. See Note 17 — Variable Interest Entities for additional information.
On April 1, 2014, Generation and EDF entered into various agreements including a NOSA, an amended LLC Operating Agreement, an Employee Matters Agreement, and a Put Option Agreement, among others. Under the potential risks posed byamended LLC Operating Agreement, CENG made a $400 million special distribution to EDF and committed to make preferred distributions to Generation until Generation has received aggregate distributions of $400 million plus a return of 8.50% per annum.
Under the global outbreak (pandemic)terms of the 2019 novel coronavirus (COVID-19).Put Option Agreement, EDF has the option to sell its 49.99% equity interest in CENG to Generation exercisable beginning on January 1, 2016 and thereafter until June 30, 2022. The RegistrantsPut Option Agreement’s terms also provide a critical service to their customers and have taken measures to keep employees who operatethat in the business safe and minimize unnecessary risk of exposureevent the put closing has not been completed prior to the virus, including extra precautions for employees who work in18-month anniversary of the field. The Registrants have implemented work from home policies where appropriateexercise date, EDF may withdraw its exercise notice. In the event of a withdrawal, EDF retains the right to exercise the put option until the later of June 30, 2022 and imposed travel limitations on employees. In addition, the Registrants have updated their existing business continuity plans.

Management makes estimates and assumptions that affect the reported amounts of assets and liabilities and disclosure of contingent assets and liabilities as of18 months following the date of withdrawal, but in no event later than January 1, 2024. EDF is not entitled to this withdrawal right in the financial statementsevent it breaches any provision of the Put Option Agreement that results in the failure of the put to close on or before the 18-month anniversary of the exercise date.
The Put Option Agreement provides that the purchase price is to be determined by agreement of the parties, or absent such agreement, by a third-party arbitration process. The third parties determining fair market value of EDF’s 49.99% interest are to take into consideration all rights and accompanying notes,obligations under the LLC Operating Agreement and the amounts of revenues and expenses reported during the periods covered by those financial statements and accompanying notes. Management assessed certain accounting matters that require consideration of forecasted financial information,Employee Matters Agreement including but not limited to our allowance for credit losses, the carrying value of our goodwill and other long-lived assets, in contextGeneration’s rights with the information reasonably availablerespect to usany unpaid aggregate preferred distributions and the unknown future impacts of COVID-19 asrelated return. As of June 30, 2021, the total unpaid aggregate preferred distributions and related return owed to Generation is $645 million. 
On November 20, 2019, Generation received notice of EDF’s intention to exercise the put option to sell its interest 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 required approval by the FERC and the NYPSC, which approvals were received on July 30, 2020 and throughApril 15, 2021, respectively. The sale process is currently expected to close in the datesecond half of this report. The Registrants' future assessment of our current expectations2021. EDF has not exercised its right to withdraw the exercise of the magnitudeput, which right became effective on July 19, 2021.
Agreement for Sale of Generation’s Solar Business (Exelon and durationGeneration)
On December 8, 2020, Generation entered into an agreement with an affiliate of COVID-19, as well as other factors, could resultBrookfield Renewable, for the sale of a significant portion of Generation’s solar business, including 360 MW of generation in material impacts to their consolidated financial statementsoperation or under construction across more than 600 sites across the United States. Generation will retain certain solar assets not included in future reporting periods.this agreement, primarily Antelope Valley.
New Accounting Standards (All Registrants)
New Accounting Standards Adopted asCompletion of January 1, 2020: The following new authoritative accounting guidance issuedthe transaction contemplated by the FASBsale agreement was adopted assubject to the satisfaction of January 1, 2020 and was reflected by the Registrants in their consolidated financial statements beginningseveral closing conditions which were satisfied in the first quarter of 2020.2021. The sale was completed on March 31, 2021 for a purchase price of $810 million. Generation received cash proceeds of $675 million, net of $125 million long-term debt assumed by the buyer and certain working capital and other post-closing adjustments. Exelon and
57

Impairment of Financial Instruments (Issued June 2016). Provides for a new Current Expected Credit Loss (CECL) impairment model for specified financial instruments including loans, trade receivables, debt securities classified as held-to-maturity investments and net investments in leases recognized by a lessor. Under the new guidance, on initial recognition and at each reporting period, an entity is required to recognize an allowance that reflects its current estimate of credit losses expected to be incurred over the life of the financial instrument based on historical experience, current conditions and reasonable and supportable forecasts. The standard was effective January 1, 2020 and requires a modified retrospective transition approach through a cumulative-effect adjustment to retained earnings as of the beginning of the period of adoption. This standard was primarily applicable to Generation's and the Utility Registrants' Customer accounts receivables balances. This guidance did not have a significant impact on the Registrants’ consolidated financial statements.
Goodwill Impairment (Issued January 2017). Simplifies the accounting for goodwill impairment by removing Step 2 of the current test, which requires calculation of a hypothetical purchase price allocation. Under the revised guidance, goodwill impairment will be measured as the amount by which a reporting unit’s carrying value exceeds its fair value, not to exceed the carrying amount of goodwill (currently Step 1 of the two-step impairment test). Entities will continue to have the option to perform a qualitative assessment to determine if a quantitative impairment test is necessary. The standard was effective January 1, 2020 and must be applied on a prospective basis. Exelon, Generation, ComEd, PHI and DPL will apply the new guidance for their goodwill impairment assessments in 2020 and do not expect the updated guidance to have a material impact to their financial statements.
Allowance for Credit Losses on Accounts Receivables (All Registrants)

The allowance for credit losses reflects the Registrants’ best estimates of losses on the customers' accounts receivable balances based on historical experience, current information, and reasonable and supportable forecasts.

The allowance for credit losses for Generation’s retail customers is based on accounts receivable aging historical experience coupled with specific identification through a credit monitoring process, which considers current conditions and forward-looking information such as industry trends, macroeconomic factors, changes in the regulatory environment, external credit ratings, publicly available news, payment status, payment history, and the

57
COMBINED NOTES TO CONSOLIDATED FINANCIAL STATEMENTS— (Continued)
(Dollars in millions, except per share data, unless otherwise noted)

Note 12 — Significant Accounting PoliciesMergers, Acquisitions, and Dispositions

exerciseGeneration recognized a pre-tax gain of collateral calls. The allowance for credit losses for Generation wholesale customers$68 million which is developed using a credit monitoring process, similar to that used for retail customers. When a wholesale customer’s risk characteristics are no longer aligned with the pooled population, Generation uses specific identification to develop an allowance for credit losses. Adjustments to the allowance for credit losses are recordedincluded in OperatingGain on sales of assets and maintenance expense onbusinesses in Exelon’s and Generation’s Consolidated Statements of Operations and Comprehensive Income.

See Note 17 — Debt and Credit Agreements of the Exelon 2020 Form 10-K for additional information on the SolGen nonrecourse debt included as part of the transaction.
The allowance for credit lossesAgreement for the Utility Registrants’ customers is developed by applying loss rates for each Utility Registrant, based on historical loss experience, current conditionsSale of a Generation Biomass Facility (Exelon and forward-looking risk factors,Generation)
On April 28, 2021, Generation and ReGenerate Energy Holdings, LLC (“ReGenerate”) entered into a purchase agreement, under which ReGenerate agreed to purchase Generation’s interest in the outstanding receivable balance by customer risk segment. Utility Registrants' customer accounts are written off consistent with approved regulatory requirements. Adjustments toAlbany Green Energy biomass facility. As a result, in the allowance for credit losses are primarilysecond quarter of 2021, Exelon and Generation recorded toa pre-tax impairment charge of $140 million within Operating and maintenance expense on the Utility Registrants'in Exelon’s and Generation’s Consolidated Statements of Operations and Comprehensive Income and Regulatory assets on ComEd, BGE, Pepco, DPL and ACE’s Consolidated Balance Sheets. See Note 3 - Regulatory MattersIncome. Completion of the 2019 Form 10-Ktransaction was subject to the satisfaction of various customary closing conditions which were satisfied in the second quarter of 2021. The sale was completed on June 30, 2021 for additional information regarding the regulatory recoverya net purchase price of credit losses on customer accounts receivable at ComEd, BGE, Pepco, DPL and ACE.$36 million.

The Registrants have certain non-customer receivables in Other deferred debits and other assets which primarily are with governmental agencies and other high-quality counterparties with no history of default.  As such, the allowance for credit losses related to these receivables is not material.  The Registrants monitor these balances and will record an allowance if there are indicators of a decline in credit quality.

2.3. Regulatory Matters (All Registrants)
As discussed in Note 3 — Regulatory Matters of the Exelon 20192020 Form 10-K, the Registrants are involved in rate and regulatory proceedings at the FERC and their state commissions. The following discusses developments in 20202021 and updates to the 20192020 Form 10-K.
Utility Regulatory Matters (Exelon, PHI, and the Utility Registrants)
Distribution Base Rate Case Proceedings
The following tables show the completed and pending distribution base rate case proceedings in 2020.

2021.
58



COMBINED NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)
(Dollars in millions, except per share data, unless otherwise noted)

Note 23 — Regulatory Matters

Completed Distribution Base Rate Case Proceedings
Registrant/JurisdictionFiling DateServiceRequested Revenue Requirement (Decrease) IncreaseApproved Revenue Requirement (Decrease) IncreaseApproved ROEApproval DateRate Effective Date
ComEd - Illinois(a)
April 16, 2020Electric$(11)$(14)8.38 %December 9, 2020January 1, 2021
PECO - PennsylvaniaSeptember 30, 2020Natural Gas69 29 10.24 %June 22, 2021July 1, 2021
BGE - Maryland(b)
May 15, 2020 (amended September 11, 2020)Electric203 140 9.50 %December 16, 2020January 1, 2021
Natural Gas108 74 9.65 %
Pepco - District of Columbia(c)
May 30, 2019 (amended June 1, 2020)Electric136 109 9.275 %June 8, 2021July 1, 2021
Pepco - Maryland(d)
October 26, 2020 (amended March 31, 2021)Electric104 52 9.55 %June 28, 2021June 28, 2021
ACE - New Jersey(e)
December 9, 2020 (amended February 26, 2021)Electric67 41 9.60 %July 14, 2021January 1, 2022
Registrant/JurisdictionFiling DateRequested Revenue Requirement (Decrease) Increase Approved Revenue Requirement (Decrease) Increase Approved ROE Approval DateRate Effective Date
ComEd - Illinois (Electric)(a)
April 8, 2019$(6) $(17) 8.91% December 4, 2019January 1, 2020
DPL - Maryland (Electric)December 5, 2019 (amended April 23, 2020)17
 12
 9.60% July 14, 2020July 16, 2020
__________
(a)ComEd's 2021 approved revenue requirement reflects an increase of $50 million for the initial year revenue requirement for 2021 and a decrease of $64 million related to the annual reconciliation for 2019. The revenue requirement for 2021 and the revenue requirement for 2019 provide for a weighted average debt and equity return on distribution rate base of 6.28%, inclusive of an allowed ROE of 8.38%, reflecting the monthly average yields for 30-year treasury bonds plus 580 basis points.
(b)Reflects a three-year cumulative multi-year plan for 2021 through 2023. The MDPSC awarded BGE electric revenue requirement increases of $59 million, $39 million, and $42 million, before offsets, in 2021, 2022, and 2023, respectively, and natural gas revenue requirement increases of $53 million, $11 million, and $10 million, before offsets, in 2021, 2022, and 2023, respectively. BGE proposed to use certain tax benefits to fully offset the increases in 2021 and 2022 and partially offset the increase in 2023. However, the MDPSC only utilized the tax benefits to fully offset the increases in 2021 such that customer rates will remain unchanged from 2020 to 2021. The MDPSC has deferred a decision on whether to use certain tax benefits to offset the customer rate increases in 2022 and 2023 and BGE cannot predict the outcome.
(c)Reflects a cumulative multi-year plan with 18-months remaining in 2021 through 2022. The DCPSC awarded Pepco electric incremental revenue requirement increases of $42 million and $67 million, before offsets, for the remainder of 2021 and 2022, respectively. However, the DCPSC utilized the acceleration of refunds for certain tax benefits along with other rate relief to partially offset the customer rate increases by $22 million and $40 million for the remainder of 2021 and 2022, respectively.
(d)Reflects a three-year cumulative multi-year plan for April 1, 2021 through March 31, 2024. The MDPSC awarded Pepco electric incremental revenue requirement increases of $21 million, $16 million, and $15 million, before offsets, for the 12-month periods ending March 31, 2022, 2023, and 2024, respectively. Pepco proposed to utilize certain tax benefits to fully offset the increase through 2023 and partially offset customer rate increases in 2024. However, the MDPSC only utilized the acceleration of refunds for certain tax benefits to fully offset the increases such that customer rates remain unchanged through March 31, 2022. The MDPSC has deferred decision on whether to use additional tax benefits to offset customer rate increases for periods after March 31, 2022 and Pepco cannot predict the outcome.
(e)Requested and approved increases are before New Jersey sales and use tax. The order allows ACE to retain approximately $11 million of certain tax benefits which will result in a decrease to income tax expense within Exelon's, PHI's, and ACE's Consolidated Statements of Operations and Comprehensive Income in the third quarter of 2021.
59

__________
(a)Reflects an increase of $51 million for the initial revenue requirement for 2019 and a decrease of $68 million related to the annual reconciliation for 2018. The revenue requirement for 2019 and annual reconciliation for 2018 provides for a weighted average debt and equity return on distribution rate base of 6.51%, inclusive of an allowed ROE of 8.91%, reflecting the average rate on 30-year treasury notes plus 580 basis points.
Pending Distribution Base Rate Case Proceedings
Registrant/JurisdictionFiling DateRequested Revenue Requirement (Decrease) IncreaseRequested ROEExpected Approval Timing
ComEd - Illinois (Electric)(a)
April 16, 2020$(11)8.38%Fourth quarter of 2020
BGE - Maryland (Electric and Natural Gas)(b)
May 15, 2020235
10.1%Fourth quarter of 2020
Pepco - District of Columbia (Electric)(c)
May 30, 2019 (amended June 1, 2020)136
9.7%Fourth quarter of 2020
DPL - Delaware (Natural Gas)(d)
February 21, 2020 (amended March 17, 2020)9
10.3%First quarter of 2021
DPL - Delaware (Electric)(e)
March 6, 2020 (amended April 16, 2020)24
10.3%Second quarter of 2021
__________
(a)Reflects an increase of $51 million for the initial revenue requirement for 2020 and a decrease of $62 million related to the annual reconciliation for 2019. The revenue requirement for 2020 and annual reconciliation for 2019 provides for a weighted average debt and equity return on distribution rate base of 6.28%, inclusive of an allowed ROE of 8.38%, reflecting the average rate on 30-year treasury notes plus 580 basis points.
(b)Reflects a three-year cumulative multi-year plan for 2021 through 2023 and total requested revenue requirement increases in 2023 of $140 million related to electric distribution and $95 million related to natural gas distribution to recover capital investments made in late 2019 and planned capital investments from 2020 to 2023.
(c)Pepco filed the multi-year plan enhanced proposal as an alternative to address the impacts of COVID-19. Reflects a three-year cumulative multi-year plan and requested revenue requirement increases of $73 million and $63 million for 2022 and 2023, respectively, to recover capital investments made in 2018 and 2019 and planned capital investments from 2020 to 2022.
(d)The rates will go into effect on September 21, 2020, subject to refund.
(e)The rates will go into effect on October 6, 2020, subject to refund.
Transmission Formula Rates

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

Note 23 — Regulatory Matters

Pending Distribution Base Rate Case Proceedings
Registrant/JurisdictionFiling DateServiceRequested Revenue Requirement IncreaseRequested ROEExpected Approval Timing
ComEd - Illinois(a)
April 16, 2021Electric$51 7.36 %Fourth quarter of 2021
PECO - PennsylvaniaMarch 30, 2021Electric246 10.95 %Fourth quarter of 2021
DPL - Delaware(b)
March 6, 2020 (amended February 2, 2021)Electric23 10.3 %Third quarter of 2021
__________
(a)ComEd's 2022 requested revenue requirement reflects an increase of $40 million for the initial year revenue requirement for 2022 and an increase of $11 million related to the annual reconciliation for 2020. The revenue requirement for 2022 provides for a weighted average debt and equity return on distribution rate base of 5.72%, inclusive of an allowed ROE of 7.36%, reflecting the average monthly yields for 30-year treasury bonds plus 580 basis points. The reconciliation revenue requirement for 2020 provides for a weighted average debt and equity return on distribution rate base of 5.69%, inclusive of an allowed ROE of 7.29%, reflecting the average monthly yields for 30-year treasury bonds plus 580 basis points less a performance metrics penalty of 7 basis points.
(b)The rates went into effect on October 6, 2020, subject to refund.
Transmission Formula Rate (Exelon, ComEd, PECO, BGE, PHI, Pepco, DPL and ACE). ComEd’s, PECO's, BGE’s, Pepco's, DPL's and ACE'sRates
The Utility Registrants' transmission rates are each established based on a FERC-approved formula. ComEd, BGE, Pepco, DPL, and ACE are required to file an annual update to the FERC-approved formula on or before May 15, and PECO is required to file on or before May 31, with the resulting rates effective on June 1 of the same year. The annual update for ComEd BGE, DPL and ACE is based on prior year actual costs and current year projected capital additions (initial year revenue requirement). The annual update for PECO is based on prior year actual costs and current year projected capital additions, accumulated depreciation, and accumulated deferred income taxes. The annual update for BGE, Pepco, DPL, and ACE is based on prior year actual costs and current year projected capital additions, accumulated depreciation, depreciation and amortization expense, and accumulated deferred income taxes. The update for ComEd BGE, DPL and ACE also reconciles any differences between the revenue requirement in effect beginning June 1 of the prior year and actual costs incurred for that year (annual reconciliation). The update for PECO, BGE, Pepco, DPL, and PepcoACE also reconciles any differences between the actual costs and actual revenues for the calendar year (annual reconciliation).
For 2020,2021, the following total increases/(decreases) were included in ComEd’s, PECO's, BGE’s, Pepco's, DPL's and ACE'sthe Utility Registrants’ electric transmission formula rate filings:updates:
Registrant(a)
Initial Revenue Requirement Increase (Decrease)Annual Reconciliation Decrease
Total Revenue Requirement Increase (Decrease)(c)
 
Allowed Return on Rate Base(d)
Allowed ROE(e)
Registrant(a)
Initial Revenue Requirement Increase (Decrease)Annual Reconciliation Increase
Total Revenue Requirement Increase(b)
Allowed Return on Rate Base(c)
Allowed ROE(d)
ComEd$18
$(4)$14
 8.17%11.50%ComEd$33 $12 $45 8.20 %11.50 %
PECO(b)
5
(28)(23) 7.47%10.35%
PECOPECO(2)26 24 7.37 %10.35 %
BGE16
(3)4
 7.26%10.50%BGE38 27 65 7.35 %10.50 %
Pepco2
(46)(44) 7.81%10.50%Pepco(9)21 12 7.68 %10.50 %
DPL(4)(40)(44) 7.20%10.50%DPL19 33 52 7.20 %10.50 %
ACE5
(25)(20) 7.40%10.50%ACE27 24 51 7.45 %10.50 %
__________
(a)
(a)All rates are effective June 1, 2021 - May 31, 2022, subject to review by interested parties pursuant to review protocols of each Utility Registrants' tariff.
(b)In 2020, subject to review by interested parties, which is anticipated to be completed by the fourth quarter of 2020 or first quarter of 2021 for ComEd, BGE, Pepco, DPL, and ACE's transmission revenue requirement included a one-time decrease in accordance with the April 24, 2020 settlement agreement related to excess deferred income taxes which now completed has resulted in an increase to the 2021 transmission revenue requirement. In 2020, PECO's transmission revenue requirement included a one-time decrease in accordance with the December 5, 2019 settlement agreement related to refunds which now completed has resulted in an increase to the 2021 transmission revenue requirement.
(c)Represents the weighted average debt and equity return on transmission rate bases.
(d)As part of the FERC-approved settlements of ComEd’s 2007 and PECO's 2017 rate cases, the rate of return on common equity is 11.50% and 10.35%, respectively, inclusive of a 50-basis-point incentive adder for being a member of a RTO, and ACE and second quarter of 2021 for PECO.
(b)PECO posted a revised filing to the PJM website on July 17, 2020 reflecting updates to the formula rate based on the FERC order dated July 9, 2020.
(c)
The decrease in PECO's transmission revenue requirement relates to refunds from December 1, 2017, in accordance with the settlement agreement dated July 22, 2019. The change in BGE's transmission revenue requirement includes a $9 million reduction related to a FERC-approved dedicated facilities charge to recover the costs of providing transmission service to specifically designated load by BGE. ComEd, BGE, Pepco, DPL and ACE’s transmission revenue requirement include a decrease related to the April 24, 2020 settlement agreement related to excess deferred income taxes. Refer to Transmission-Related Income Tax Regulatory Assets below for additional information.
(d)Represents the weighted average debt and equity return on transmission rate bases.
(e)As part of the FERC-approved settlements of ComEd’s 2007 and PECO's 2017 transmission rate cases, the rate of return on common equity is 11.50% and 10.35%, respectively, inclusive of a 50-basis-point incentive adder for being a member of a RTO, and the common equity component of the ratio used to calculate the weighted average debt and equity return for the transmission formula rate is currently capped at 55% and 55.75%, respectively. As part of the FERC-approved settlement of the ROE complaint against BGE, Pepco, DPL and ACE, the rate of return on common equity is 10.50%, inclusive of a 50-basis-point incentive adder for being a member of a RTO.

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Note 23 — Regulatory Matters

the common equity component of the ratio used to calculate the weighted average debt and equity return for the transmission formula rate is currently capped at 55% and 55.75%, respectively. As part of the FERC-approved settlement of the ROE complaint against BGE, Pepco, DPL, and ACE, the rate of return on common equity is 10.50%, inclusive of a 50-basis-point incentive adder for being a member of a RTO.
Other State Regulatory Matters
Illinois Regulatory Matters
Energy Efficiency Formula Rate (Exelon and ComEd). ComEd filed its annual energy efficiency formula rate update with the ICC on May 21, 2020.June 1, 2021. The filing establishes the revenue requirement used to set the rates that will take effect in January 20212022 after the ICC’s review and approval. The requested revenue requirement requestedupdate is based on a reconciliation of the 20192020 actual costs plus projected 2020 and 20212022 expenditures.
Initial Revenue Requirement IncreaseAnnual Reconciliation DecreaseTotal Revenue Requirement Increase
Requested Return on Rate Base(a)
Requested ROE
$55 $(1)$54 5.72 %7.36 %
__________
Initial Revenue Requirement IncreaseAnnual Reconciliation IncreaseTotal Revenue Requirement Increase Requested Return on Rate BaseRequested ROE
$45
$3
$48
(a) 
6.28%8.38%
(a)The requested revenue requirement increase provides for a weighted average debt and equity return on the energy efficiency regulatory asset and rate base of 5.72% inclusive of an allowed ROE of 7.36%, reflecting the monthly average yields for 30-year treasury bonds plus 580 basis points. For the 2020 reconciliation year, the requested revenue requirement provides for a weighted average debt and equity return on the energy efficiency regulatory asset and rate base of 6.26% inclusive of an allowed ROE of 8.46%, which includes an upward performance adjustment that increased the ROE. The performance adjustment can either increase or decrease the ROE based upon the achievement of energy efficiency savings goals.
__________
(a)The requested revenue requirement increase provides for a weighted average debt and equity return on rate base of 6.28% inclusive of an allowed ROE of 8.38%. The ROE reflects the average rate on 30-year treasury notes plus 580 basis points. The ROE applicable to the 2019 reconciliation year is 8.96% and the return on rate base is 6.56%, which includes a performance adjustment that can either increase or decrease the ROE.
Other FederalMaryland Regulatory Matters
Transmission-Related Income Tax Regulatory AssetsMaryland Order Directing the Distribution of Energy Assistance Funds (Exelon, ComEd, BGE, PHI, Pepco, DPL and ACE)DPL).On December 13, 2016 (and as amended on March 13, 2017), BGE filed with FERC to begin recovering certain existing and future transmission-related income tax regulatory assets through its transmission formula rate. BGE’s existing regulatory assets included (1) amounts that, if BGE’s transmission formula rate provided for recovery, would have been previously amortized and (2) amounts that would be amortized and recovered prospectively. On November 16, 2017, FERCJune 15, 2021, the MDPSC issued an order rejecting BGE’s proposed revisionsauthorizing the disbursal of funds to its transmission formula rateutilities in accordance with Maryland COVID-19 relief legislation. Upon receipt, the funds are to recover these transmission-related income tax regulatory assets. In the fourth quarter of 2017, ComEd,be used to reduce or eliminate certain qualifying past-due residential customer receivables. Under this order, BGE, Pepco, and DPL received funds of $50 million, $12 million, and $8 million, respectively, in July 2021.
New Jersey Regulatory Matters
Advanced Metering Infrastructure Filing (Exelon, PHI, and ACE). On August 26, 2020, ACE fully impaired their associated transmission-related income tax regulatory assetfiled an application with the NJBPU as was required seeking approval to deploy a smart energy network in alignment with New Jersey’s Energy Master Plan and Clean Energy Act. The proposal consisted of estimated costs totaling $220 million with deployment taking place over a 3-year implementation period from approximately 2021 to 2024 that involves the installation of an integrated system of smart meters for all customers accompanied by the portionrequisite communications facilities and data management systems.
On July 14, 2021, the NJBPU approved the settlement filed by ACE and the third parties to the proceeding. The approved settlement addresses all material aspects of ACE's smart energy network deployment plan, including cost recovery of the income tax regulatory asset that would have been previously amortized.investment costs, incremental O&M expenses, and the unrecovered balance of existing infrastructure through future distribution rates.
On February 23, 2018 (as amended on July 9, 2018), ComEd, Pepco, DPL,Regulatory Assets and ACE each filed with FERC to revise their transmission formula rate mechanisms to permit recovery of transmission-related income tax regulatory assets, including those amounts that would have been previously amortized and recovered through rates had the transmission formula rate provided for such recovery.Liabilities
On September 7, 2018, FERC issued orders rejecting 1) BGE's rehearing request of FERC's November 16, 2017 order; and 2) February 23, 2018 (as amended on July 9, 2018) filing by ComEd, Pepco, DPL and ACE for similar recovery.
On November 2, 2018, BGE filed an appeal of FERC’s September 7, 2018 order to the Court of Appeals for the D.C. Circuit. On March 27, 2020, the Court of Appeals denied BGE’s November 2, 2018 appeal.
On October 1, 2018, ComEd, BGE, Pepco, DPL, and ACE submitted filings to recover only ongoing non-TCJA amortization amounts and credit TCJA transmission-related income tax regulatory liabilities to customers for the prospective period starting on October 1, 2018. On April 26, 2019, FERC issued an order accepting ComEd’s, BGE’s, Pepco’s, DPL’s, and ACE’s October 1, 2018 filings, effective October 1, 2018, subject to refund and established hearing and settlement judge procedures. On April 24, 2020, ComEd, BGE, Pepco, DPL, ACE and other parties filed a settlement agreement with FERC. The settlement agreement provides for the recovery of ongoing transmission-related income taxUtility Registrants' regulatory assets and establishesliabilities have not changed materially since December 31, 2020, unless noted below. See Note 3 — Regulatory Matters of the amountExelon 2020 Form 10-K for additional information on the specific regulatory assets and amortization period for excess deferred income taxes resulting from TCJA. The settlement resulted in a reductionliabilities.
ComEd. Regulatory assets increased $116 million primarily due to Operating revenues and an offsetting reduction to Income tax expenseincrease of $67 million in the second quarter of 2020.
While FERC has no deadline by which it must rule on the settlement, a final order from FERC is expectedElectric Distribution Formula Rate Annual Reconciliations regulatory asset and $85 million in the third quarterEnergy Efficiency Costs regulatory asset, partially offset by a decrease of 2020. Exelon cannot predict$36 million in the outcomerenewable energy regulatory asset.
PECO. Regulatory assets increased $95 million primarily due to an increase of this proceeding. If FERC ultimately rules that$81 million in the future, ongoing non-TCJA amortization amounts are not recoverable, Exelon, ComEd, BGE, PHI, Pepco, DPLDeferred Income Taxes regulatory asset and ACE would record additional charges to Income tax expense, which could be up to approximately $83$12 million $51 million, $19 million, $13 million, $5 million, $6 million and $2 million, respectively, as of June 30, 2020.

in the Vacation Accrual regulatory asset. Regulatory liabilities
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Note 23 — Regulatory Matters

Regulatory Assets and Liabilities
The Utility Registrants' regulatory assets and liabilities have not changed materially since December 31, 2019, unless noted below. See Note 3 — Regulatory Matters of the Exelon 2019 Form 10-K for additional information on the specific regulatory assets and liabilities.
ComEd. Regulatory assets increased $120by $85 million primarily due to an increase of $94 million in the Energy Efficiency Costs regulatory asset and $17 million in the Renewable Energy regulatory asset.
PECO. Regulatory assets increased $55 million primarily due to an increase of $54 million in the Deferred Income Taxes regulatory asset. Regulatory liabilities decreased $81 million primarily due to a decrease of $104$96 million in the Nuclear Decommissioning regulatory liability partially offset by a $25$13 million increasedecrease in the Electric Energy and Natural Gas Costs regulatory liability.
ACEBGE. Regulatory liabilities decreased $30$109 million primarily due to a decrease of $44$111 million in the Deferred Income Taxes regulatory liability.
Pepco. Regulatory liabilities decreased $53 million primarily due to a decrease of $46 million in the Deferred Income Taxes regulatory liability and $14 million in the Transmission Formula Rate regulatory liability partially offset by an increase of $10 million in various regulatory liabilities as a $18result of the Pepco DC multi-year plan.
DPL. Regulatory liabilities decreased $32 million increaseprimarily due to a decrease of $26 million in the Deferred Income Taxes regulatory liability and $9 million in the Transmission FERCFormula Rate regulatory liability.
ACE. Regulatory liabilities decreased $27 million primarily due to a decrease of $20 million in the Deferred Income Taxes regulatory liability and $6 million in the Transmission Formula Rate regulatory liability.
Capitalized Ratemaking Amounts Not Recognized (Exelon and the Utility Registrants)
The following table presents authorized amounts capitalized for ratemaking purposes related to earnings on shareholders’ investment that are not recognized for financial reporting purposes in Exelon's and the Utility Registrant's Consolidated Balance Sheets. These amounts will be recognized as revenues in the related Consolidated Statements of Operations and Comprehensive Income in the periods they are billable to ourthe Utility Registrants' customers.
Exelon
ComEd(a)
PECO
BGE(b)
PHI
Pepco(c)
DPL(c)
ACE
June 30, 2021$48 $1 $0 $41 $6 $3 $3 $0 
December 31, 202051 (1)0 45 7 4 3 0 
 Exelon 
ComEd(a)
 PECO 
BGE(b)
 PHI 
Pepco(c)
 
DPL(c)
 ACE
June 30, 2020$57
 $1
 $—
 $49
 $7
 $4
 $3
 $—
December 31, 201963
 3
 —
 53
 7
 4
 3
 —
__________
_________(a)Reflects ComEd's unrecognized equity returns/(losses) earned/(incurred) for ratemaking purposes on its electric distribution formula rate regulatory assets.
(a)Reflects ComEd's unrecognized equity returns earned for ratemaking purposes on its electric distribution formula rate regulatory assets.
(b)BGE's authorized amounts capitalized for ratemaking purposes primarily relate to earnings on shareholders' investment on its AMI programs.
(c)Pepco's and DPL's authorized amounts capitalized for ratemaking purposes relate to earnings on shareholders' investment on their respective AMI Programs and Energy Efficiency and Demand Response Programs. The earnings on energy efficiency are on Pepco DC and DPL DE programs only.
(b)BGE's authorized amounts capitalized for ratemaking purposes primarily relate to earnings on shareholders' investment on its AMI programs.
(c)Pepco's and DPL's authorized amounts capitalized for ratemaking purposes relate to earnings on shareholders' investment on their respective AMI Programs and Energy Efficiency and Demand Response Programs. The earnings on energy efficiency are on Pepco DC and DPL DE programs only.
Generation Regulatory Matters (Exelon and Generation)
Impacts of the February 2021 Extreme Cold Weather Event 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 outages as a result of extreme cold weather conditions. In addition, those weather conditions drove increased demand for service, dramatically increased wholesale power prices, and also increased gas prices in certain regions. In response to the high demand and significantly reduced total generation on the system, the PUCT directed ERCOT to use an administrative price cap of $9,000 per MWh during firm load shedding events.
The estimated impact to Exelon’s and Generation’s Net income for the six months ended June 30, 2021 arising from these market and weather conditions was a reduction of approximately $880 million. The estimated impact to Exelon's and Generation's Net income for the three months ended June 30, 2021 was not material. The ultimate impact to Exelon’s and Generation’s consolidated financial statements for the full year 2021 may be affected by a number of factors, including final settlement data, the impacts of customer and counterparty credit losses, any state or federal solutions to address the financial challenges caused by the event, and related litigation and contract disputes.
During February and March 2021, various parties with differing interests, including generators and retail providers, filed requests with the PUCT to void the PUCT’s orders setting prices at $9,000 per MWh during firm load shedding events. Other requests were made for the PUCT to enforce its order and reduce prices for 33 hours between February 18 and February 19 after firm load shedding ceased, and to cap ancillary services at $9,000 per MWh.On March 2, 2021, a third party filed a notice of appeal in the Court of Appeals for the Third
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Note 3 — Regulatory Matters
District of Texas challenging the validity of the PUCT’s actions. Generation intervened in that appeal and filed its initial brief on June 2, 2021. On April 19, 2021, Generation filed a declaratory action and request for judicial review of the PUCT’s orders setting prices at $9,000 per MWh in District Court of Travis County, Texas. Generation subsequently requested that the District Court of Travis County, Texas stay its proceeding pending action by the Court of Appeals in the third party proceeding. On May 17, 2021, Generation amended its petition for declaratory action and request for judicial review pending in the District Court of Travis County, Texas. Exelon and Generation cannot predict the outcome of these proceedings or the financial statement impact.
Due to these events, a number of ERCOT market participants experienced bankruptcies or defaulted on payments to ERCOT, resulting in approximately a $3.0 billion payment shortfall in collections, which is allocated to the remaining ERCOT market participants. As of June 30, 2021, Generation has recorded its portion of this obligation of approximately $17 million on a discounted basis, which is to be paid over a term of 83 years. ERCOT rules historically have limited recovery of default from market participants to $2.5 million per month market-wide. In February 2021, the PUCT gave ERCOT discretion to disregard those rules, but ERCOT has declined to exercise that discretion thus far. On March 8, 2021, a third party filed a notice of appeal in the Court of Appeals for the Third District of Texas challenging the validity of the PUCT's order to ERCOT in February 2021. Generation intervened in that appeal and filed its initial brief on July 7, 2021. On May 7, 2021, Generation filed a declaratory action and request for judicial review of the PUCT's order in the District Court of Travis County, Texas. Generation subsequently requested that the District Court of Travis County, Texas stay its proceeding pending action by the Court of Appeals in the third party proceeding. Exelon and Generation cannot predict the outcome of these proceedings or the financial statement impact. Additionally, several legislative proposals were introduced in the Texas legislature during February and March 2021 concerning the amount, timing and allocation of recovery of the $3.0 billion shortfall, as well as recovery of other costs associated with the PUCT's directive to set prices at $9,000 per MWh. Two of these proposals were enacted into law in June 2021 and establish financing mechanisms that ERCOT and certain market participants can utilize to fund amounts owed to ERCOT. Exelon and Generation are monitoring the implementation of the legislation, which could result in further adjustment to Generation's portion of the obligation.
In addition, other legislative proposals were introduced in the Texas legislature during February and March 2021 addressing cold-weather preparation for power plants and natural gas production and transportation infrastructure and the market structure for reliability services. The Texas legislature addressed these proposals by enacting a bill with a broad set of market reforms that, among other things, directed the PUCT to establish weatherization standards for electric generators within six months of enactment and gave the PUCT authority to impose administrative penalties if the new proposed standards, once adopted, are not met. On June 9, 2021, PUCT staff issued a request for comments regarding the conditions under which the PUCT should require the operation of electric generation facilities and Generation and other third parties responded on June 23, 2021. Exelon and Generation are monitoring and cannot predict the outcome of this proceeding, which could have a material adverse impact in Exelon’s and Generation’s consolidated financial statements. The legislation also directs the PUCT to evaluate whether additional ancillary services are needed for reliability in the ERCOT power region to provide adequate incentives for dispatchable generation. This evaluation is expected to be taken up by the PUCT later in 2021.
In February 2021, more than 70 local distribution companies (LDCs) and natural gas pipelines in multiple states throughout the mid-continent region, where Generation serves natural gas customers, issued operational flow orders (OFOs), curtailments or other limitations on natural gas transportation or use to manage the operational integrity of the applicable LDC or pipeline system. When in effect, gas transportation or use above these limitations is subject to significant penalties according to the applicable LDCs’ and natural gas pipelines’ tariffs. Gas transportation and supply in many states became restricted due to wells freezing and pipeline compression disruption, while demand was increasing due to the extreme cold temperatures, resulting in extremely high natural gas prices. Due to the extraordinary circumstances, many LDCs and natural gas pipelines have either voluntarily waived or have sought applicable regulatory approvals to waive the tariff penalties associated with the extreme weather event. During March 2021, three natural gas pipelines filed individual petitions with the FERC requesting approval to waive OFO penalties. Generation also filed motions in March 2021 to intervene and filed comments in support of these FERC waiver requests. On March 25, 2021, the FERC issued an order on one of the petitions approving a pipeline’s request for a limited waiver of penalties for February 15, 2021. On April 23, 2021, Generation and several other entities filed a request for rehearing and a complaint requesting that FERC expand the order to include additional days of the weather event in February, from February 16 through February 19, 2021. During April 2021, the FERC issued orders on the remaining petitions approving the requests to waive the penalties. During May 2021, an LDC filed a motion with the Kansas Corporation Commission (KCC)
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Note 3 — Regulatory Matters
requesting the KCC to grant a waiver from the tariff and allow the LDC to reduce the amounts assessed by permitting the removal of a multiplier from the penalty calculation. Exelon and Generation cannot predict the outcome of the pending FERC complaint proceeding, the KCC proceeding, or the determinations made by the LDCs and natural gas pipelines.
New Jersey Regulatory Matters
New Jersey Clean Energy Legislation. On May 23, 2018, New Jersey enacted legislation that established a ZEC program that provides compensation for nuclear plants that demonstrate to the NJBPU that they meet certain requirements, including that they make a significant contribution to air quality in the state and that their revenues are insufficient to cover their costs and risks. Under the legislation, the NJBPU will issue ZECs to qualifying nuclear power plants and the electric distribution utilities in New Jersey, including ACE, will be required to purchase those ZECs. On April 18, 2019, the NJBPU approved the award of ZECs to Salem 1 and Salem 2. Upon approval, Generation began recognizing revenue for the sale of New Jersey ZECs in the month they are generated and has recognized $17 million and $35 milliongenerated. On March 19, 2021, a three-judge panel of the Superior Court of New Jersey Appellate Division unanimously affirmed the NJBPU’s April 2019 order awarding ZECs for the threefirst eligibility period. On April 8, 2021, New Jersey Rate Counsel filed a notice asking the New Jersey Supreme Court to hear the appeal of the Superior Court’s order. On July 9, 2021, the New Jersey Supreme Court declined to hear the appeal. On October 1, 2020, PSEG and six months ended June 30, 2020 and $10 millionGeneration filed applications seeking ZECs for the threesecond eligibility period (June 2022 through May 2025). On April 27, 2021, the NJBPU approved the award of ZECs to Salem 1 and six months ended June 30, 2019.Salem 2 for the second eligibility period. On May 15, 2019,11, 2021, the New Jersey Rate Counsel appealed the NJBPU'sApril 27, 2021 decision to the Superior Court of New Jersey Superior Court.Appellate Division. Exelon and Generation cannot predict the outcome of the appeal.this proceeding. See Note 67 — Early Plant Retirements for additional information related to Salem.
New YorkEngland Regulatory Matters
New York Clean Energy Standard.Mystic Units 8 & 9 and Everett Marine Terminal Cost of Service Agreement. On AugustMarch 29, 2018, Generation notified grid operator ISO-NE of its plans to early retire Mystic Units 8 and 9 absent regulatory reforms on June 1, 2016,2022. On May 16, 2018, Generation made a filing with FERC to establish cost-of-service compensation and terms and conditions of service for Mystic Units 8 & 9 for the NYPSCperiod between June 1, 2022 - May 31, 2024. On December 20, 2018, FERC issued an order accepting the cost of service compensation, reflecting a number of adjustments to the annual fixed revenue requirement and allowing for recovery of a substantial portion of the costs associated with the adjacent Everett Marine Terminal acquired by Generation in October 2018. Those adjustments were reflected in a compliance filing made on March 1, 2019. In the December 20, 2018 order, FERC also directed a paper hearing on ROE using a new methodology. On January 22, 2019, Exelon and several other parties filed requests for rehearing of certain findings in the order. On July 15, 2021, FERC issued an order establishing the New York CES,ROE to be used in the cost of service agreement for Mystic 8 and 9 at 9.33%.
On July 17, 2020, FERC issued three orders, which together affirmed the recovery of key elements of Mystic's cost of service compensation, including recovery of costs associated with the operation of the Everett Marine Terminal. FERC directed a componentdownward adjustment to the rate base for Mystic Units 8 and 9, the effect of which iswill be partially offset by elimination of a Tier 3 ZEC program targeted at preservingcrediting mechanism for third party gas sales during the environmental attributesterm of zero-emissions nuclear-powered generating facilitiesthe cost of service agreement. In addition, several parties filed protests to a compliance filing by Generation on September 15, 2020, taking issue with how gross plant in-service was calculated, and Generation filed an answer to the protests on October 21, 2020. On December 21, 2020, FERC issued an order on rehearing of the three July 17, 2020 orders, clarifying several cost of service provisions. Several parties appealed the December 21, 2020 order to the U.S. Court of Appeals for the D.C. Circuit and that meetappeal was consolidated with appeals of orders issued December 20, 2018 and July 17, 2020 in the criteria demonstrating public necessity as determined byMystic proceeding. The briefing schedule for the NYPSCconsolidated appeal has not yet been set.
On February 25, 2021, Mystic made its filing to be Generation's FitzPatrick, Ginnacomply with the December 21, 2020 order. On April 26, 2021, FERC rejected Mystic’s language and Nine Mile Point nuclear facilities.directed another compliance filing relating to the claw back provision language, which only applies if Mystic 8 and 9 were to continue operation after the conclusion of the cost-of-service period. FERC’s April 26, 2021 order also accepted in part and rejected in part Mystic’s September 15, 2020 compliance filing. It directed a further compliance filing in 60 days consistent with the information provided in Mystic’s October 21, 2020 answer to protests, which Mystic filed on June 2, 2021.
64


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Note 23 — Regulatory Matters

On November 30, 2016 (as amended on January 13, 2017),August 25, 2020, a group of partiesNew England generators filed a Petition in New York State courtcomplaint against Generation seeking to invalidateextend the ZEC program, which argued that the NYPSC did not have authority to establish the program, that it violated state environmental law and that it violated certain technical provisionsscope of the State Administrative Procedures Act when adoptingclaw back provision in the ZEC program.cost-of-service agreement, whereby Generation would refund certain amounts recovered during the term of the cost of service if it returns to market afterwards. On January 22, 2018, the courtApril 15, 2021 FERC dismissed the environmental claims andcomplaint.
On February 16, 2021, Generation filed an unopposed motion to voluntarily dismiss an appeal filed with the majorityU.S. Court of Appeals for the plaintiffsD.C. Circuit stemming from a June 2020 complaint filed with the case but deniedFERC against ISO-NE over failures to follow its tariff in evaluating Mystic for transmission security for the motions2024 to dismiss with respect to the remaining five plaintiffs and claims, without commenting2025 Capacity Commitment Period, which was granted on the merits of the case. On October 8, 2019, the court dismissed all remaining claims. The petitioners filed a notice of appeal on November 4, 2019 and originally had until May 4, 2020 to file their brief. Due to COVID-19 related restrictions, the court extended the deadline to July 29, 2020 and, as of August 4, 2020, no brief has been received.February 18, 2021.
See Note 67 — Early Plant Retirements for additional information relatedon the impacts of Generation’s August 2020 decision to Ginna and Nine Mile Point.retire Mystic Units 8 & 9 upon expiration of the cost of service agreement.
Federal Regulatory Matters
PJM and NYISO MOPR Proceedings. PJM and NYISO capacity markets include a Minimum Offer Price Rule (MOPR).MOPR. If a resource is subjected to a MOPR, its offer is adjusted to effectively remove the revenues it receives through a state government-provided financial support program - resulting in a higher offer that may not clear the capacity market. Prior to December 19, 2019, the MOPR in PJM applied only to certain new gas-fired resources. Currently, the MOPR in NYISO applies only to certain resources in downstate New York.
For Generation’s facilities in PJM and NYISO that are currently receiving ZEC compensation, an expanded MOPR would require exclusion of ZEC compensation when bidding into future capacity auctions, resulting in an increased risk of these facilities not receiving capacity revenues in future auctions. While FERC issued a set of orders on MOPR in NYISO on February 20, 2020, it did not expand mitigation to include Generation's nuclear assets in upstate New York. However, FERC has taken action to expand the MOPR in PJM.

On December 19, 2019, FERC required PJM to broadly apply the MOPR to all new and existing resources including nuclear, renewables, demand response, energy efficiency, storage, and all resources owned by vertically-integrated utilities. This greatly expands the breadth and scope of PJM’s MOPR, which is effective as of PJM’s next capacity auction. While FERC included some limited exemptions, no exemptions were available to state-supported nuclear resources.

FERC provided no new mechanism for accommodating state-supported resources other than the existing FRR mechanism (under which an entire utility zone would be removed from PJM’s capacity auction along with sufficient resources to support the load in such zone). In response to FERC’s order, PJM submitted a compliance filing on March 18, 2020 wherein PJM proposesproposed tariff language interpreting and implementing FERC's directives, and proposesproposed a schedule for resuming capacity auctions that is contingent on the timing of FERC's action on the compliance filing. FERC has no deadline for such action, and FERC could accept, reject or direct further revisions to all or part of PJM's proposed tariff revisions and auction schedule.

On April 16, 2020, FERC issued an order largely denying most requests for rehearing of FERC's December 2019 order but granting a few clarifications that required an additional PJM compliance filing that could also delay the timing for FERC to issue its compliance order(s) which PJM submitted on June 1, 2020. PJM cannot resume activities related to its capacity auctions until FERC acts on these compliance filings.
On October 15, 2020, FERC issued an order denying requests for rehearing of its April 16, 2020 order and accepting PJM’s two compliance filings, subject to a further compliance filing to revise minor aspects of the proposed MOPR methodology. As part of that order, FERC also accepted PJM’s proposal to condense the schedule of activities leading up to the next capacity auction. A number of parties, including Exelon, have filed petitions for review of FERC's orders in this proceeding, which remain pending before the Court of Appeals for the District of Columbia Circuit.
In November 2020, PJM announced that it will conduct its next capacity auction beginning on May 21, 2020 involving reforms to PJM’s day-ahead19, 2021 and real-time reserves markets that may require further changes toending on May 25, 2021 and will post the MOPR levels pending before FERC inresults on June 2, 2021. PJM conducted the PJM MOPR Proceeding. In approving reforms to PJM’s reserves markets, FERC also directed PJM to develop a new methodology for estimating revenues that resources will receive for sales of energyauction as scheduled and, related services (referred to as the Energy and Ancillary Services Offset) and to use that new methodology in calculating a number of parameters and assumptions used in the capacity market, including MOPR levels. FERC directed PJM to submit its new Energy and Ancillary Services Offset revenue projection methodology no later than August 5, 2020. On review of this compliance filing, FERC will address how these additional reforms will impact MOPR levels and the timeline for implementing the new revenue projection methodology, including any potential impacts on auction timing.
Unlessbecause neither Illinois andnor New Jersey can implementimplemented an FRR program in their PJM zones, the MOPR will applyapplied in the next capacity auction to Generation's owned or jointly owned nuclear plants in those states receiving a benefit under the Illinois ZES, or the New Jersey ZEC program, as applicable, increasing the risk that those units may not clearprogram. The MOPR prevented Quad Cities from clearing in the capacity market.auction.

At the direction of the PJM Board of Managers, PJM and its stakeholders are considering MOPR reforms to ensure that the capacity market rules respect and accommodate state resource preferences such as the ZEC
63
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COMBINED NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)
(Dollars in millions, except per share data, unless otherwise noted)

Note 23 — Regulatory Matters

Exelon is currently working withprograms which PJM and other stakeholders to pursue the FRR option prior to the next capacity auction in PJM. If Illinois implements the FRR option, Generation’s Illinois nuclear plants could be removed from PJM’s capacity auction and instead supply capacity and be compensated under the FRR program, which has the potential to mitigate the current economic distress being experienced by Generation's nuclear plants in Illinois, as discussed in Note 6 - Early Plant Retirements. Implementing the FRR program in Illinois will require both legislative and regulatory changes. Legislation may be introduced in New Jersey as well.filed at FERC on July 30, 2021. Exelon cannot predict whether or when such legislative and regulatory changes can be implemented.
On February 20, 2020, FERC issued an order rejecting requests to expand NYISO’s version of the MOPR (referred to as buyer-side mitigation rules) beyond its current limited applicability to certain resources in downstate. However, on October 14, 2020, two natural gas-fired generators in New York filed a complaint at FERC seeking to expand the MOPR in NYISO to apply to all resources, new and existing, across the entire NYISO market. Exelon is strenuously opposing expansion of FERC’s MOPR policies in the NYISO market. While it is too early in the proceeding to predict its outcome and there are significant differences between the NYISO and PJM markets that would justify a different result, if FERC follows its MOPR precedent in PJM and applies the MOPR in NYISO broadly as requested in the complaint, Generation’s facilities in NYISO that are receiving ZEC compensation may be at increased risk of not clearing the capacity auction.
If Generation’s state-supported nuclear plants in PJM or NYISO are subjected to the MOPR or equivalent without compensation under an FRR or similar program, it could have a material adverse impact on Exelon's and Generation's financial statements, which Exelon and Generation cannot reasonably estimate at this time.
Operating License Renewals
Conowingo Hydroelectric Project. On August 29, 2012, Generation submitted a hydroelectric license application to FERC for a new license for the Conowingo Hydroelectric Project (Conowingo). In connection with Generation’s efforts to obtain a water quality certification pursuant to Section 401 of the Clean Water Act (401 Certification) from MDE for Conowingo, Generation hashad been working with MDE and other stakeholders to resolve water quality licensing issues, including: (1) water quality, (2) fish habitat, and (3) sediment.
On April 27, 2018, MDE issued its 401 Certification for Conowingo. On October 29, 2019, Generation and MDE filed with FERC a Joint Offer of Settlement (Offer of Settlement) that would resolve all outstanding issues relating to the 401 Certification. Pursuant to the Offer of Settlement, the parties submitted Proposed License Articles to FERC to be incorporated by FERC into the new license in accordance with FERC’s discretionary authority under the Federal Power Act. Among the Proposed License Articles are modifications to river flows to improve aquatic habitat, eel passage improvements and initiatives to support rare, threatened and endangered wildlife. If
On March 19, 2021, FERC approves the Offer of Settlement and incorporatesissued a new 50-year license for Conowingo, effective March 1, 2021. FERC adopted the Proposed License Articles into the new license without modification, then MDE would waive its rightsonly making modifications it deemed necessary to issue a 401 Certification and Generation would agree, pursuantallow FERC to a separate agreementenforce the Proposed License Articles. Consistent with MDE (MDE Settlement), to implement additional environmental protection, mitigation and enhancement measures over the anticipated 50-year term of the new license. These measures address mussel restoration and other ecological and water quality matters, among other commitments. Exelon’s commitments under the various provisions of the Offer of Settlement, andFERC found that MDE Settlement are not effective unless and untilwaived its 401 Certification. On April 19, 2021, a few environmental groups filed with FERC approvesa petition for rehearing requesting that FERC reconsider the Offerissuance of Settlement and issues the new Conowingo license, withwhich was denied by operation of law on May 20, 2021. On June 17, 2021, the Proposed License Articles.petitioners appealed FERC’s ruling to the United States Court of Appeals. On July 15, 2021, FERC issued an order addressing the arguments raised on rehearing, affirming the determinations of its March 19, 2021 order. Generation cannot currently predict when FERC will issue the new license.outcome of this proceeding.
Peach Bottom Units 2 and 3. On July 10, 2018, Generation submitted a second 20-year license renewal application with the NRC for Peach Bottom Units 2 and 3, which was approved on March 6, 2020. Peach Bottom Units 2 and 3 are now licensed to operate through 2053 and 2054, respectively.
3.4. Revenue from Contracts with Customers (All Registrants)
The Registrants recognize revenue from contracts with customers to depict the transfer of goods or services to customers at an amount that the entities expect to be entitled to in exchange for those goods or services. Generation’s primary sources of revenue include competitive sales of power, natural gas, and other energy-related products and services. The Utility Registrants’ primary sources of revenue include regulated electric and gas tariff sales, distribution, and transmission services.
See Note 4 — Revenue from Contracts with Customers of the Exelon 20192020 Form 10-K for additional information regarding the primary sources of revenue for the Registrants.
Contract Balances (All Registrants)
Contract Assets and Liabilities
Generation records contract assets for the revenue recognized on the construction and installation of energy efficiency assets and new power generating facilities before Generation has an unconditional right to bill for and
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COMBINED NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)
(Dollars in millions, except per share data, unless otherwise noted)

Note 4 — Revenue from Contracts with Customers
receive the consideration from the customer. These contract assets are subsequently reclassified to receivables when the right to payment becomes unconditional. Generation records contract assets and contract receivables within Other current assets and Customer accounts receivable, net, respectively, within Exelon’s and Generation’s Consolidated Balance Sheets.

The following table provides a rollforward of the contract assets reflected in Exelon's and Generation's Consolidated Balance Sheets for the three and six months ended June 30, 2021 and 2020. The Utility Registrants do not have any contract assets.
ExelonGeneration
Balance as of December 31, 2020$144 $144 
Amounts reclassified to receivables(16)(16)
Revenues recognized13 13 
Amounts previously held-for-sale12 12 
Balance as of March 31, 2021153 153 
Amounts reclassified to receivables(12)(12)
Revenues recognized9 9 
Balance as of June 30, 2021$150 $150 
ExelonGeneration
Balance as of December 31, 2019$174 $174 
Amounts reclassified to receivables(19)(19)
Revenues recognized17 17 
Balance as of March 31, 2020172 172 
Amounts reclassified to receivables(26)(26)
Revenues recognized13 13 
Balance as of June 30, 2020$159 $159 
Contract Liabilities
The Registrants record contract liabilities when consideration is received or due prior to the satisfaction of the performance obligations. The Registrants record contract liabilities within Other current liabilities and Other noncurrent liabilities within the Registrants' Consolidated Balance Sheets.
For Generation, these contract liabilities primarily relate to upfront consideration received or due for equipment service plans, and the Illinois ZEC program that introduces a cap on the total consideration to be received by Generation.
For PHI, Pepco, DPL, and ACE these contract liabilities primarily relate to upfront consideration received in the third quarter of 2020 for a collaborative arrangement with an unrelated owner and manager of communication infrastructure. The revenue attributable to this arrangement will be recognized as operating revenue over the 35 years under the collaborative arrangement.
The following table provides a rollforward of the contract liabilities reflected in Exelon's, Generation's, PHI's, Pepco's, DPL's, and ACE's Consolidated Balance Sheets for the three and six months ended June 30, 2021 and 2020. As of June 30, 2021 and December 31, 2020, ComEd's, PECO's, and BGE's contract liabilities were immaterial.
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COMBINED NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)
(Dollars in millions, except per share data, unless otherwise noted)

Note 34 — Revenue from Contracts with Customers

Generation records contract liabilities when consideration is received or due prior to the satisfaction of the performance obligations. These contract liabilities primarily relate to upfront consideration received or due for equipment service plans, solar panel leases and the Illinois ZEC program that introduces a cap on the total consideration to be received by Generation. Generation records contract liabilities within Other current liabilities and Other noncurrent liabilities within Exelon's and Generation's Consolidated Balance Sheets.
ExelonGenerationPHIPepcoDPLACE
Balance as of December 31, 2020$151 $84 $118 $94 $12 $12 
Consideration received or due20 31 0 0 0 0 
Revenues recognized(27)(64)(2)(2)0 0 
Amounts previously held-for-sale3 3 0 0 0 0 
Balance as of March 31, 2021147 54 116 92 12 12 
Consideration received or due17 39 0 0 0 0 
Revenues recognized(32)(68)(3)(1)(1)(1)
Balance as of June 30, 2021$132 $25 $113 $91 $11 $11 
ExelonGenerationPHIPepcoDPLACE
Balance as of December 31, 2019$33 $71 $0 $0 $0 $0 
Consideration received or due20 55 0 0 0 0 
Revenues recognized(24)(70)0 0 0 0 
Balance as of March 31, 202029 56 0 0 0 0 
Consideration received or due13 34 0 0 0 0 
Revenues recognized(22)(63)0 0 0 0 
Balance as of June 30, 2020$20 $27 $0 $0 $0 $0 
The following table provides a rollforward of the contract assets and liabilities reflectedreflects revenues recognized in Exelon's and Generation's Consolidated Balance Sheets for the three and six months ended June 30, 2021 and 2020, which were included in contract liabilities at December 31, 2020 and 2019.2019, respectively:
  Contract Assets Contract Liabilities
  Exelon Generation Exelon Generation
Balance as of December 31, 2019 $174
 $174
 $33
 $71
Consideration received or due (19) (19) 20
 55
Revenues recognized (a)
 17
 17
 (24) (70)
Balance at March 31, 2020 $172
 $172
 $29
 $56
Consideration received or due (26) (26) 13
 34
Revenues recognized (a)
 13
 13
 (22) (63)
Balance at June 30, 2020 $159
 $159
 $20
 $27
    ��    
Balance as of December 31, 2018 $187
 $187
 $27
 $42
Consideration received or due (26) (26) 21
 63
Revenues recognized (b)
 26
 26
 (23) (66)
Balance at March 31, 2019 $187
 $187
 $25
 $39
Consideration received or due (18) (18) 17
 52
Revenues recognized (b)
 27
 27
 (21) (65)
Balance at June 30, 2019 $196
 $196
 $21
 $26

__________
(a)Revenues recognized in the three and six months ended June 30, 2020, which were included in contract liabilities at December 31, 2019, were approximately $14 million and $23 million, respectively, for Exelon and $42 million and $61 million, respectively, for Generation.
(b)Revenues recognized in the three and six months ended June 30, 2019, which were included in contract liabilities at December 31, 2018, were approximately $9 million and $14 million, respectively, for Exelon and $24 million and $28 million, respectively, for Generation.
The Utility Registrants do not have any contract assets. The Utility Registrants also record contract liabilities when consideration is received prior to the satisfaction of the performance obligations. As of June 30, 2020 and December 31, 2019, the Utility Registrants' contract liabilities were not material.
Three Months Ended June 30,Six Months Ended June 30,
2021202020212020
Exelon$17 $14 $34 $23 
Generation41 42 7961
PHI3 0 50 
Pepco1 0 30 
DPL1 0 10 
ACE1 0 10 
Transaction Price Allocated to Remaining Performance Obligations (All Registrants)
The following table shows the amounts of future revenues expected to be recorded in each year for performance obligations that are unsatisfied or partially unsatisfied as of June 30, 2020.2021. This disclosure only includes contracts for which the total consideration is fixed and determinable at contract inception. The average contract term varies by customer type and commodity but ranges from one month to several years.
This disclosure excludes Generation's power and gas sales contracts as they contain variable volumes and/or variable pricing. This disclosure also excludes the Utility Registrants' gas and electric tariff sales contracts and transmission revenue contracts as they generally have an original expected duration of one year or less and, therefore, do not contain any future, unsatisfied performance obligations to be included in this disclosure.

20212022202320242025 and thereafterTotal
Exelon$149 $100 $46 $31 $180 $506 
Generation223 146 54 29 94 546 
PHI5 8 8 6 86 113 
Pepco3 6 6 5 71 91 
DPL1 1 1 0 8 11 
ACE1 1 1 1 7 11 
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COMBINED NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)
(Dollars in millions, except per share data, unless otherwise noted)

Note 34 — Revenue from Contracts with Customers

 2020 2021 2022 2023 2024 and thereafter Total
Exelon$169
 $194
 $73
 $43
 $189
 $668
Generation231
 282
 105
 48
 189
 855

Revenue Disaggregation (All Registrants)
The Registrants disaggregate revenue recognized from contracts with customers into categories that depict how the nature, amount, timing, and uncertainty of revenue and cash flows are affected by economic factors. See Note 45 — Segment Information for the presentation of the Registrant's revenue disaggregation.

4.
5. Segment Information (All Registrants)
Operating segments for each of the Registrants are determined based on information used by the CODM in deciding how to evaluate performance and allocate resources at each of the Registrants.
Exelon has 11 reportable segments, which include Generation's 5 reportable segments consisting of the Mid-Atlantic, Midwest, New York, ERCOT, and all other power regions referred to collectively as “Other Power Regions” and ComEd, PECO, BGE, and PHI's 3 reportable segments consisting of Pepco, DPL, and ACE. ComEd, PECO, BGE, Pepco, DPL, and ACE each represent a single reportable segment, and as such, no separate segment information is provided for these Registrants. Exelon, ComEd, PECO, BGE, Pepco, DPL, and ACE's CODMs evaluate the performance of and allocate resources to ComEd, PECO, BGE, Pepco, DPL, and ACE based on net income.
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 to these same geographic regions. Descriptions of each of Generation’s 5 reportable segments are as follows:
•
•Mid-Atlantic represents operations in the eastern half of PJM, which includes New Jersey, Maryland, Virginia, West Virginia, Delaware, the District of Columbia, and parts of Pennsylvania and North Carolina.
•Midwest represents operations in the western half of PJM and the United States footprint of MISO, excluding MISO’s Southern Region.
•New York represents operations within NYISO.
•ERCOT represents operations within Electric Reliability Council of Texas.
• represents operations in the eastern half of PJM, which includes New Jersey, Maryland, Virginia, West Virginia, Delaware, the District of Columbia and parts of Pennsylvania and North Carolina.
•
Midwest represents operations in the western half of PJM and the United States footprint of MISO, excluding MISO’s Southern Region.
•
New York represents operations within NYISO.
•
ERCOT represents operations within Electric Reliability Council of Texas.
Other Power Regions:
•
•New England represents the operations within ISO-NE.
•South represents operations in the FRCC, MISO’s Southern Region, and the remaining portions of the SERC not included within MISO or PJM.
•West represents operations in the WECC, which includes California ISO.
• represents the operations within ISO-NE.
•
South represents operations in the FRCC, MISO’s Southern Region, and the remaining portions of the SERC not included within MISO or PJM.
•
West represents operations in the WECC, which includes California ISO.
•
Canada represents operations across the entire country of Canada and includes AESO, OIESO, and the Canadian portion of MISO.
The CODMs for Exelon and Generation evaluate the performance of Generation’s electric business activities and allocate resources based on RNF. Generation believes that RNF is a useful measurement of operational performance. RNF is not a presentation defined under GAAP and may not be comparable to other companies’ presentations or deemed more useful than the GAAP information provided elsewhere in this report. Generation’s 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, and ancillary services. Fuel expense includes the fuel costs for Generation’s owned generation and fuel costs associated with tolling agreements. The results of Generation's other business activities are not regularly reviewed by the

66
Table of Contents
COMBINED NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)
(Dollars in millions, except per share data, unless otherwise noted)

Note 4 — Segment Information

CODM and are therefore not classified as operating segments or included in the regional reportable segment amounts. These activities include natural gas, as well as other miscellaneous business activities that are not significant to Generation's overall operating revenues or results of operations. Further,
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COMBINED NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)
(Dollars in millions, except per share data, unless otherwise noted)

Note 5 — Segment Information
Generation’s unrealized mark-to-market gains and losses on economic hedging activities and its amortization of certain intangible assets and liabilities relating to commodity contracts recorded at fair value from mergers and acquisitions are also excluded from the regional reportable segment amounts. Exelon and Generation do not use a measure of total assets in making decisions regarding allocating resources to or assessing the performance of these reportable segments.
An analysis and reconciliation of the Registrants’ reportable segment information to the respective information in the consolidated financial statements for the three and six months ended June 30, 20202021 and 20192020 is as follows:

Three Months Ended June 30, 20202021 and 20192020
GenerationComEdPECOBGEPHI
Other(a)
Intersegment
Eliminations		Exelon
Operating revenues(b):
2021
Competitive businesses electric revenues$3,747 $0 $0 $0 $0 $0 $(250)$3,497 
Competitive businesses natural gas revenues507 0 0 0 0 0 0 507 
Competitive businesses other revenues(101)0 0 0 0 0 (3)(104)
Rate-regulated electric revenues0 1,517 610 558 1,113 0 (11)3,787 
Rate-regulated natural gas revenues0 0 83 124 24 0 (3)228 
Shared service and other revenues0 0 0 — 3 524 (527)0 
Total operating revenues$4,153 $1,517 $693 $682 $1,140 $524 $(794)$7,915 
2020
Competitive businesses electric revenues$3,414 $0 $0 $0 $0 $0 $(268)$3,146 
Competitive businesses natural gas revenues353 0 0 0 0 0 0 353 
Competitive businesses other revenues113 0 0 0 0 0 (1)112 
Rate-regulated electric revenues0 1,417 586 504 983 0 (15)3,475 
Rate-regulated natural gas revenues0 0 95 112 30 0 (1)236 
Shared service and other revenues0 0 0 0 3 472 (475)0 
Total operating revenues$3,880 $1,417 $681 $616 $1,016 $472 $(760)$7,322 
GenerationComEdPECOBGEPHI
Other(a)
Intersegment
Eliminations		Exelon
Intersegment revenues(c):
2021$254 $5 $2 $7 $4 $522 $(794)$0 
2020271 11 2 4 3 470 (760)1 
Depreciation and amortization:
70
 Generation ComEd PECO BGE PHI 
Other(a)
 Intersegment
Eliminations		 Exelon
Operating revenues(b):
2020               
Competitive businesses electric revenues$3,414
 $—
 $—
 $—
 $—
 $—
 $(268) $3,146
Competitive businesses natural gas revenues353
 —
 —
 —
 —
 —
 —
 353
Competitive businesses other revenues113
 —
 —
 —
 —
 —
 (1) 112
Rate-regulated electric revenues—
 1,417
 586
 504
 983
 —
 (15) 3,475
Rate-regulated natural gas revenues—
 —
 95
 112
 30
 —
 (1) 236
Shared service and other revenues—
 —
 —
 —
 3
 472
 (475) —
Total operating revenues$3,880
 $1,417
 $681
 $616
 $1,016
 $472
 $(760) $7,322
2019               
Competitive businesses electric revenues$3,718
 $—
 $—
 $—
 $—
 $—
 $(250) $3,468
Competitive businesses natural gas revenues333
 —
 —
 —
 —
 —
 —
 333
Competitive businesses other revenues159
 —
 —
 —
 —
 —
 (1) 158
Rate-regulated electric revenues—
 1,351
 566
 540
 1,063
 —
 (8) 3,512
Rate-regulated natural gas revenues—
 —
 89
 109
 24
 —
 (4) 218
Shared service and other revenues—
 —
 —
 —
 4
 484
 (488) —
Total operating revenues$4,210
 $1,351
 $655
 $649
 $1,091
 $484
 $(751) $7,689
Intersegment revenues(c):
               
2020$271
 $11
 $2
 $4
 $3
 $470
 $(760) $1
2019252
 5
 2
 6
 3
 482
 (750) —
Depreciation and amortization:               
2020$300
 $274
 $88
 $129
 $191
 $19
 $—
 $1,001
2019409
 257
 83
 117
 188
 25
 —
 1,079


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COMBINED NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)
(Dollars in millions, except per share data, unless otherwise noted)

Note 45 — Segment Information
2021$930 $296 $87 $141 $194 $18 $0 $1,666 
2020300 274 88 129 191 19 0 1,001 
Operating expenses:
2021$4,469 $1,196 $552 $620 $955 $537 $(768)$7,561 
20203,547 1,345 618 573 956 478 (748)6,769 
Interest expense, net:
2021$76 $98 $42 $34 $67 $79 $0 $396 
202087 98 36 32 67 107 0 427 
Income (loss) before income taxes:
2021$124 $238 $106 $37 $138 $(92)$0 $551 
2020860 (15)32 17 7 (108)1 794 
Income Taxes:
2021$110 $46 $2 $(8)$(3)$(73)$0 $74 
2020329 46 (7)(22)(87)(40)0 219 
Net income (loss):
2021$13 $192 $104 $45 $141 $(19)$0 $476 
2020529 (61)39 39 94 (67)1 574 
Capital Expenditures:
2021$337 $549 $282 $284 $433 $15 $0 $1,900 
2020372 523 253 265 310 34 0 1,757 
(a)Other primarily includes Exelon’s corporate operations, shared service entities, and other financing and investment activities.
(b)Includes gross utility tax receipts from customers. The offsetting remittance of utility taxes to the governing bodies is recorded in expenses in the Registrants’ Consolidated Statements of Operations and Comprehensive Income. See Note 18— Supplemental Financial Information for additional information on total utility taxes.
(c)Intersegment revenues exclude sales to unconsolidated affiliates. The intersegment profit associated with Generation’s sale of certain products and services by and between Exelon’s segments is not eliminated in consolidation due to the recognition of intersegment profit in accordance with regulatory accounting guidance. For Exelon, these amounts are included in Operating revenues in the Consolidated Statements of Operations and Comprehensive Income. See Note 19— Related Party Transactions for additional information on intersegment revenues.

71
 Generation ComEd PECO BGE PHI 
Other(a)
 Intersegment
Eliminations		 Exelon
Operating expenses:               
2020$3,547
 $1,345
 $618
 $573
 $956
 $478
 $(748) $6,769
20194,096
 1,040
 510
 569
 926
 484
 (744) 6,881
Interest expense, net:               
2020$87
 $98
 $36
 $32
 $67
 $107
 $—
 $427
2019116
 89
 33
 29
 67
 75
 —
 409
Income (loss) before income taxes:               
2020$860
 $(15) $32
 $17
 $7
 $(108) $1
 $794
2019202
 232
 115
 56
 112
 (73) —
 644
Income Taxes:               
2020$329
 $46
 $(7) $(22) $(87) $(40) $—
 $219
201978
 46
 13
 11
 6
 (10) —
 144
Net income (loss):               
2020$529
 $(61) $39
 $39
 $94
 $(67) $1
 $574
2019118
 186
 102
 45
 106
 (63) —
 494
Capital Expenditures               
2020$372
 $523
 $253
 $265
 $310
 $34
 $—
 $1,757
2019383
 459
 225
 284
 340
 11
 —
 1,702

__________
(a)Other primarily includes Exelon’s corporate operations, shared service entities and other financing and investment activities.
(b)Includes gross utility tax receipts from customers. The offsetting remittance of utility taxes to the governing bodies is recorded in expenses in the Registrants’ Consolidated Statements of Operations and Comprehensive Income. See Note 17 — Supplemental Financial Information for additional information on total utility taxes.
(c)Intersegment revenues exclude sales to unconsolidated affiliates. The intersegment profit associated with Generation’s sale of certain products and services by and between Exelon’s segments is not eliminated in consolidation due to the recognition of intersegment profit in accordance with regulatory accounting guidance. For Exelon, these amounts are included in Operating revenues in the Consolidated Statements of Operations and Comprehensive Income. See Note 18 — Related Party Transactions for additional information on intersegment revenues.



68
COMBINED NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)
(Dollars in millions, except per share data, unless otherwise noted)

Note 45 — Segment Information

PHI:
 Pepco DPL ACE 
Other(a)
 Intersegment
Eliminations		 PHI
Operating revenues(b):
           
2020           
Rate-regulated electric revenues$494
 $237
 $256
 $—
 $(4) $983
Rate-regulated natural gas revenues—
 30
 —
 —
 —
 30
Shared service and other revenues—
 —
 —
 97
 (94) 3
Total operating revenues$494
 $267
 $256
 $97
 $(98) $1,016
2019           
Rate-regulated electric revenues$531
 $261
 $274
 $—
 $(3) $1,063
Rate-regulated natural gas revenues—
 24
 —
 —
 —
 24
Shared service and other revenues—
 2
 —
 97
 (95) 4
Total operating revenues$531
 $287
 $274
 $97
 $(98) $1,091
Intersegment revenues(c):
           
2020$1
 $2
 $1
 $97
 $(98) $3
20191
 2
 1
 98
 (99) 3
Depreciation and amortization:           
2020$92
 $47
 $44
 $8
 $—
 $191
201993
 45
 40
 10
 —
 188
Operating expenses:           
2020$436
 $263
 $258
 $97
 $(98) $956
2019438
 243
 246
 100
 (101) 926
Interest expense, net:           
2020$34
 $15
 $15
 $3
 $—
 $67
201934
 15
 15
 3
 —
 67
Income (loss) before income taxes:           
2020$33
 $(9) $(15) $(2) $—
 $7
2019(d)
66
 34
 14
 (2) —
 112
Income Taxes:           
2020$(24) $(28) $(33) $(2) $—
 $(87)
20192
 4
 —
 —
 —
 6
Net income (loss):           
2020$57
 $19
 $18
 $—
 $—
 $94
201964
 30
 14
 (2) —
 106
Capital Expenditures           
2020$144
 $89
 $77
 $—
 $—
 $310
2019154
 82
 99
 5
 —
 340
__________
(a)Other primarily includes PHI’s corporate operations, shared service entities and other financing and investment activities.
(b)Includes gross utility tax receipts from customers. The offsetting remittance of utility taxes to the governing bodies is recorded in expenses in the Registrants’ Consolidated Statements of Operations and Comprehensive Income. See Note 17 — Supplemental Financial Information for additional information on total utility taxes.
(c)Includes intersegment revenues with ComEd, BGE and PECO, which are eliminated at Exelon.
(d)
The Income (loss) before income taxes amounts in Other and Intersegment Eliminations have been adjusted by an offsetting $108 million for consistency with the Exelon consolidating disclosure above.

PepcoDPLACE
Other(a)
Intersegment
Eliminations		PHI
Operating revenues(b):
2021
Rate-regulated electric revenues$523 $274 $319 $0 $(3)$1,113 
Rate-regulated natural gas revenues0 24 0 0 0 24 
Shared service and other revenues0 0 0 95 (92)3 
Total operating revenues$523 $298 $319 $95 $(95)$1,140 
2020
Rate-regulated electric revenues$494 $237 $256 $0 $(4)$983 
Rate-regulated natural gas revenues0 30 0 0 0 30 
Shared service and other revenues0 0 0 97 (94)3 
Total operating revenues$494 $267 $256 $97 $(98)$1,016 
Intersegment revenues(c):
2021$1 $2 $1 $95 $(95)$4 
20201 2 1 97 (98)3 
Depreciation and amortization:
2021$96 $51 $40 $7 $0 $194 
202092 47 44 8 0 191 
Operating expenses:
2021$429 $255 $269 $97 $(95)$955 
2020436 263 258 97 (98)956 
Interest expense, net:
2021$35 $16 $14 $2 $0 $67 
202034 15 15 3 0 67 
Income (loss) before income taxes:
2021$72 $31 $36 $(1)$0 $138 
202033 (9)(15)(2)0 7 
Income Taxes:
2021$(3)$1 $(1)$0 $0 $(3)
2020(24)(28)(33)(2)0 (87)
Net income (loss):
2021$75 $30 $37 $(1)$0 $141 
202057 19 18 0 0 94 
Capital Expenditures:
2021$219 $99 $116 $(1)$0 $433 
2020144 89 77 0 0 310 

69
Table of Contents__________
COMBINED NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (a)— (Continued)Other primarily includes PHI’s corporate operations, shared service entities, and other financing and investment activities.
(Dollars(b)Includes gross utility tax receipts from customers. The offsetting remittance of utility taxes to the governing bodies is recorded in millions, except per share data, unless otherwise noted)expenses in the Registrants’ Consolidated Statements of Operations and Comprehensive Income. See Note 18— Supplemental Financial Information for additional information on total utility taxes.

(c)Includes intersegment revenues with ComEd, BGE, and PECO, which are eliminated at Exelon.
Note 4 — Segment Information



The following tables disaggregate the Registrants' revenue recognized from contracts with customers into categories that depict how the nature, amount, timing, and uncertainty of revenue and cash flows are affected by economic factors. For Generation, the disaggregation of revenues reflects Generation’s two primary products of power sales and natural gas sales, with further disaggregation of power sales provided by geographic region. For the Utility Registrants, the disaggregation of revenues reflects the two primary utility services of rate-regulated
72



COMBINED NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)
(Dollars in millions, except per share data, unless otherwise noted)

Note 5 — Segment Information
electric sales and rate-regulated natural gas sales (where applicable), with further disaggregation of these tariff sales provided by major customer groups. Exelon’s disaggregated revenues are consistent with Generation and the Utility Registrants, but exclude any intercompany revenues.
Competitive Business Revenues (Generation):
Three Months Ended June 30, 2021
Revenues from external customers(a)
Intersegment
Revenues		Total
Revenues
Contracts with customers
Other(b)
Total
Mid-Atlantic$1,062 $24 $1,086 $5 $1,091 
Midwest975 (13)962 0 962 
New York376 5 381 0 381 
ERCOT179 92 271 4 275 
Other Power Regions921 126 1,047 (9)1,038 
Total Competitive Businesses Electric Revenues3,513 234 3,747 0 3,747 
Competitive Businesses Natural Gas Revenues253 254 507 0 507 
Competitive Businesses Other Revenues(c)
107 (208)(101)0 (101)
Total Generation Consolidated Operating Revenues$3,873 $280 $4,153 $0 $4,153 
Three Months Ended June 30, 2020Three Months Ended June 30, 2020
Revenues from external customers(a)
 
Intersegment
Revenues
 
Total
Revenues
Revenues from external customers(a)
Intersegment
revenues		Total
Revenues
Contracts with customers 
Other(b)
 Total Contracts with customers
Other(b)
Total
Mid-Atlantic$1,100
 $(35) $1,065
 $9
 $1,074
Mid-Atlantic$1,100 $(35)$1,065 $9 $1,074 
Midwest855
 107
 962
 —
 962
Midwest855 107 962 0 962 
New York336
 5
 341
 (1) 340
New York336 5 341 (1)340 
ERCOT175
 52
 227
 7
 234
ERCOT175 52 227 7 234 
Other Power Regions776
 43
 819
 (15) 804
Other Power Regions776 43 819 (15)804 
Total Competitive Businesses Electric Revenues3,242
 172
 3,414
 —
 3,414
Total Competitive Businesses Electric Revenues3,242 172 3,414 0 3,414 
Competitive Businesses Natural Gas Revenues209
 144
 353
 —
 353
Competitive Businesses Natural Gas Revenues209 144 353 0 353 
Competitive Businesses Other Revenues(c)
86
 27
 113
 —
 113
Competitive Businesses Other Revenues(c)
86 27 113 0 113 
Total Generation Consolidated Operating Revenues$3,537
 $343
 $3,880
 $—
 $3,880
Total Generation Consolidated Operating Revenues$3,537 $343 $3,880 $0 $3,880 
__________
(a)Includes all wholesale and retail electric sales to third parties and affiliated sales to the Utility Registrants.
(b)Includes revenues from derivatives and leases.
(c)Other represents activities not allocated to a region. See text above for a description of included activities. Includes unrealized mark-to-market losses of $239 million and gains of $21 million in 2021 and 2020, respectively, and elimination of intersegment revenues.

 Three Months Ended June 30, 2019
 
Revenues from external customers(a)
 Intersegment
revenues		 Total
Revenues
 Contracts with customers 
Other(b)
 Total  
Mid-Atlantic$1,162
 $21
 $1,183
 $6
 $1,189
Midwest974
 68
 1,042
 (8) 1,034
New York373
 17
 390
 —
 390
ERCOT178
 47
 225
 4
 229
Other Power Regions814
 64
 878
 (17) 861
Total Competitive Businesses Electric Revenues3,501
 217
 3,718
 (15) 3,703
Competitive Businesses Natural Gas Revenues177
 156
 333
 15
 348
Competitive Businesses Other Revenues(c)
108
 51
 159
 —
 159
Total Generation Consolidated Operating Revenues$3,786
 $424
 $4,210
 $—
 $4,210
73
__________
(a)Includes all wholesale and retail electric sales to third parties and affiliated sales to the Utility Registrants.
(b)Includes revenues from derivatives and leases.
(c)Other represents activities not allocated to a region. See text above for a description of included activities. Includes unrealized mark-to-market gains of $21 million and $38 million in 2020 and 2019, respectively, and elimination of intersegment revenues.


70
COMBINED NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)
(Dollars in millions, except per share data, unless otherwise noted)

Note 45 — Segment Information

Revenues net of purchased power and fuel expense (Generation):
Three Months Ended June 30, 2020 Three Months Ended June 30, 2019Three Months Ended June 30, 2021Three Months Ended June 30, 2020
RNF
from external
customers(a)
 
Intersegment
RNF
 Total RNF 
RNF
from external
customers(a)
 
Intersegment
RNF
 Total RNF
RNF
from external
customers(a)
Intersegment
RNF		Total RNF
RNF
from external
customers(a)
Intersegment
RNF		Total RNF
Mid-Atlantic$516
 $9
 $525
 $644
 $8
 $652
Mid-Atlantic$567 $5 $572 $516 $9 $525 
Midwest702
 1
 703
 738
 (8) 730
Midwest658 0 658 702 1 703 
New York243
 3
 246
 250
 3
 253
New York289 3 292 243 3 246 
ERCOT92
 5
 97
 80
 (1) 79
ERCOT80 3 83 92 5 97 
Other Power Regions181
 (24) 157
 154
 (20) 134
Other Power Regions157 (21)136 181 (24)157 
Total Revenues net of purchased power and fuel expense for Reportable Segments1,734

(6)
1,728

1,866

(18)
1,848
Total Revenues net of purchased power and fuel expense for Reportable Segments1,751 (10)1,741 1,734 (6)1,728 
Other(b)
204
 6
 210
 52
 18
 70
Other(b)
455 10 465 204 6 210 
Total Generation Revenues net of purchased power and fuel expense$1,938
 $—
 $1,938
 $1,918
 $—
 $1,918
Total Generation Revenues net of purchased power and fuel expense$2,206 $0 $2,206 $1,938 $0 $1,938 
__________
(a)Includes purchases and sales from/to third parties and affiliated sales to the Utility Registrants.
(b)Other represents activities not allocated to a region. See text above for a description of included activities. Includes unrealized mark-to-market gains of $85 million and losses of $74 million in 2020 and 2019, respectively and the elimination of intersegment RNF.

(a)Includes purchases and sales from/to third parties and affiliated sales to the Utility Registrants.

(b)Other represents activities not allocated to a region. See text above for a description of included activities. Includes unrealized mark-to-market gains of $314 million and gains of $85 million in 2021 and 2020, respectively and the elimination of intersegment RNF.

71
74



COMBINED NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)
(Dollars in millions, except per share data, unless otherwise noted)

Note 45 — Segment Information

Electric and Gas Revenue by Customer Class (Utility Registrants):
 Three Months Ended June 30, 2020
Revenues from contracts with customersComEd PECO BGE PHI Pepco DPL ACE
Rate-regulated electric revenues             
Residential$767
 $377
 $304
 $529
 $237
 $147
 $145
Small commercial & industrial327
 88
 51
 105
 29
 39
 37
Large commercial & industrial119
 55
 94
 240
 175
 22
 43
Public authorities & electric railroads11
 7
 7
 15
 8
 3
 4
Other(a)
218
 55
 76
 161
 58
 51
 53
Total rate-regulated electric revenues(b)
$1,442
 $582
 $532
 $1,050
 $507
 $262
 $282
Rate-regulated natural gas revenues             
Residential$—
 $70
 $81
 $17
 $—
 $17
 $—
Small commercial & industrial—
 19
 12
 8
 —
 8
 —
Large commercial & industrial—
 —
 24
 1
 —
 1
 —
Transportation—
 6
 —
 3
 —
 3
 —
Other(c)
—
 1
 3
 1
 —
 1
 —
Total rate-regulated natural gas revenues(d)
$—
 $96
 $120
 $30
 $—
 $30
 $—
Total rate-regulated revenues from contracts with customers$1,442
 $678
 $652
 $1,080
 $507
 $292
 $282
              
Other revenues             
Revenues from alternative revenue programs$(25) $4
 $(37) $(64) $(13) $(25) $(26)
Other rate-regulated electric revenues(e)
—
 —
 1
 —
 —
 —
 —
Other rate-regulated natural gas revenues(e)
—
 (1) —
 —
 —
 —
 —
Total other revenues$(25) $3
 $(36) $(64) $(13) $(25) $(26)
Total rate-regulated revenues for reportable segments$1,417
 $681
 $616
 $1,016
 $494
 $267
 $256

Three Months Ended June 30, 2021
Revenues from contracts with customersComEdPECOBGEPHIPepcoDPLACE
Rate-regulated electric revenues
Residential$759 $383 $299 $537 $223 $147 $167 
Small commercial & industrial377 99 60 124 32 46 46 
Large commercial & industrial138 59 108 257 188 22 47 
Public authorities & electric railroads11 8 7 17 10 3 4 
Other(a)
214 54 87 139 50 46 43 
Total rate-regulated electric revenues(b)
$1,499 $603 $561 $1,074 $503 $264 $307 
Rate-regulated natural gas revenues
Residential$0 $55 $81 $12 $0 $12 $0 
Small commercial & industrial0 22 13 6 0 6 0 
Large commercial & industrial0 0 27 1 0 1 0 
Transportation0 5 0 3 0 3 0 
Other(c)
0 1 6 2 0 2 0 
Total rate-regulated natural gas revenues(d)
$0 $83 $127 $24 $0 $24 $0 
Total rate-regulated revenues from contracts with customers$1,499 $686 $688 $1,098 $503 $288 $307 
Other revenues
Revenues from alternative revenue programs$9 $7 $(10)$41 $19 $10 $12 
Other rate-regulated electric revenues(e)
9 0 3 1 1 0 0 
Other rate-regulated natural gas revenues(e)
0 0 1 0 0 0 0 
Total other revenues$18 $7 $(6)$42 $20 $10 $12 
Total rate-regulated revenues for reportable segments$1,517 $693 $682 $1,140 $523 $298 $319 
72
75



COMBINED NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)
(Dollars in millions, except per share data, unless otherwise noted)

Note 45 — Segment Information
Three Months Ended June 30, 2020
Revenues from contracts with customersComEdPECOBGEPHIPepcoDPLACE
Rate-regulated electric revenues
Residential$767 $377 $304 $529 $237 $147 $145 
Small commercial & industrial327 88 51 105 29 39 37 
Large commercial & industrial119 55 94 240 175 22 43 
Public authorities & electric railroads11 7 7 15 8 3 4 
Other(a)
218 55 76 161 58 51 53 
Total rate-regulated electric revenues(b)
$1,442 $582 $532 $1,050 $507 $262 $282 
Rate-regulated natural gas revenues
Residential$0 $70 $81 $17 $0 $17 $0 
Small commercial & industrial0 19 12 8 0 8 0 
Large commercial & industrial0 0 24 1 0 1 0 
Transportation0 6 0 3 0 3 0 
Other(c)
0 1 3 1 0 1 0 
Total rate-regulated natural gas revenues(d)
$0 $96 $120 $30 $0 $30 $0 
Total rate-regulated revenues from contracts with customers$1,442 $678 $652 $1,080 $507 $292 $282 
Other revenues
Revenues from alternative revenue programs$(25)$4 $(37)$(64)$(13)$(25)$(26)
Other rate-regulated electric revenues(e)
0 0 1 0 0 0 0 
Other rate-regulated natural gas revenues(e)
0 (1)0 0 0 0 0 
Total other revenues$(25)$3 $(36)$(64)$(13)$(25)$(26)
Total rate-regulated revenues for reportable segments$1,417 $681 $616 $1,016 $494 $267 $256 

__________
(a)Includes revenues from transmission revenue from PJM, wholesale electric revenue and mutual assistance revenue.
(b)Includes operating revenues from affiliates in 2021 and 2020 respectively of:
•$5 million, $11 million at ComEd
•$1 million, $1 million at PECO
•$4 million, $3 million at BGE
•$4 million, $3 million at PHI
•$1 million, $1 million at Pepco
•$2 million, $2 million at DPL
•$1 million, $1 million at ACE
(c)Includes revenues from off-system natural gas sales.
(d)Includes operating revenues from affiliates in 2021 and 2020 respectively of:
•less than $1 million at PECO both 2021 and 2020
•$3 million, $1 million at BGE
(e)Includes late payment charge revenues.


Six Months Ended June 30, 2021 and 2020
GenerationComEdPECOBGEPHI
Other(a)
Intersegment
Eliminations		Exelon
Operating revenues(b):
2021
Competitive businesses electric revenues$7,935 $0 $0 $0 $0 $0 $(546)$7,389 
76
 Three Months Ended June 30, 2019
Revenues from contracts with customersComEd PECO BGE PHI Pepco DPL ACE
Rate-regulated electric revenues             
Residential$647
 $343
 $282
 $494
 $224
 $135
 $135
Small commercial & industrial349
 99
 59
 120
 35
 44
 41
Large commercial & industrial127
 52
 109
 278
 207
 25
 46
Public authorities & electric railroads10
 7
 6
 16
 8
 4
 4
Other(a)
227
 62
 82
 159
 56
 54
 50
Total rate-regulated electric revenues(b)
$1,360
 $563
 $538
 $1,067
 $530
 $262
 $276
Rate-regulated natural gas revenues             
Residential$—
 $49
 $60
 $11
 $—
 $11
 $—
Small commercial & industrial—
 33
 11
 7
 —
 7
 —
Large commercial & industrial—
 —
 23
 2
 —
 2
 —
Transportation—
 6
 —
 3
 —
 3
 —
Other(c)
—
 1
 7
 1
 —
 1
 —
Total rate-regulated natural gas revenues(d)
$—
 $89
 $101
 $24
 $—
 $24
 $—
Total rate-regulated revenues from contracts with customers$1,360
 $652
 $639
 $1,091
 $530
 $286
 $276
              
Other revenues             
Revenues from alternative revenue programs$(14) $(3) $6
 $(3) $(1) $—
 $(2)
Other rate-regulated electric revenues(e)
5
 6
 3
 3
 2
 1
 —
Other rate-regulated natural gas revenues(e)
—
 —
 1
 —
 —
 —
 —
Total other revenues$(9) $3
 $10
 $—
 $1
 $1
 $(2)
Total rate-regulated revenues for reportable segments$1,351
 $655
 $649
 $1,091
 $531
 $287
 $274

__________
(a)Includes revenues from transmission revenue from PJM, wholesale electric revenue and mutual assistance revenue.
(b)Includes operating revenues from affiliates of $11 million, $1 million, $3 million, $3 million, $1 million, $2 million and $1 million at ComEd, PECO, BGE, PHI, Pepco, DPL and ACE, respectively, in 2020 and $5 million, $1 million, $1 million, $3 million, $1 million, $2 million and $1 million at ComEd, PECO, BGE, PHI, Pepco, DPL and ACE, respectively, in 2019.
(c)Includes revenues from off-system natural gas sales.
(d)Includes operating revenues from affiliates of less than $1 million and $1 million at PECO and BGE, respectively, in 2020 and less than $1 million and $4 million at PECO and BGE, respectively, in 2019.
(e)Includes late payment charge revenues.

73
COMBINED NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)
(Dollars in millions, except per share data, unless otherwise noted)

Note 45 — Segment Information

Six Months Ended June 30, 2020 and 2019
GenerationComEdPECOBGEPHI
Other(a)
Intersegment
Eliminations		Exelon
Competitive businesses natural gas revenues1,833 0 0 0 0 0 0 1,833 
Competitive businesses other revenues(56)0 0 0 0 0 (1)(57)
Rate-regulated electric revenues0 3,052 1,271 1,190 2,283 0 (21)7,775 
Rate-regulated natural gas revenues0 0 311 466 95 0 (7)865 
Shared service and other revenues0 0 0 0 6 1,013 (1,019)0 
Total operating revenues$9,712 $3,052 $1,582 $1,656 $2,384 $1,013 $(1,594)$17,805 
2020
Competitive businesses electric revenues$7,165 $0 $0 $0 $0 $0 $(594)$6,571 
Competitive businesses natural gas revenues1,025 0 0 0 0 0 (3)1,022 
Competitive businesses other revenues423 0 0 0 0 0 (2)421 
Rate-regulated electric revenues0 2,856 1,189 1,118 2,086 0 (27)7,222 
Rate-regulated natural gas revenues0 0 304 436 94 0 (2)832 
Shared service and other revenues0 0 0 0 7 953 (959)1 
Total operating revenues$8,613 $2,856 $1,493 $1,554 $2,187 $953 $(1,587)$16,069 
Intersegment revenues(c):
2021$549 $11 $4 $13 $7 $1,010 $(1,594)$0 
2020601 16 4 10 7 949 (1,585)2 
Depreciation and amortization:
2021$1,869 $589 $173 $293 $404 $35 $0 $3,363 
2020604 547 173 272 385 42 0 2,023 
Operating expenses:
2021$11,141 $2,406 $1,231 $1,372 $2,013 $1,029 $(1,549)$17,643 
20207,947 2,497 1,242 1,263 1,955 958 (1,564)14,298 
Interest expense, net:
2021$148 $193 $80 $67 $134 $161 $0 $783 
2020197 192 71 64 134 179 0 837 
77
 Generation ComEd PECO BGE PHI 
Other(a)
 Intersegment
Eliminations		 Exelon
Operating revenues(b):
2020               
Competitive businesses electric revenues$7,165
 $—
 $—
 $—
 $—
 $—
 $(594) $6,571
Competitive businesses natural gas revenues1,025
 —
 —
 —
 —
 —
 (3) 1,022
Competitive businesses other revenues423
 —
 —
 —
 —
 —
 (2) 421
Rate-regulated electric revenues—
 2,856
 1,189
 1,118
 2,086
 —
 (27) 7,222
Rate-regulated natural gas revenues—
 —
 304
 436
 94
 —
 (2) 832
Shared service and other revenues—
 —
 —
 —
 7
 953
 (959) 1
Total operating revenues$8,613
 $2,856
 $1,493
 $1,554
 $2,187
 $953
 $(1,587) $16,069
2019               
Competitive businesses electric revenues$8,052
 $—
 $—
 $—
 $—
 $—
 $(565) $7,487
Competitive businesses natural gas revenues1,214
 —
 —
 —
 —
 —
 (1) 1,213
Competitive businesses other revenues240
 —
 —
 —
 —
 —
 (2) 238
Rate-regulated electric revenues—
 2,759
 1,185
 1,198
 2,218
 —
 (17) 7,343
Rate-regulated natural gas revenues—
 —
 369
 427
 95
 —
 (8) 883
Shared service and other revenues—
 —
 —
 —
 6
 940
 (944) 2
Total operating revenues$9,506
 $2,759
 $1,554
 $1,625
 $2,319
 $940
 $(1,537) $17,166
Intersegment revenues(c):
               
2020$601
 $16
 $4
 $10
 $7
 $949
 $(1,585) $2
2019568
 9
 3
 12
 7
 935
 (1,534) —
Depreciation and amortization:               
2020$604
 $547
 $173
 $272
 $385
 $42
 $—
 $2,023
2019814
 508
 164
 252
 369
 47
 —
 2,154
Operating expenses:               
2020$7,947
 $2,497
 $1,242
 $1,263
 $1,955
 $958
 $(1,564) $14,298
20199,059
 2,174
 1,187
 1,325
 1,981
 942
 (1,526) 15,142
Interest expense, net:               
2020$197
 $192
 $71
 $64
 $134
 $179
 $—
 $837
2019227
 178
 67
 58
 131
 152
 —
 813


74
COMBINED NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)
(Dollars in millions, except per share data, unless otherwise noted)

Note 45 — Segment Information

Generation ComEd PECO BGE PHI 
Other(a)
 Intersegment
Eliminations		 ExelonGenerationComEdPECOBGEPHI
Other(a)
Intersegment
Eliminations		Exelon
Income (loss) before income taxes:               Income (loss) before income taxes:
20212021$(823)$475 $283 $233 $273 $(174)$1 $268 
2020$313
 $189
 $187
 $237
 $126
 $(175) $2
 $879
2020313 189 187 237 126 (175)2 879 
2019854
 429
 307
 253
 234
 (151) —
 1,926
Income Taxes:               Income Taxes:
20212021$(70)$85 $12 $(21)$5 $44 $0 $55 
2020$(59) $82
 $9
 $18
 $(76) $(49) $—
 $(75)2020(59)82 9 18 (76)(49)0 (75)
2019301
 85
 37
 47
 11
 (27) —
 454
Net income (loss):               Net income (loss):
20212021$(756)$390 $271 $254 $269 $(218)$1 $211 
2020$368
 $107
 $178
 $219
 $202
 $(126) $2
 $950
2020368 107 178 219 202 (126)2 950 
2019540
 344
 270
 206
 223
 (123) —
 1,460
Capital Expenditures               
Capital Expenditures:Capital Expenditures:
20212021$719 $1,162 $577 $620 $889 $73 $0 $4,040 
2020$930
 $1,029
 $512
 $548
 $686
 $68
 $—
 $3,773
2020930 1,029 512 548 686 68 0 3,773 
2019890
 961
 447
 542
 698
 34
 —
 3,572
Total assets:               Total assets:
June 30, 2020$47,003
 $33,896
 $12,120
 $11,027
 $23,004
 $9,288
 $(10,025) $126,313
December 31, 201948,995
 32,765
 11,469
 10,634
 22,719
 8,484
 (10,089) 124,977
June 30, 2021June 30, 2021$45,821 $35,324 $13,491 $12,186 $24,235 $8,507 $(10,168)$129,396 
December 31, 2020December 31, 202048,094 34,466 12,531 11,650 23,736 9,005 (10,165)129,317 
__________
(a)Other primarily includes Exelon’s corporate operations, shared service entities and other financing and investment activities.
(b)Includes gross utility tax receipts from customers. The offsetting remittance of utility taxes to the governing bodies is recorded in expenses in the Registrants’ Consolidated Statements of Operations and Comprehensive Income. See Note 17 — Supplemental Financial Information for additional information on total utility taxes.
(c)Intersegment revenues exclude sales to unconsolidated affiliates. The intersegment profit associated with Generation’s sale of certain products and services by and between Exelon’s segments is not eliminated in consolidation due to the recognition of intersegment profit in accordance with regulatory accounting guidance. For Exelon, these amounts are included in Operating revenues in the Consolidated Statements of Operations and Comprehensive Income. See Note 18 — Related Party Transactions for additional information on intersegment revenues.

(a)Other primarily includes Exelon’s corporate operations, shared service entities, and other financing and investment activities.
(b)Includes gross utility tax receipts from customers. The offsetting remittance of utility taxes to the governing bodies is recorded in expenses in the Registrants’ Consolidated Statements of Operations and Comprehensive Income. See Note 18 — Supplemental Financial Information for additional information on total utility taxes.
(c)Intersegment revenues exclude sales to unconsolidated affiliates. The intersegment profit associated with Generation’s sale of certain products and services by and between Exelon’s segments is not eliminated in consolidation due to the recognition of intersegment profit in accordance with regulatory accounting guidance. For Exelon, these amounts are included in Operating revenues in the Consolidated Statements of Operations and Comprehensive Income. See Note 19 — Related Party Transactions for additional information on intersegment revenues.

75
78



COMBINED NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)
(Dollars in millions, except per share data, unless otherwise noted)

Note 45 — Segment Information

PHI:
 Pepco DPL ACE 
Other(a)
 Intersegment
Eliminations		 PHI
Operating revenues(b):
           
2020           
Rate-regulated electric revenues$1,039
 $523
 $532
 $—
 $(8) $2,086
Rate-regulated natural gas revenues—
 94
 —
 —
 —
 94
Shared service and other revenues—
 —
 —
 189
 (182) 7
Total operating revenues$1,039
 $617
 $532
 $189
 $(190) $2,187
2019           
Rate-regulated electric revenues$1,106
 $572
 $547
 $—
 $(7) $2,218
Rate-regulated natural gas revenues—
 95
 —
 —
 —
 95
Shared service and other revenues—
 —
 —
 205
 (199) 6
Total operating revenues$1,106
 $667
 $547
 $205
 $(206) $2,319
Intersegment revenues(c):
           
2020$3
 $4
 $1
 $189
 $(190) $7
20193
 3
 1
 205
 (205) 7
Depreciation and amortization:           
2020$186
 $94
 $86
 $19
 $—
 $385
2019186
 91
 71
 20
 1
 369
Operating expenses:           
2020$899
 $547
 $509
 $190
 $(190) $1,955
2019929
 550
 498
 208
 (204) 1,981
Interest expense, net:           
2020$68
 $31
 $29
 $6
 $—
 $134
201968
 30
 28
 5
 —
 131
Income (loss) before income taxes:           
2020$90
 $44
 $(1) $(7) $—
 $126
2019(d)
123
 94
 25
 (8) —
 234
Income Taxes:           
2020$(19) $(20) $(32) $(5) $—
 $(76)
20194
 11
 1
 (5) —
 11
Net income (loss):           
2020$109
 $64
 $31
 $(2) $—
 $202
2019119
 83
 24
 (3) —
 223
Capital Expenditures           
2020$324
 $184
 $178
 $—
 $—
 $686
2019298
 160
 227
 13
 —
 698
Total assets:           
June 30, 2020$8,869
 $4,966
 $4,089
 $5,234
 $(154) $23,004
December 31, 2019(d)
8,661
 4,830
 3,933
 5,335
 (40) 22,719

76
Table of Contents
COMBINED NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)
(Dollars in millions, except per share data, unless otherwise noted)

Note 4 — Segment Information

PepcoDPLACE
Other(a)
Intersegment
Eliminations		PHI
Operating revenues(b):
2021
Rate-regulated electric revenues$1,076 $585 $629 $0 $(7)$2,283 
Rate-regulated natural gas revenues0 95 0 0 0 95 
Shared service and other revenues0 0 0 189 (183)6 
Total operating revenues$1,076 $680 $629 $189 $(190)$2,384 
2020
Rate-regulated electric revenues$1,039 $523 $532 $0 $(8)$2,086 
Rate-regulated natural gas revenues0 94 0 0 0 94 
Shared service and other revenues0 0 0 189 (182)7 
Total operating revenues$1,039 $617 $532 $189 $(190)$2,187 
Intersegment revenues(c):
2021$3 $4 $1 $189 $(190)$7 
20203 4 1 189 (190)7 
Depreciation and amortization:
2021$199 $104 $87 $14 $0 $404 
2020186 94 86 19 0 385 
Operating expenses:
2021$895 $564 $552 $192 $(190)$2,013 
2020899 547 509 190 (190)1,955 
Interest expense, net:
2021$69 $30 $29 $6 $0 $134 
202068 31 29 6 0 134 
Income (loss) before income taxes:
2021$137 $92 $50 $(6)$0 $273 
202090 44 (1)(7)0 126 
Income Taxes:
2021$3 $6 $(1)$(3)$0 $5 
2020(19)(20)(32)(5)0 (76)
Net income (loss):
2021$134 $86 $51 $(2)$0 $269 
2020109 64 31 (2)0 202 
Capital Expenditures:
2021$439 $211 $239 $0 $0 $889 
2020324 184 178 0 0 686 
Total assets:
June 30, 2021$9,588 $5,229 $4,473 $5,014 $(69)$24,235 
December 31, 20209,264 5,140 4,286 5,079 (33)23,736 
__________
(a)Other primarily includes PHI’s corporate operations, shared service entities and other financing and investment activities.
(b)Includes gross utility tax receipts from customers. The offsetting remittance of utility taxes to the governing bodies is recorded in expenses in the Registrants’ Consolidated Statements of Operations and Comprehensive Income. See Note 17 — Supplemental Financial Information for additional information on total utility taxes.
(c)Includes intersegment revenues with ComEd, BGE and PECO, which are eliminated at Exelon.
(d)
The Income (loss) before income taxes and Total assets amounts in Other and Intersegment Eliminations have been adjusted by an offsetting $227 million and $5.7 billion, respectively, for consistency with the Exelon consolidating disclosure above.
(a)Other primarily includes PHI’s corporate operations, shared service entities, and other financing and investment activities.
(b)Includes gross utility tax receipts from customers. The offsetting remittance of utility taxes to the governing bodies is recorded in expenses in the Registrants’ Consolidated Statements of Operations and Comprehensive Income. See Note 18 — Supplemental Financial Information for additional information on total utility taxes.
(c)Includes intersegment revenues with ComEd, BGE, and PECO, which are eliminated at Exelon.

The following tables disaggregate the Registrants' revenue recognized from contracts with customers into categories that depict how the nature, amount, timing, and uncertainty of revenue and cash flows are affected by economic factors. For Generation, the disaggregation of revenues reflects Generation’s two primary products of power sales and natural gas sales, with further disaggregation of power sales provided by geographic region. For the Utility Registrants, the disaggregation of revenues reflects the two primary utility services of rate-regulated
79



COMBINED NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)
(Dollars in millions, except per share data, unless otherwise noted)

Note 5 — Segment Information
electric sales and rate-regulated natural gas sales (where applicable), with further disaggregation of these tariff sales provided by major customer groups. Exelon’s disaggregated revenues are consistent with Generation and the Utility Registrants, but exclude any intercompany revenues.
Competitive Business Revenues (Generation):
Six Months Ended June 30, 2021
Revenues from external customers(a)
Intersegment
Revenues		Total
Revenues
Contracts with customers
Other(b)
Total
Mid-Atlantic$2,233 $11 $2,244 $11 $2,255 
Midwest1,983 (24)1,959 1 1,960 
New York759 (40)719 0 719 
ERCOT533 (10)523 9 532 
Other Power Regions2,095 395 2,490 (21)2,469 
Total Competitive Businesses Electric Revenues7,603 332 7,935 0 7,935 
Competitive Businesses Natural Gas Revenues1,117 716 1,833 0 1,833 
Competitive Businesses Other Revenues(c)
195 (251)(56)0 (56)
Total Generation Consolidated Operating Revenues$8,915 $797 $9,712 $0 $9,712 
Six Months Ended June 30, 2020Six Months Ended June 30, 2020
Revenues from external customers(a)
 
Intersegment
Revenues
 
Total
Revenues
Revenues from external customers(a)
Intersegment
revenues		Total
Revenues
Contracts with customers 
Other(b)
 Total Contracts with customers
Other(b)
Total
Mid-Atlantic$2,365
 $(133) $2,232
 $15
 $2,247
Mid-Atlantic$2,365 $(133)$2,232 $15 $2,247 
Midwest1,798
 172
 1,970
 (6) 1,964
Midwest1,798 172 1,970 (6)1,964 
New York672
 (16) 656
 (1) 655
New York672 (16)656 (1)655 
ERCOT330
 81
 411
 13
 424
ERCOT330 81 411 13 424 
Other Power Regions1,782
 114
 1,896
 (21) 1,875
Other Power Regions1,782 114 1,896 (21)1,875 
Total Competitive Businesses Electric Revenues6,947
 218
 7,165
 —
 7,165
Total Competitive Businesses Electric Revenues6,947 218 7,165 0 7,165 
Competitive Businesses Natural Gas Revenues712
 313
 1,025
 —
 1,025
Competitive Businesses Natural Gas Revenues712 313 1,025 0 1,025 
Competitive Businesses Other Revenues(c)
185
 238
 423
 —
 423
Competitive Businesses Other Revenues(c)
185 238 423 0 423 
Total Generation Consolidated Operating Revenues$7,844
 $769
 $8,613
 $—
 $8,613
Total Generation Consolidated Operating Revenues$7,844 $769 $8,613 $0 $8,613 
__________
 Six Months Ended June 30, 2019
 
Revenues from external customers(a)
 Intersegment
revenues		 Total
Revenues
 Contracts with customers 
Other(b)
 Total  
Mid-Atlantic$2,448
 $(2) $2,446
 $(1) $2,445
Midwest2,030
 126
 2,156
 (14) 2,142
New York781
 1
 782
 —
 782
ERCOT307
 126
 433
 8
 441
Other Power Regions1,976
 259
 2,235
 (21) 2,214
Total Competitive Businesses Electric Revenues7,542
 510
 8,052
 (28) 8,024
Competitive Businesses Natural Gas Revenues763
 451
 1,214
 28
 1,242
Competitive Businesses Other Revenues(c)
230
 10
 240
 —
 240
Total Generation Consolidated Operating Revenues$8,535
 $971
 $9,506
 $—
 $9,506
(a)Includes all wholesale and retail electric sales to third parties and affiliated sales to the Utility Registrants.
(b)Includes revenues from derivatives and leases.
(c)Other represents activities not allocated to a region. See text above for a description of included activities. Includes unrealized mark-to-market losses of $323 million and gains of $200 million in 2021 and 2020, respectively, and elimination of intersegment revenues.

__________
80


77
COMBINED NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)
(Dollars in millions, except per share data, unless otherwise noted)

Note 45 — Segment Information

(a)Includes all wholesale and retail electric sales to third parties and affiliated sales to the Utility Registrants.
(b)Includes revenues from derivatives and leases.
(c)Other represents activities not allocated to a region. See text above for a description of included activities. Includes unrealized mark-to-market gains of $200 million and losses of $14 million in 2020 and 2019, respectively, and elimination of intersegment revenues.

Revenues net of purchased power and fuel expense (Generation):
Six Months Ended June 30, 2021Six Months Ended June 30, 2020
RNF
from external
customers(a)
Intersegment
RNF		Total RNF
RNF
from external
customers(a)
Intersegment
RNF		Total RNF
Mid-Atlantic$1,130 $11 $1,141 $1,074 $18 $1,092 
Midwest1,359 1 1,360 1,431 (4)1,427 
New York531 5 536 433 7 440 
ERCOT(957)(145)(1,102)168 9 177 
Other Power Regions409 (56)353 355 (43)312 
Total Revenues net of purchased power and fuel expense for Reportable Segments2,472 (184)2,288 3,461 (13)3,448 
Other(b)
683 184 867 506 13 519 
Total Generation Revenues net of purchased power and fuel expense$3,155 $0 $3,155 $3,967 $0 $3,967 
 Six Months Ended June 30, 2020 Six Months Ended June 30, 2019
 
RNF
from external
customers(a)
 
Intersegment
RNF
 Total RNF 
RNF
from external
customers(a)
 
Intersegment
RNF
 Total RNF
Mid-Atlantic$1,074
 $18
 $1,092
 $1,324
 $10
 $1,334
Midwest1,431
 (4) 1,427
 1,506
 (6) 1,500
New York433
 7
 440
 512
 7
 519
ERCOT168
 9
 177
 178
 (24) 154
Other Power Regions355
 (43) 312
 328
 (36) 292
Total Revenues net of purchased power and fuel expense for Reportable Segments3,461

(13)
3,448

3,848

(49)
3,799
Other(b)
506
 13
 519
 161
 49
 210
Total Generation Revenues net of purchased power and fuel expense$3,967

$—

$3,967

$4,009

$—

$4,009
__________
(a)Includes purchases and sales from/to third parties and affiliated sales to the Utility Registrants.
(b)Other represents activities not allocated to a region. See text above for a description of included activities. Primarily includes:
•unrealized mark-to-market gains of $489 million and gains of $218 million in 2021 and 2020, respectively;
•accelerated nuclear fuel amortization associated with announced early plant retirements as discussed in Note 7 - Early Plant Retirements of $106 million in 2021; and
• the elimination of intersegment RNF.

__________
(a)Includes purchases and sales from/to third parties and affiliated sales to the Utility Registrants.
(b)Other represents activities not allocated to a region. See text above for a description of included activities. Includes unrealized mark-to-market gains of $218 million and losses of $102 million in 2020 and 2019, respectively and the elimination of intersegment RNF.



78
81



COMBINED NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)
(Dollars in millions, except per share data, unless otherwise noted)

Note 45 — Segment Information

Electric and Gas Revenue by Customer Class (Utility Registrants):
Six Months Ended June 30, 2021
Revenues from contracts with customersComEdPECOBGEPHIPepcoDPLACE
Rate-regulated electric revenues
Residential$1,502 $816 $662 $1,142 $476 $337 $329 
Small commercial & industrial744 199 129 242 65 92 85 
Large commercial & industrial271 116 213 505 372 43 90 
Public authorities & electric railroads22 17 13 30 16 7 7 
Other(a)
433 106 165 283 101 87 95 
Total rate-regulated electric revenues(b)
$2,972 $1,254 $1,182 $2,202 $1,030 $566 $606 
Rate-regulated natural gas revenues
Residential$0 $215 $297 $57 $0 $57 $0 
Small commercial & industrial0 81 48 24 0 24 0 
Large commercial & industrial0 0 81 3 0 3 0 
Transportation0 12 0 8 0 8 0 
Other(c)
0 3 36 2 0 3 0 
Total rate-regulated natural gas revenues(d)
$0 $311 $462 $94 $0 $95 $0 
Total rate-regulated revenues from contracts with customers$2,972 $1,565 $1,644 $2,296 $1,030 $661 $606 
Other revenues
Revenues from alternative revenue programs$64 $17 $8 $88 $46 $19 $23 
Other rate-regulated electric revenues(e)
16 0 3 0 0 0 0 
Other rate-regulated natural gas revenues(e)
0 0 1 0 0 0 0 
Total other revenues$80 $17 $12 $88 $46 $19 $23 
Total rate-regulated revenues for reportable segments$3,052 $1,582 $1,656 $2,384 $1,076 $680 $629 
 Six Months Ended June 30, 2020
Revenues from contracts with customersComEd PECO BGE PHI Pepco DPL ACE
Rate-regulated electric revenues             
Residential$1,468
 $759
 $644
 $1,062
 $472
 $308
 $282
Small commercial & industrial689
 187
 118
 221
 65
 82
 74
Large commercial & industrial253
 108
 198
 493
 363
 45
 85
Public authorities & electric railroads23
 14
 14
 31
 17
 6
 7
Other(a)
430
 113
 154
 332
 119
 105
 109
Total rate-regulated electric revenues(b)
$2,863
 $1,181
 $1,128
 $2,139
 $1,036
 $546
 $557
Rate-regulated natural gas revenues             
Residential$—
 $220
 $287
 $57
 $—
 $57
 $—
Small commercial & industrial—
 70
 46
 25
 —
 25
 —
Large commercial & industrial—
 —
 76
 2
 —
 2
 —
Transportation—
 12
 —
 7
 —
 7
 —
Other(c)
—
 2
 13
 3
 —
 3
 —
Total rate-regulated natural gas revenues(d)
$—
 $304
 $422
 $94
 $—
 $94
 $—
Total rate-regulated revenues from contracts with customers$2,863
 $1,485
 $1,550
 $2,233
 $1,036
 $640
 $557
              
Other revenues             
Revenues from alternative revenue programs$(13) $5
 $—
 $(47) $2
 $(24) $(25)
Other rate-regulated electric revenues(e)
6
 3
 3
 1
 1
 1
 —
Other rate-regulated natural gas revenues(e)
—
 —
 1
 —
 —
 —
 —
Total other revenues$(7) $8
 $4
 $(46) $3
 $(23) $(25)
Total rate-regulated revenues for reportable segments$2,856
 $1,493
 $1,554
 $2,187
 $1,039
 $617
 $532
82


79
COMBINED NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)
(Dollars in millions, except per share data, unless otherwise noted)

Note 45 — Segment Information

Six Months Ended June 30, 2020
Revenues from contracts with customersComEdPECOBGEPHIPepcoDPLACE
Rate-regulated electric revenues
Residential$1,468 $759 $644 $1,062 $472 $308 $282 
Small commercial & industrial689 187 118 221 65 82 74 
Large commercial & industrial253 108 198 493 363 45 85 
Public authorities & electric railroads23 14 14 30 17 6 7 
Other(a)
430 113 154 333 119 105 109 
Total rate-regulated electric revenues(b)
$2,863 $1,181 $1,128 $2,139 $1,036 $546 $557 
Rate-regulated natural gas revenues
Residential$0 $220 $287 $57 $0 $57 $0 
Small commercial & industrial0 70 46 25 0 25 0 
Large commercial & industrial0 0 76 2 0 2 0 
Transportation0 12 0 7 0 7 0 
Other(c)
0 2 13 3 0 3 0 
Total rate-regulated natural gas revenues(d)
$0 $304 $422 $94 $0 $94 $0 
Total rate-regulated revenues from contracts with customers$2,863 $1,485 $1,550 $2,233 $1,036 $640 $557 
Other revenues
Revenues from alternative revenue programs$(13)$5 $0 $(47)$2 $(24)$(25)
Other rate-regulated electric revenues(e)
6 3 3 1 1 1 0 
Other rate-regulated natural gas revenues(e)
0 0 1 0 0 0 0 
Total other revenues$(7)$8 $4 $(46)$3 $(23)$(25)
Total rate-regulated revenues for reportable segments$2,856 $1,493 $1,554 $2,187 $1,039 $617 $532 
__________
 Six Months Ended June 30, 2019
Revenues from contracts with customersComEd PECO BGE PHI Pepco DPL ACE
Rate-regulated electric revenues             
Residential$1,356
 $752
 $667
 $1,073
 $480
 $320
 $273
Small commercial & industrial709
 195
 129
 241
 73
 93
 75
Large commercial & industrial259
 100
 219
 545
 411
 49
 85
Public authorities & electric railroads23
 14
 13
 31
 17
 7
 7
Other(a)
442
 123
 160
 317
 108
 101
 108
Total rate-regulated electric revenues(b)
$2,789
 $1,184
 $1,188
 $2,207
 $1,089
 $570
 $548
Rate-regulated natural gas revenues             
Residential$—
 $247
 $279
 $55
 $—
 $55
 $—
Small commercial & industrial—
 105
 46
 26
 —
 26
 —
Large commercial & industrial—
 1
 73
 3
 —
 3
 —
Transportation—
 13
 —
 7
 —
 7
 —
Other(c)
—
 3
 13
 4
 —
 4
 —
Total rate-regulated natural gas revenues(d)
$—
 $369
 $411
 $95
 $—
 $95
 $—
Total rate-regulated revenues from contracts with customers$2,789
 $1,553
 $1,599
 $2,302
 $1,089
 $665
 $548
              
Other revenues             
Revenues from alternative revenue programs$(42) $(6) $17
 $12
 $13
 $1
 $(1)
Other rate-regulated electric revenues(e)
12
 7
 6
 5
 4
 1
 —
Other rate-regulated natural gas revenues(e)
—
 —
 3
 —
 —
 —
 —
Total other revenues$(30) $1
 $26
 $17
 $17
 $2
 $(1)
Total rate-regulated revenues for reportable segments$2,759
 $1,554
 $1,625
 $2,319
 $1,106
 $667
 $547
(a)Includes revenues from transmission revenue from PJM, wholesale electric revenue and mutual assistance revenue.
(b)Includes operating revenues from affiliates in 2021 and 2020 respectively of:
•$11 million, $16 million at ComEd
•$3 million, $3 million at PECO
•$5 million, $6 million at BGE
•$7 million, $7 million at PHI
•$3 million, $3 million at Pepco
•$4 million, $4 million at DPL
•$1 million, $1 million at ACE
(c)Includes revenues from off-system natural gas sales.
(d)Includes operating revenues from affiliates in 2021 and 2020 respectively of:
•$1 million, less than $1 million at PECO
•$7 million, $4 million at BGE
(e)Includes late payment charge revenues.

__________
(a)Includes revenues from transmission revenue from PJM, wholesale electric revenue and mutual assistance revenue.
(b)Includes operating revenues from affiliates of $16 million, $3 million, $6 million, $7 million, $3 million, $4 million and $1 million at ComEd, PECO, BGE, PHI, Pepco, DPL and ACE, respectively, in 2020 and $9 million, $2 million, $1 million, $7 million, $3 million, $3 million and $1 million at ComEd, PECO, BGE, PHI, Pepco, DPL and ACE, respectively, in 2019.
(c)Includes revenues from off-system natural gas sales.
(d)Includes operating revenues from affiliates of less than $1 million and $4 million at PECO and BGE, respectively, in 2020 and $1 million and $9 million at PECO and BGE, respectively, in 2019.
(e)Includes late payment charge revenues.

83


80
Table of Contents
COMBINED NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)
(Dollars in millions, except per share data, unless otherwise noted)

Note 56 — Accounts Receivable

5.6. Accounts Receivable (All Registrants)
Allowance for Credit Losses on Accounts Receivable (All Registrants)
The following tables present the rollforward of Allowance for Credit Losses on Customer Accounts Receivable.
 Three Months Ended June 30, 2020
 Exelon Generation ComEd PECO BGE PHI Pepco DPL ACE
Balance as of March 31, 2020$278
 $81
 $71
 $66
 $18
 $42
 $15
 $13
 $14
Plus: Current Period Provision for Expected Credit Losses51
 9
 7
 10
 6
 19
 8
 5
 6
Less: Write-offs, net of recoveries(a)
12
 1
 6
 5
 1
 (1) (1) —
 —
Less: Sale of customer accounts receivable (b)
56
 56
 —
 —
 —
 —
 —
 —
 —
Balance as of June 30, 2020$261
 $33
 $72
 $71
 $23
 $62
 $24
 $18
 $20
 Six Months Ended June 30, 2020
 Exelon Generation ComEd PECO BGE PHI Pepco DPL ACE
Balance as of December 31, 2019$243
 $80
 $59
 $55
 $12
 $37
 $13
 $11
 $13
Plus: Current Period Provision for Expected Credit Losses106
 13
 25
 28
 14
 26
 11
 7
 8
Less: Write-offs, net of recoveries(a)
32
 4
 12
 12
 3
 1
 —
 —
 1
Less: Sale of customer accounts receivable (b)

56
 56
 —
 —
 —
 —
 —
 —
 —
Balance as of June 30, 2020$261
 $33
 $72
 $71
 $23
 $62
 $24
 $18
 $20
_________
Three Months Ended June 30, 2021
ExelonGenerationComEdPECOBGEPHIPepcoDPLACE
Balance as of March 31, 2021$442 $65 $103 $130 $43 $101 $41 $25 $35 
Plus: Current period provision for expected credit losses(29)13 (9)(14)(14)(5)(1)(5)1 
Less: Write-offs, net of recoveries(a)
18 3 5 5 2 3 2 1 0 
Balance as of June 30, 2021$395 $75 $89 $111 $27 $93 $38 $19 $36 
Three Months Ended June 30, 2020
ExelonGenerationComEdPECOBGEPHIPepcoDPLACE
Balance as of March 31, 2020$278 $81 $71 $66 $18 $42 $15 $13 $14 
Plus: Current period provision for expected credit losses51 9 7 10 6 19 8 5 6 
Less: Write-offs, net of recoveries(a)
12 1 6 5 1 (1)(1)0 0 
Less: Sale of customer accounts receivable(b)
56 56 — — — — — — — 
Balance as of June 30, 2020$261 $33 $72 $71 $23 $62 $24 $18 $20 
(a)Recoveries were not material to the Registrants.
(b)See below for additional information on the sale of customer accounts receivable at Generation in the second quarter of 2020.


81
84



COMBINED NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)
(Dollars in millions, except per share data, unless otherwise noted)

Note 56 — Accounts Receivable
Six Months Ended June 30, 2021
ExelonGenerationComEdPECOBGEPHIPepcoDPLACE
Balance as of December 31, 2020$366 $32 $97 $116 $35 $86 $32 $22 $32 
Plus: Current period provision for expected credit losses(c)
75 47 12 6 (5)15 10 1 4 
Less: Write-offs, net of recoveries(a)
46 4 20 11 3 8 4 4 0 
Balance as of June 30, 2021$395 $75 $89 $111 $27 $93 $38 $19 $36 
Six Months Ended June 30, 2020
ExelonGenerationComEdPECOBGEPHIPepcoDPLACE
Balance as of December 31, 2019$243 $80 $59 $55 $12 $37 $13 $11 $13 
Plus: Current period provision for expected credit losses106 13 25 28 14 26 11 7 8 
Less: Write-offs, net of recoveries(a)
32 4 12 12 3 1 0 0 1 
Less: Sale of customer accounts receivable(b)
56 56 — — — — — — — 
Balance as of June 30, 2020$261 $33 $72 $71 $23 $62 $24 $18 $20 
__________
(a)Recoveries were not material to the Registrants.
(b)See below for additional information on the sale of customer accounts receivable at Generation in the second quarter of 2020.
(c)For Generation, primarily relates to the impacts of the February 2021 extreme cold weather event. See Note 3 — Regulatory Matters for additional information.
85



COMBINED NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)
(Dollars in millions, except per share data, unless otherwise noted)

Note 6 — Accounts Receivable
The following tables present the rollforward of Allowance for Credit Losses on Other Accounts Receivable.
Three Months Ended June 30, 2021
ExelonGenerationComEdPECOBGEPHIPepcoDPLACE
Balance as of March 31, 2021$79 $0 $22 $11 $9 $37 $15 $10 $12 
Plus: Current period provision for expected credit losses(4)1 (3)(3)0 1 1 (1)1 
Less: Write-offs, net of recoveries(a)
3 0 1 1 1 0 0 0 0 
Balance as of June 30, 2021$72 $1 $18 $7 $8 $38 $16 $9 $13 
Three Months Ended June 30, 2020
ExelonGenerationComEdPECOBGEPHIPepcoDPLACE
Balance as of March 31, 2020$52 $0 $22 $7 $5 $18 $8 $4 $6 
Plus: Current period provision for expected credit losses12 0 1 1 2 8 3 3 2 
Less: Write-offs, net of recoveries(a)
3 0 1 1 1 0 0 0 0 
Balance as of June 30, 2020$61 $0 $22 $7 $6 $26 $11 $7 $8 
Six Months Ended June 30, 2021
ExelonGenerationComEdPECOBGEPHIPepcoDPLACE
Balance as of December 31, 2020$71 $0 $21 $8 $9 $33 $13 $9 $11 
Plus: Current period provision for expected credit losses6 1 (2)1 1 5 3 0 2 
Less: Write-offs, net of recoveries(a)
5 0 1 2 2 0 0 0 0 
Balance as of June 30, 2021$72 $1 $18 $7 $8 $38 $16 $9 $13 
Six Months Ended June 30, 2020
ExelonGenerationComEdPECOBGEPHIPepcoDPLACE
Balance as of December 31, 2019$48 $0 $20 $7 $5 $16 $7 $4 $5 
Plus: Current period provision for expected credit losses20 0 4 2 4 10 4 3 3 
Less: Write-offs, net of recoveries(a)
7 0 2 2 3 0 0 0 0 
Balance as of June 30, 2020$61 $0 $22 $7 $6 $26 $11 $7 $8 
 Three Months Ended June 30, 2020
 Exelon Generation ComEd PECO BGE PHI Pepco DPL ACE
Balance as of March 31, 2020$52
 $—
 $22
 $7
 $5
 $18
 $8
 $4
 $6
Plus: Current Period Provision for Expected Credit Losses12
 —
 1
 1
 2
 8
 3
 3
 2
Less: Write-offs, net of recoveries(a)
3
 —
 1
 1
 1
 —
 —
 —
 —
Balance as of June 30, 2020$61
 $—
 $22
 $7
 $6
 $26
 $11
 $7
 $8
__________
(a)Recoveries were not material to the Registrants.

86



 Six Months Ended June 30, 2020
 Exelon Generation ComEd PECO BGE PHI Pepco DPL ACE
Balance as of December 31, 2019$48
 $—
 $20
 $7
 $5
 $16
 $7
 $4
 $5
Plus: Current Period Provision for Expected Credit Losses20
 —
 4
 2
 4
 10
 4
 3
 3
Less: Write-offs, net of recoveries(a)
7
 —
 2
 2
 3
 —
 —
 —
 —
Balance as of June 30, 2020$61
 $—
 $22
 $7
 $6
 $26
 $11
 $7
 $8
_________COMBINED NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)
(a)Recoveries were not material to the Registrants.
(Dollars in millions, except per share data, unless otherwise noted)

Note 6 — Accounts Receivable
Unbilled Customer Revenue (All Registrants)
The following table provides additional information about unbilled customer revenues recorded in the Registrants' Consolidated Balance Sheets.Sheets as of June 30, 2021 and December 31, 2020.
Unbilled customer revenues(a)
ExelonGenerationComEdPECOBGEPHIPepcoDPLACE
June 30, 2021$1,029 $329 $263 $131 $119 $187 $90 $39 $58 
December 31, 2020998 258 218 147 197 178 87 62 29 
 
Unbilled customer revenues(a)
 Exelon Generation ComEd PECO BGE PHI Pepco DPL ACE
June 30, 2020$804
 $120
 $257
 $120
 $116
 $191
 $102
 $49
 $40
December 31, 20191,535
 807
 218
 146
 170
 194
 100
 61
 33
__________
_________(a)Unbilled customer revenues are classified in Customer accounts receivables, net in the Registrants' Consolidated Balance Sheets.
(a)Unbilled customer revenues are classified in customer accounts receivables, net in the Registrants' Consolidated Balance Sheets.
Sales of Customer Accounts Receivable (Exelon and Generation)
On April 8, 2020, NER, a bankruptcy remote, special purpose entity, which is wholly-owned by Generation, entered into a revolving accounts receivable financing arrangement with a number of financial institutions and a commercial paper conduit (the Purchasers) to sell certain customer accounts receivable (the Facility). The Facility whosehad a maximum capacity isfunding limit of $750 million isand was scheduled to expire on April 7, 2021, unless renewed by the mutual consent of the parties in accordance with its terms. UnderThe Facility was renewed on March 29, 2021. The Facility term was extended through March 29, 2024, unless further renewed by the mutual consent of the parties, and the maximum funding limit was increased to $900 million.Under the Facility, NER may sell eligible short-term customer accounts receivable to the Purchasers in exchange for cash and subordinated interest. The transfers are reported as sales of receivables in Exelon’s and Generation’s consolidated financial statements. The subordinated interest in collections upon the receivables sold to the Purchasers is referred to as the DPP, which is reflected in Other current assets on Exelon’s and Generation’s Consolidated Balance Sheet.Sheets.

82
TableThe Facility requires the balance of Contentseligible receivables to be maintained at or above the balance of cash proceeds received from the Purchasers. To the extent the eligible receivables decrease below such balance, Generation is required to repay cash to the Purchasers. When eligible receivables exceed cash proceeds, Generation has the ability to increase the cash received up to the maximum funding limit. These cash inflows and outflows impact the DPP.
COMBINED NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)
(Dollars in millions, except per share data, unless otherwise noted)

Note 5 — Accounts Receivable

On April 8, 2020, Generation derecognized and transferred approximatelyapproximately $1.2 billion of receivables at fair value to the Purchasers in exchange for approximately $500 million in cash purchase price and $650 million of DPP.DPP.
During the first quarter of 2021, Generation received additional cash of $250 million from the Purchasers for the remaining available funding in the Facility.
Additionally, during the first quarter of 2021, Generation received cash of approximately $150 million from the Purchasers in connection with the increased funding limit at the time of the Facility renewal.
During the second quarter of 2021, Generation returned cash of $50 million to the Purchasers due to the eligible receivables decreasing temporarily. Subsequently, in the second quarter, Generation received cash of $50 million from the Purchasers as a result of an increase in the eligible receivable balance. The $50 million cash outflow and inflow is included in the Collection of DPP line within Cash flows from investing activities in Exelon’s and Generation’s Consolidated Statements of Cash Flows.
87



COMBINED NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)
(Dollars in millions, except per share data, unless otherwise noted)

Note 6 — Accounts Receivable
The following table summarizes the impact of the sale of certain receivables:
June 30, 2021December 31, 2020
Derecognized receivables transferred at fair value$1,274 $1,139 
Cash proceeds received900 500 
DPP374 639 
 As of June 30, 2020
Derecognized receivables transferred at fair value(a)
$1,135
Cash proceeds received500
DPP635
Three Months Ended June 30,Six Months Ended June 30,
2021202020212020
Loss on sale of receivables(a)
$8 $15 $25 $15 
_________
(a)Includes additional customer accounts receivable sold into the Facility of $2,032 million since the start of the financing agreement.

__________
(a)Reflected in Operating and maintenance expense on Exelon's and Generation's Consolidated Statements of Operations and Comprehensive Income.
 Three and six months ended June 30, 2020
Loss on sale of receivables(a)

$15
Six Months Ended June 30,
20212020
Proceeds from new transfers(a)
$2,689 $927 
Cash collections received on DPP and reinvested in the Facility(b)
1,809 1,102 
Cash collections reinvested in the Facility4,498 2,029 
_________
(a)Reflected in Operating and maintenance expense on Exelon and Generation's Consolidated Statements of Operations and Income Statement.

__________
(a)Customer accounts receivable sold into the Facility were $4,647 million and $2,032 million for the six months ended June 30, 2021 and June 30, 2020, respectively
 Six months ended June 30, 2020
Proceeds from new transfers$927
Cash collections received on DPP1,102
Cash collections reinvested in the Facility2,029

(b)Does not include the $400 million in cash proceeds received from the Purchasers in the first quarter of 2021.
Generation’s risk of loss following the transfer of accounts receivable is limited to the DPP outstanding. Payment of DPP is not subject to significant risks other than delinquencies and credit losses on accounts receivable transferred, which have historically been and are expected to be immaterial. Generation continues to service the receivables sold in exchange for a servicing fee. Generation did not record a servicing asset or liability as the servicing fees were immaterial.
Generation reflectedrecognizes the cash proceeds received upon sale in Net cash provided by operating activities in the Consolidated Statements of Cash Flows. The collection and reinvestment of DPP is recognized in Net cash provided by investing activities of the Consolidated Statements of Cash Flows.
See Note 1314 — Fair Value of Financial Assets and Liabilities and Note 1617 — Variable Interest Entities for additional informationinformation.
88



COMBINED NOTES TO CONSOLIDATED FINANCIAL STATEMENTS .— (Continued)
(Dollars in millions, except per share data, unless otherwise noted)

Note 6 — Accounts Receivable
Other Purchases and Sales of Customer and Other Accounts Receivables (All Registrants)
Generation is required, under supplier tariffs in ISO-NE, MISO, NYISO, and PJM, to sell customer and other receivables to utility companies, which include the Utility Registrants. The Utility Registrants are required, under separate legislation and regulations in Illinois, Pennsylvania, Maryland, District of Columbia, Delaware, and New Jersey, to purchase certain receivables from alternative retail electric and, as applicable, natural gas suppliers that participate in the utilities' consolidated billing. The following tables present the total receivables purchased and sold.

Six Months Ended June 30, 2021
ExelonGenerationComEdPECOBGEPHIPepcoDPLACE
Total receivables purchased$1,823 $0 $485 $507 $343 $503 $310 $103 $90 
Total receivables sold92 107 0 0 0 0 0 0 0 
Related party transactions:
Receivables purchased from Generation— — 0 0 15 0 0 0 0 
Receivables sold to the Utility Registrants— 15 — — — — — — — 
83
Table of Contents
Six Months Ended June 30, 2020
ExelonGenerationComEdPECOBGEPHIPepcoDPLACE
Total receivables purchased$1,584 $0 $518 $494 $333 $485 $303 $98 $84 
Total receivables sold533 779 0 0 0 0 0 0 0 
Related party transactions:
Receivables purchased from Generation— — 34 67 73 72 51 13 8 
Receivables sold to the Utility Registrants— 246 — — — — — — — 
COMBINED NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)
(Dollars in millions, except per share data, unless otherwise noted)

Note 5 — Accounts Receivable

 Six Months Ended June 30, 2020
 Exelon Generation ComEd PECO BGE PHI Pepco DPL ACE
Total Receivables Purchased$1,584
 $—
 $518
 $494
 $333
 $485
 $303
 $98
 $84
Total Receivables Sold533
 779
 —
 —
 —
 —
 —
 —
 —
                  
Related Party Transactions:                 
Receivables purchased from Generation—
 —
 34
 67
 73
 72
 51
 13
 8
Receivables sold to the Utility Registrants—
 246
 —
 —
 —
 —
 —
 —
 —

6.7. Early Plant Retirements (Exelon and Generation)
Exelon and Generation continuously evaluate factors that affect the current and expected economic value of Generation’s plants, including, but not limited to: market power prices, results of capacity auctions, potential legislative and regulatory solutions to ensure plants are fairly compensated for benefits they provide through their carbon-free emissions, reliability, or fuel security, and the impact of potential rules from the EPA requiring reduction of carbon and other emissions and the efforts of states to implement those final rules. The precise timing of an early retirement date for any plant, and the resulting financial statement impacts, may be affected by many factors, including the status of potential regulatory or legislative solutions, results of any transmission system reliability study assessments, the nature of any co-owner requirements and stipulations, and NDT fund requirements for nuclear plants, among other factors. However, the earliest retirement date for any plant would usually be the first year in which the unit does not have capacity or other obligations, and where applicable, just prior to its next scheduled nuclear refueling outage.
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COMBINED NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)
(Dollars in millions, except per share data, unless otherwise noted)

Note 7 — Early Plant Retirements
Nuclear Generation
In 2015 and 2016, Generation identified the Clinton and Quad Cities nuclear plants in Illinois, Ginna and Nine Mile Point nuclear plants in New York, and Three Mile IslandTMI nuclear plant in Pennsylvania as having the greatest risk of early retirement based on economic valuation and other factors. In 2017, PSEG made public similar financial challenges facing its New Jersey nuclear plants, including Salem, of which Generation owns a 42.59% ownership interest. PSEG is the operator of Salem and also has the decision-making authority to retire Salem.
Assuming the continued effectiveness of the Illinois ZES, New Jersey ZEC program, and the New York CES, Generation and CENG, through its ownership of Ginna and Nine Mile Point, no longer consider Clinton, Quad Cities, Salem, Ginna, or Nine Mile Point to be at heightened risk for early retirement. However, to the extent the Illinois ZES, New Jersey ZEC program, or the New York CES do not operate as expected over their full terms, each of these plants, could againin addition to FitzPatrick, would be at heightened risk for early retirement, which could have a material impact on Exelon’s and Generation’s future financial statements. In addition, FERC’s December 19, 2019 order on the MOPR in PJM may undermine the continued effectiveness of the Illinois ZES and the New Jersey ZEC program unless PJM adopts further changes to the MOPR or Illinois and New Jersey implement an FRR mechanism under which the Generation plants in these states would be removed from PJM’s capacity auction. At the direction of the PJM Board of Managers, PJM and its stakeholders are considering MOPR reforms to ensure that the capacity market rules respect and accommodate state resource preferences such as the ZEC programs, which PJM filed at FERC on July 30, 2021. See Note 2 —3 - Regulatory Matters for additional information on the New Jersey ZEC program, Note 3 — Regulatory Matters of the 2020 Form 10-K for additional information on the Illinois ZES, New York CES and FERC's December 19, 2019 order and Note 3 — Regulatory Matters of the 2019 Form 10-K for additional information on the Illinois ZES.MOPR in PJM. We cannot predict whether or when FERC will act on PJM's proposed changes.
In Pennsylvania, the TMI nuclear plant did not clear in the May 2017 PJM capacity auction for the 2020-2021 planning year, the third consecutive year that TMI failed to clear the PJM base residual capacity auction and on May 30, 2017, based on these capacity auction results, prolonged periods of low wholesale power prices, and the absence of federal or state policies that place a value on nuclear energy for its ability to produce electricity without air pollution,On August 27, 2020, Generation announced that it wouldintends to permanently cease generation operations at TMI. OnByron in September 20, 2019, Generation permanently ceased generation operations2021 and at TMI.

Dresden in November 2021. The current NRC licenses for Byron Units 1 and 2 expire in 2044 and 2046, respectively, and the licenses for Dresden Units 2 and 3 expire in 2029 and 2031, respectively. Neither of these nuclear plants cleared in PJM’s capacity auction for the 2022-2023 planning year held in May 2021.
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COMBINED NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)
(Dollars in millions, except per share data, unless otherwise noted)

Note 67 — Early Plant Retirements

As a result of the early nuclear plant retirement decision at TMI, ExelonGeneration’s Braidwood and Generation recognized incremental non-cash charges to earnings stemming from shortening the expected economic useful lives primarily related to accelerated depreciation of plant assets (including any ARC) and accelerated amortization of nuclear fuel, as well as operating and maintenance expenses. The total impact for the three and six months ended June 30, 2019 are summarized in the table below.
Income statement expense (pre-tax) Three Months Ended June 30, 2019 Six Months Ended June 30, 2019
Depreciation and amortization    
Accelerated depreciation $71
 $145
Accelerated nuclear fuel amortization 4
 9
Operating and maintenance(a)
 —
 (83)
Total $75
 $71
_________
(a)Primarily reflects the net impacts associated with the remeasurement of the TMI ARO. See Note 9 — Asset Retirement Obligations of the 2019 Form 10-K for additional information.
Generation’s Dresden, Byron and BraidwoodLaSalle nuclear plants in Illinois are also showing increased signs of economic distress, which could lead to an early retirement, in a market that does not currently compensate them for their unique contribution to grid resiliency and their ability to produce large amounts of energy without carbon and air pollution. The May 2018 PJM capacity auction for the 2021-2022 planning year resulted in the largest volume of nuclear capacity ever not selected in the auction, includingWhile all of Dresden,Braidwood's and portions of Byron and Braidwood. While all of LaSalle's capacity did clear in the 2021-20222022-2023 planning year auction, Generation has become increasingly concerned about the economic viability of this plantthese plants as well in a landscape where energy market prices remain depressed and energy market rules remain fatally flawed.
As a result of the decision to early retire Byron and Dresden, Exelon and Generation recognized certain one-time charges in the third and fourth quarters of 2020 related to materials and supplies inventory reserve adjustments, employee-related costs including severance benefit costs further discussed below, and construction work-in-progress impairments, among other items. In addition, as a result of the decisions to early retire Byron and Dresden, there are ongoing annual financial impacts stemming from shortening the expected economic useful lives of these nuclear plants primarily related to accelerated depreciation of plant assets (including any ARC), accelerated amortization of nuclear fuel, and changes in ARO accretion expense associated with the changes in decommissioning timing and cost assumptions to reflect an earlier retirement date. The total impact for the three and six months ended June 30, 2021 on Exelon's and Generation's Consolidated Statements of Operations and Comprehensive Income is summarized in the table below.
Income statement expense (pre-tax)
Three Months Ended June 30, 2021(a)
Six Months Ended June 30, 2021(a)
Depreciation and amortization
     Accelerated depreciation(a)
$611 $1,230 
     Accelerated nuclear fuel amortization52 106 
Operating and maintenance
     Other charges2 4 
     Contractual offset(b)
(166)(391)
Total$499 $949 
_________
(a)Includes the accelerated depreciation of plant assets including any ARC.
(b)Reflects contractual offset for ARO accretion and ARC depreciation and excludes any changes in earnings in the NDT funds. Decommissioning-related impacts were not offset for the Byron units starting in the second quarter of 2021 due to the inability to recognize a regulatory asset at ComEd. 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. The offset resulted in an equal adjustment to the noncurrent payables to ComEd at Generation and an adjustment to the regulatory liabilities at ComEd. See Note 8 - Nuclear Decommissioning for additional information.
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COMBINED NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)
(Dollars in millions, except per share data, unless otherwise noted)

Note 7 — Early Plant Retirements
Severance benefit costs will be provided to employees impacted by the early retirements of Byron and Dresden, to the extent they are not redeployed to other nuclear plants. In 2020, Exelon and Generation recorded estimated severance expense of $81 million within Operating and maintenance expense in their Consolidated Statements of Operations and Comprehensive Income. The severance liability was $81 million as of June 30, 2021 on Exelon's and Generation's Consolidated Balance Sheets. The final amount of severance benefit costs will depend on the specific employees severed.
The following table provides the balance sheet amounts as of June 30, 2021 for Exelon's and Generation's significant assets and liabilities associated with the Braidwood and LaSalle nuclear plants. Current depreciation provisions are based on the estimated useful lives of these nuclear generating stations, which reflect the first renewal of the operating licenses.
BraidwoodLaSalleTotal
Asset Balances
Materials and supplies inventory, net$82 $105 $187 
Nuclear fuel inventory, net196 244 440 
Completed plant, net1,380 1,610 2,990 
Construction work in progress30 12 42 
Liability Balances
Asset retirement obligation(585)(975)(1,560)
NRC License First Renewal Term2046 (Unit 1)2042 (Unit 1)
2047 (Unit 2)2043 (Unit 2)
Exelon continues to work with stakeholders on state policy solutions, while also advocating for broader market reforms at the regional and federal level. The absence of such solutions or reforms could result in future impairments of the Midwest asset group, or accelerated depreciation for specific plants over their shortened estimated useful lives, both of which could have a material unfavorable impact on Exelon's and Generation's future results of operations.
The following table provides the balance sheet amounts as of June 30, 2020 for Exelon's and Generation's significant assets and liabilities associated with these four nuclear plants. Depreciation provisions are based on the estimated useful lives of these nuclear generating stations, which reflect the first renewal of the operating licenses.
  Dresden Byron Braidwood LaSalle Total
Asset Balances          
Materials and supplies inventory, net $70
 $70
 $82
 $108
 $330
Nuclear fuel inventory, net 182
 145
 180
 244
 751
Completed plant, net 1,057
 1,334
 1,416
 1,588
 5,395
Construction work in progress 18
 21
 18
 19
 76
Liability Balances          
Asset retirement obligation (1,317) (604) (562) (915) (3,398)
           
NRC License First Renewal Term 2029 (Unit 2)
 2044 (Unit 1)
 2046 (Unit 1)
 2042 (Unit 1)
  
 2031 (Unit 3)
 2046 (Unit 2)
 2047 (Unit 2)
 2043 (Unit 2)
  

Other Generation
OnIn March 29, 2018, Generation notified grid operator ISO-NE of its plans to early retire, itsamong other assets, the Mystic UnitsGenerating Station's units 8 and 9 (Mystic 8 and 9) absent regulatory reforms onto properly value reliability and regional fuel security. Thereafter, ISO-NE identified Mystic 8 and 9 as being needed to ensure fuel security for the region and entered into a cost of service agreement with these two units for the period between June 1, 2022 - May 31, 2024. The agreement was approved by the FERC in December 2018.
On June 10, 2020, Generation filed a complaint with FERC against ISO-NE stating that ISO-NE failed to follow its tariff with respect to its evaluation of Mystic 8 and 9 for transmission security for the 2024 to 2025 Capacity Commitment Period and that the modifications that ISO-NE made to its unfiled planning procedures to avoid retaining Mystic 8 and 9 should have been filed with FERC for approval. On August 17, 2020, FERC issued an order denying the complaint. As a result, on August 20, 2020, Exelon determined that Generation will permanently cease generation operations at Mystic 8 and 9 at the endexpiration of the then-current capacitycost of service commitment in May 2024. See Note 3 — Regulatory Matters for additional discussion of Mystic’s cost of service agreement.
As a result of the decision to early retire Mystic Units 78 and 8.9, there are financial impacts stemming from shortening the expected economic useful life of Mystic Unit8 and 9 was then committed through May 2021.primarily related to accelerated depreciation of plant assets. Exelon and Generation recorded incremental Depreciation and amortization expense of $21 million and $41 million for the three and six months ended June 30, 2021, respectively.

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COMBINED NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)
(Dollars in millions, except per share data, unless otherwise noted)

Note 6 — Early Plant Retirements

On May 16, 2018, Generation made a filing with FERC to establish cost-of-service compensation and terms and conditions of service for Mystic Units 8 and 9 for the period between June 1, 2022 - May 31, 2024. On December 20, 2018, FERC issued an order accepting the cost of service agreement, reflecting a number of adjustments to the annual fixed revenue requirement and allowing for recovery of a substantial portion of the costs associated with the Everett Marine Terminal. Those adjustments were reflected in a compliance filing filed March 1, 2019. In the December 20, 2018 order, FERC also directed a paper hearing on ROE using a new methodology. On January 22, 2019, Exelon and several other parties filed requests for rehearing of certain findings in the order. On July 17, 2020, FERC issued three orders, which together affirmed the recovery of key elements of Mystic's cost of service compensation, including recovery of costs associated with the operation of the Everett Marine Terminal. FERC directed a downward adjustment to the rate base for Mystic Units 8 and 9, the effect of which will be partially offset by elimination of a crediting mechanism for third party gas sales during the term of the cost of service agreement. A compliance filing will be due on September 15, 2020. On July 28, 2020, FERC ordered additional briefings in the ROE proceeding, with initial briefs due by September 28, 2020.
On March 25, 2019, ISO-NE filed the Inventoried Energy Program (IEP), which is intended to provide an interim fuel security program pending conclusion of the stakeholder process to develop a long-term, market-based solution to address fuel security. The IEP went into effect by operation of law on August 5, 2019 because FERC did not have a quorum at that time. On October 7, 2019, requests for rehearing were denied and several parties appealed to the D.C. Circuit Court. On April 14, 2020, FERC filed an unopposed motion asking the court for a voluntary remand of the IEP order, noting that FERC now has a quorum of commissioners who can participate in the consideration of ISO-NE’s IEP filing. On April 21, 2020, the D.C. Circuit Court granted the voluntary remand and on June 18, 2020, FERC issued an order finding the IEP just and reasonable and accepting ISO-NE's proposed tariff revisions. Several parties have filed requests for rehearing.
On April 15, 2020, ISO-NE filed its long-term, market-based fuel security proposal, proposing three new, day-ahead ancillary services products intended to compensate generators for operational capabilities that provide fuel security to the region. In the filing, ISO-NE also proposed to sunset the Fuel Security Retention Mechanism, through which Mystic has been retained for fuel security, and the IEP by June 1, 2024. In addition, the filing includes an alternate proposal sponsored by New England Power Pool (NEPOOL), which includes substantive amendments to the ISO-NE proposal. On May 15, 2020, Exelon filed a limited protest to ISO's long-term fuel-security proposal asking FERC to accept ISO-NE's proposal but to direct ISO-NE to revise its tariff so that the IEP remains in place as a safeguard until the long-term solution is in place. A number of other comments in support and protests have been filed. ISO-NE asked for a decision on its proposal by November 1, 2020.
On June 12, 2020, Generation filed a complaint with FERC against ISO-NE on the grounds that ISO-NE failed to follow its tariff with respect to its evaluation of Mystic for transmission security for the 2024 to 2025 Capacity Commitment Period (FCA 15) and that modifications ISO-NE made to its unfiled planning procedures to avoid retaining Mystic should have been filed with FERC for approval. Generation asked for a ruling from FERC by August 10, 2020, but ISO-NE asserts that a ruling is not needed until November 2, 2020. On July 27, 2020, ISO-NE issued a memo to NEPOOL announcing its determination pursuant to its unfiled planning procedures that Mystic Units 8 and 9 are not needed for FCA 15 for transmission security. It had previously determined Mystic Units 8 and 9 are not needed for fuel security. The timing and the outcome of this proceeding is uncertain.
The following table provides the balance sheet amounts as of June 30, 2020 for Exelon's and Generation’s significant assets and liabilities associated with the Mystic Units 8 and 9 and Everett Marine Terminal assets that would potentially be impacted by the failure to adopt long-term solutions for reliability and fuel security.
  June 30, 2020
Asset Balances  
Materials and supplies inventory $33
Fuel inventory 6
Property, plant and equipment, net 898
Liability Balances  
Asset retirement obligation (3)

See Note 8 — Asset Impairments for impairment assessment considerations on the New England Asset Group.

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

Note 7 — Nuclear Decommissioning

7.8. Nuclear Decommissioning (Exelon and Generation)
Nuclear Decommissioning Asset Retirement Obligations
Generation has a legal obligation to decommission its nuclear power plants following the expiration of their operating licenses. To estimate its decommissioning obligation related to its nuclear generating stations for financial accounting and reporting purposes, Generation uses a probability-weighted, discounted cash flow model which, on a unit-by-unit basis, considers multiple outcome scenarios that include significant estimates and assumptions, and are based on decommissioning cost studies, cost escalation rates, probabilistic cash flow models, and discount rates. Generation updates its ARO annually, unless circumstances warrant more frequent updates, based on its review of updated cost studies and its annual evaluation of cost escalation factors and probabilities assigned to various scenarios.
The financial statement impact for changes in the ARO, on an individual unit basis, due to the changes in and timing of estimated cash flows generally result in a corresponding change in the unit’s ARC within Property, plant, and equipment on Exelon’s and Generation’s Consolidated Balance Sheets. If the ARO decreases for a Non-Regulatory Agreement unit without any remaining ARC, the corresponding change is recorded as decrease in Operating and maintenance expense within Exelon’s and Generation’s Consolidated Statements of Operations and Comprehensive Income.
The following table provides a rollforward of the nuclear decommissioning ARO reflected in Exelon’s and Generation’s Consolidated Balance Sheets from December 31, 20192020 to June 30, 2020:2021:
Nuclear decommissioning ARO at December 31, 2019 (a)
$10,504
Accretion expense243
Costs incurred related to decommissioning plants$(37)
Nuclear decommissioning ARO at June 30, 2020 (a)
$10,710
_________
Nuclear decommissioning ARO at December 31, 2020(a)
$11,922 
Accretion expense249 
(a)Costs incurred related to decommissioning plantsIncludes $104 million and $112 million as the current portion of the(39)
Nuclear decommissioning ARO at June 30, 2020 and December 31, 2019, respectively, which is included in Other current liabilities in Exelon’s and Generation’s Consolidated Balance Sheets.2021(a)
$12,132 

_________
(a)Includes $84 million and $80 million as the current portion of the ARO at June 30, 2021 and December 31, 2020, which is included in Other current liabilities in Exelon’s and Generation’s Consolidated Balance Sheets.
On July 28, 2021 Generation submitted PSDAR filings for the Byron and Dresden nuclear units, selecting the SAFSTOR decommissioning approach that allows for up to 60 years in duration, with certain aspects of the specific approach unique to each unit. Based on the approaches selected, and assuming the Byron and Dresden units retire as previously announced in September 2021 and November 2021, respectively, Generation expects to record an incremental increase in the nuclear decommissioning ARO of $650 million to $850 million in the second half of 2021. As discussed further below, contractual offset for the Byron units has been suspended and $275 million to $375 million of this increase in the ARO would result in a pre-tax charge in Exelon’s and Generation’s Consolidated Statements of Operations and Comprehensive Income.
NDT Funds
Exelon and Generation had NDT funds totaling $12,917$15,596 million and $13,353$14,599 million at June 30, 20202021 and December 31, 2019,2020, respectively. The NDT funds also include $187$196 million and $163$134 million for the current portion of the NDT funds at June 30, 20202021 and December 31, 2019,2020, respectively, which are included in Other current assets in Exelon's and Generation's Consolidated Balance Sheets. See Note 1718 — Supplemental Financial Information for additional information on activities of the NDT funds.
Accounting Implications of the Regulatory Agreements with ComEd and PECO
Based on the regulatory agreements with the ICC and PAPUC that dictate Generation’s obligations related to the shortfall or excess of NDT funds necessary for decommissioning the former ComEd units on a unit-by-unit basis and the former PECO units in total, decommissioning-related activities net of applicable taxes, including realized and unrealized gains and losses on the NDT funds, depreciation of the ARC, and accretion of the decommissioning obligation, are generally offset within Exelon’s and Generation’s Consolidated Statements of Operations and Comprehensive Income and are recorded by Generation and the corresponding regulated utility as a component of the intercompany and regulatory balances on the balance sheet. For the purposes of making this determination, the decommissioning obligation referred to is different from the calculation used in the NRC minimum funding obligation filings based on NRC guidelines.
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(Dollars in millions, except per share data, unless otherwise noted)

Note 8 — Nuclear Decommissioning
For the former ComEd units, given no further recovery from ComEd customers is permitted and Generation retains an obligation to ultimately return any unused NDTs to ComEd customers (on a unit-by-unit basis), to the extent the related NDT investment balances are expected to exceed the total estimated decommissioning obligation for each unit, the offset of decommissioning-related activities within the Consolidated Statements of Operations and Comprehensive Income results with Generation recognizing an intercompany payable to ComEd while ComEd records an intercompany receivable from Generation with a corresponding regulatory liability. However, given the asymmetric settlement provision that does not allow for continued recovery from ComEd customers in the event of a shortfall, recognition of a regulatory asset at ComEd is not permissible and accounting for decommissioning-related activities at Generation for that unit would not be offset, and the impact to Exelon’s and Generation’s Consolidated Statements of Operations and Comprehensive Income could be material during such periods. During the second quarter of 2021, a pre-tax charge of $53 million was recorded in Exelon’s and Generation’s Consolidated Statements of Operations and Comprehensive Income for decommissioning-related activities that were not offset for the Byron units due to contractual offset being suspended.Generation believes that additional growth of the NDT funds for the Byron units will ultimately be sufficient to cover the future costs of decommissioning.
As of June 30, 2021, decommissioning-related activities for all of the former ComEd units, except for Byron (see discussion above) and Zion (see Note 10 – Asset Retirement Obligations of the Exelon 2020 Form 10-K), are currently offset within Exelon’s and Generation’s Consolidated Statements of Operations and Comprehensive Income.
The decommissioning-related activities related to the Non-Regulatory Agreement Units are reflected in Exelon’s and Generation’s Consolidated Statements of Operations and Comprehensive Income.
See Note 10 – Asset Retirement Obligations of the Exelon 2020 Form 10-K for additional information, including the former PECO units.
NRC Minimum Funding Requirements
NRC regulations require that licensees of nuclear generating facilities demonstrate reasonable assurance that funds will be available in specified minimum amounts to decommission the facility at the end of its life.
Generation filed its biennial decommissioning funding status report with the NRC on April 1, 2019February 24, 2021 for all units, including its shutdown units, except for Zion Station which is included in a separate report to the NRC submitted by ZionSolutions, LLC. The status report demonstrated adequate decommissioning funding assurance as of December 31, 20182020 for all units except for ClintonByron Units 1 and Peach Bottom Unit 1. As2. Prior to shutdown, Generation will supplement its July 28, 2021 PSDAR filing with decommissioning cost information for Byron Units 1 and 2 and will evaluate the status of February 28, 2019, Clinton demonstrated adequate minimum funding assurance duebased on this cost information and updated trust fund values. If required, Generation intends to market recovery and no further action is required. This demonstration was also included inprovide additional funding assurance by the April 1, 2019 submittal. On March 31, 2020, time of shutdown.
Generation filedwill file its annualnext decommissioning funding status report with the NRC for Generation’s shutdown units (excluding Zion Station forby March 31, 2022. This report will reflect the reason noted above). The annual status report demonstrated adequateof decommissioning funding assurance as of December 31, 2019,2021 for all of its shutdown reactors except for Peach Bottom Unit 1. As a former PECO plant, financial assurance for decommissioning Peach Bottom Unit 1 is provided by the NDT fund, collections from PECO ratepayers, and the ability to adjust those collections in accordance with the approved PAPUC tariff. No additional actions are required aside from the PAPUC filing in accordance with the tariff.  See Note 9 — Asset Retirement

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COMBINED NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)
(Dollars in millions, except per share data, unless otherwise noted)

Note 7 — Nuclear Decommissioning

Obligations of the Exelon 2019 Form 10-K for information regarding the amount collected from PECO ratepayers for decommissioning cost.
8.9. Asset Impairments (Exelon and Generation)
The Registrants evaluate the carrying value of long-lived assets or asset groups for recoverability whenever events or changes in circumstances indicate that the carrying value of those assets may not be recoverable. Indicators of impairment may include a deteriorating business climate, including, but not limited to, declines in energy prices, condition of the asset, specific regulatory disallowance, or plans to dispose of a long-lived asset significantly before the end of its useful life. The Registrants determine if long-lived assets or asset groups are impaired by comparing the undiscounted expected future cash flows to the carrying value. When the undiscounted cash flow analysis indicates a long-lived asset or asset group is not recoverable, the amount of the impairment loss is determined by measuring the excess of the carrying amount of the long-lived asset or asset group over its fair value. The fair value analysis is primarily based on the income approach using significant unobservable inputs (Level 3) including revenue and generation forecasts, projected capital and maintenance expenditures, and discount rates. A variation in the assumptions used could lead to a different conclusion
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(Dollars in millions, except per share data, unless otherwise noted)

Note 9 — Asset Impairments
regarding the recoverability of an asset or asset group and, thus, could potentially result in material future impairments of the Registrant's long-lived assets.
Antelope Valley Solar Facility
Generation’s Antelope Valley, a 242 MW solar facility in Lancaster, CA, sells all of its output to PG&E through a PPA. As of June 30, 2020, Generation had approximately $710 million of net long-lived assets related to Antelope Valley. As a result of the PG&E bankruptcy filing in the first quarter of 2019, Generation completed a comprehensive review of Antelope Valley's estimated undiscounted future cash flows and no impairment charge was recorded.
Antelope Valley is a wholly owned indirect subsidiary of EGR IV, which had approximately $1,840 million of additional net long-lived assets as of June 30, 2020. EGR IV is a wholly owned indirect subsidiary of Exelon and Generation and includes Generation's interest in EGRP and other projects with non-controlling interests. To date, there have been no indicators to suggest that the carrying amount of other net long-lived assets of EGR IV may not be recoverable.
The United States Bankruptcy Court entered an order on June 20, 2020 confirming PG&E’s plan of reorganization. On July 1, 2020 the plan became effective, and PG&E emerged from bankruptcy. Under the confirmed plan, PG&E will continue to honor the existing PPA agreement with Antelope Valley.
See Note 12 - Debt and Credit Agreements for additional information.
New England Asset Group
DuringIn the firstthird quarter of 2018,2020, in conjunction with the retirement announcement of Mystic UnitUnits 8 and 9, did not clearGeneration, recorded a pre-tax impairment charge of $500 million for the New England asset group. See Note 12 - Asset Impairments of the Exelon 2020 Form 10-K for additional information. In the second quarter of 2021, an overall decline in the ISO-NE capacity auction for the 2021 - 2022 planning year. On March 29, 2018, Generation notified ISO-NE of the early retirement of its Mystic Generating Station's Units 7, 8, 9 and the Mystic Jet Unit (Mystic Generating Station assets) absent regulatory reforms. These eventsasset group's portfolio value suggested that the carrying value of itsthe New England asset group may be impaired. In the second quarter of 2018, Generation completed a comprehensive review of the estimated undiscounted future cash flows of the New England asset group and noconcluded that the carrying value was not recoverable and that its fair value was less than its carrying value. As a result, a pre-tax impairment charge of $350 million was required. Generation continues to monitor developmentsrecorded in the region that would indicate a potential triggering event for impairmentsecond quarter of 2021 within Operating and continues to look for solutions that appropriately compensate both Mystic 8maintenance expense in Exelon’s and 9Generation’s Consolidated Statements of Operations and the Everett Marine Terminal for their contributions to the region. Further developments such as the failure of ISO-NE to adopt long-term solutions for reliability and fuel security could potentially result in material future impairments of the New England asset group. See Note 6 - Early Plant Retirements for additional information.Comprehensive Income.
Midwest Asset Group
WeGeneration will continue to monitor the recoverability of the carrying value of the Midwest asset group as certain nuclear plantscircumstances continue to evolve in Illinois are showing increased signs of economic distress, which could lead to an early retirement.Illinois. See Note 6 -7 — Early Plant Retirements for additional information.

10. Income Taxes (All Registrants)
Rate Reconciliation
The effective income tax rate from continuing operations varies from the U.S. federal statutory rate principally due to the following:
Three Months Ended June 30, 2021
Exelon(a)
Generation(a)
ComEd(a)
PECO(a)
BGE(a)(b)
PHI(a)
Pepco(a)
DPL(a)
ACE(a)
U.S. Federal statutory rate21.0%21.0%21.0%21.0%21.0%21.0%21.0%21.0%21.0%
Increase (decrease) due to:
State income taxes, net of Federal income tax benefit1.4(1.3)8.0(2.9)(12.5)2.4(2.1)7.08.1
Qualified NDT fund income17.985.20000000
Amortization of investment tax credit, including deferred taxes on basis difference0(1.8)(0.1)0(0.1)(0.1)0(0.2)(0.2)
Plant basis differences(3.1)0(0.7)(12.5)(2.3)(1.1)(1.5)(0.7)(0.6)
Production tax credits and other credits(1.9)(13.0)(0.8)0(3.6)(0.8)(0.7)(0.9)(0.6)
Noncontrolling interests(0.9)(4.2)0000000
Excess deferred tax amortization(10.4)0(7.0)(3.3)(17.5)(22.3)(19.0)(21.9)(28.2)
Other(10.6)2.8(1.1)(0.4)(6.6)(1.3)(1.9)(1.1)(2.3)
Effective income tax rate13.4%88.7%19.3%1.9%(21.6)%(2.2)%(4.2)%3.2%(2.8)%

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

Note 910 — Income Taxes

Three Months Ended June 30, 2020
Exelon(a)
Generation(a)
ComEd(c)
PECO(d)
BGE(d)
PHI(d)
Pepco(d)
DPL(e)
ACE(e)
U.S. Federal statutory rate21.0%21.0%21.0%21.0%21.0%21.0%21.0%21.0%21.0%
Increase (decrease) due to:
State income taxes, net of Federal income tax benefit3.83.1(131.7)(9.7)3.8(25.8)2.16.77.2
Qualified NDT fund income18.817.30000000
Deferred Prosecution Agreement payments5.30(288.3)000000
Amortization of investment tax credit, including deferred taxes on basis difference(0.6)(0.5)2.90(0.2)(2.2)(0.1)0.50.3
Plant basis differences(1.6)02.4(23.6)(13.4)(44.7)(3.9)(1.1)10.0
Production tax credits and other credits(1.4)(1.2)3.30(1.0)(0.7)(0.1)0.10
Noncontrolling interests0.10.10000000
Excess deferred tax amortization(15.5)0116.0(4.8)(137.9)(1,358.5)(89.0)284.0174.5
Tax Settlements(1.9)(1.8)0000000
Other(f)
(0.4)0.3(32.3)(4.8)(1.7)168.0(2.7)(0.1)7.0
Effective income tax rate27.6%38.3%(306.7)%(21.9)%(129.4)%(1,242.9)%(72.7)%311.1%220.0%
9. Income Taxes (All Registrants)__________
Rate Reconciliation
The effective(a)Positive percentages represent income tax rate from continuing operations varies fromexpense. Negative percentages represent income tax benefit.
(b)For BGE, the U.S. Federal statutory rate principallyincome tax benefit is primarily due to the following:Maryland multi-year plan which resulted in the acceleration of certain income tax benefits.
(c)ComEd recognized a loss before income taxes for the three months ended June 30, 2020. As a result, negative percentages represent income tax expense. The higher effective tax rate is primarily related to the nondeductible Deferred Prosecution Agreement payments.
(d)At PECO, BGE, PHI, and Pepco, negative percentages represent an income tax benefit. At PECO, the lower effective tax rate is primarily related to an increase in plant basis differences attributable to storm repairs. At BGE, PHI, and Pepco, the lower effective tax rate is primarily attributable to accelerated amortization of transmission related deferred income tax regulatory liabilities as a result of regulatory settlements.
(e)DPL and ACE recognized a loss before income taxes for the three months ended June 30, 2020. As a result, positive percentages represent an income tax benefit. At DPL and ACE, the higher effective tax rate is primarily attributable to accelerated amortization of transmission related deferred income tax regulatory liabilities as a result of regulatory settlements.
(f)For Exelon, "Other" is primarily driven by the reversal of the consolidating income tax adjustment recorded at Exelon Corporate in the first quarter of 2021 that was required pursuant to GAAP interim reporting guidance.
96
 Three Months Ended June 30, 2020
 
Exelon(a)

Generation(a)

ComEd(b)

PECO(c)

BGE(c)
 
PHI(c)
 
Pepco(c)
 
DPL(d)
 
ACE(d)
U.S. Federal statutory rate21.0% 21.0% 21.0% 21.0% 21.0% 21.0% 21.0% 21.0% 21.0%
Increase (decrease) due to:                 
State income taxes, net of Federal income tax benefit3.8 3.1 (131.7) (9.7) 3.8 (25.8) 2.1 6.7 7.2
Qualified NDT fund income18.8 17.3 — — — — — — —
Deferred Prosecution Agreement payments5.3 — (288.3) — — — — — —
Amortization of investment tax credit, including deferred taxes on basis difference(0.6) (0.5) 2.9 — (0.2) (2.2) (0.1) 0.5 0.3
Plant basis differences(1.6) — 2.4 (23.6) (13.4) (44.7) (3.9) (1.1) 10.0
Production tax credits and other credits(1.4) (1.2) 3.3 — (1.0) (0.7) (0.1) 0.1 —
Noncontrolling interests0.1 0.1 — — — — — — —
Excess deferred tax amortization(15.5) — 116.0 (4.8) (137.9) (1,358.5) (89.0) 284.0 174.5
Tax Settlements(1.9) (1.8) — — — — — — —
Other(0.4) 0.3 (32.3) (4.8) (1.7) 168.0 (2.7) (0.1) 7.0
Effective income tax rate27.6% 38.3% (306.7)% (21.9)% (129.4)% (1,242.9)% (72.7)% 311.1% 220.0%

_________
(a)At Exelon and Generation, positive percentages represent income tax expense.
(b)ComEd recognized a loss before income taxes for the three months ended June 30, 2020. As a result, negative percentages represent income tax expense. The higher effective tax rate is primarily related to the nondeductible Deferred Prosecution Agreement payments. See Note 14 — Commitments and Contingencies for additional information.
(c)At PECO, BGE, PHI, and Pepco, negative percentages represent an income tax benefit. At PECO, the lower effective tax rate is primarily related to an increase in plant basis differences attributable to storm repairs. At BGE, PHI, and Pepco, the lower effective tax rate is primarily attributable to accelerated amortization of transmission related deferred income tax regulatory liabilities as a result of regulatory settlements. See Note 2 — Regulatory Matters for additional information.
(d)DPL and ACE recognized a loss before income taxes for the three months ended June 30, 2020. As a result, positive percentages represent an income tax benefit. At DPL and ACE, the higher effective tax rate is primarily attributable to accelerated amortization of transmission related deferred income tax regulatory liabilities as a result of regulatory settlements. See Note 2 — Regulatory Matters for additional information.




89
COMBINED NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)
(Dollars in millions, except per share data, unless otherwise noted)

Note 910 — Income Taxes
Six Months Ended June 30, 2021
Exelon(a)
Generation(b)
ComEd(a)
PECO(a)(d)
BGE(a)(c)
PHI(a)
Pepco(a)
DPL(a)
ACE(a)
U.S. Federal statutory rate21.0%21.0%21.0%21.0%21.0%21.0%21.0%21.0%21.0%
Increase (decrease) due to:
State income taxes, net of Federal income tax benefit(12.6)5.37.4(2.1)(10.5)4.21.56.67.8
Qualified NDT fund income56.2(18.3)0000000
Amortization of investment tax credit, including deferred taxes on basis difference(2.5)0.7(0.1)0(0.1)(0.1)0(0.2)(0.2)
Plant basis differences(15.7)0(0.6)(11.3)(1.6)(1.3)(1.8)(0.7)(0.7)
Production tax credits and other credits(11.0)2.9(0.5)0(0.9)(0.5)(0.5)(0.4)(0.5)
Noncontrolling interests(2.5)0.80000000
Excess deferred tax amortization(50.9)0(7.0)(3.3)(15.9)(20.8)(17.2)(19.7)(28.3)
Other(e)
38.5(3.9)(2.3)(0.1)(1.0)(0.7)(0.8)(0.1)(1.1)
Effective income tax rate20.5%8.5%17.9%4.2%(9.0)%1.8%2.2%6.5%(2.0)%

Six Months Ended June 30, 2020
Exelon(a)
Generation(a)
ComEd(a)(g)
PECO(a)(d)
BGE(a)(h)
PHI(a)(h)
Pepco(a)(h)
DPL(a)(h)
ACE(i)
U.S. Federal statutory rate21.0%21.0%21.0%21.0%21.0%21.0%21.0%21.0%21.0%
Increase (decrease) due to:
State income taxes, net of Federal income tax benefit6.77.219.1(1.6)5.64.33.76.512.4
Qualified NDT fund income(5.7)(16.0)0000000
Deferred Prosecution Agreement payments4.8022.2000000
Amortization of investment tax credit, including deferred taxes on basis difference(1.0)(2.3)(0.4)0(0.1)(0.2)(0.1)(0.3)7.2
Plant basis differences(3.7)0(1.4)(11.0)(2.0)(3.5)(2.7)(0.6)146.2
Production tax credits and other credits(2.2)(5.5)(0.4)0(0.2)(0.1)(0.1)00.7
Noncontrolling interests1.13.20000000
Excess deferred tax amortization(20.9)0(20.2)(3.3)(16.1)(80.3)(41.6)(72.9)2,613.8
Tax Settlements(f)
(9.3)(26.1)0000000
Other0.7(0.3)3.5(0.3)(0.6)(1.5)(1.3)0.8398.7
Effective income tax rate(8.5)%(18.8)%43.4%4.8%7.6%(60.3)%(21.1)%(45.5)%3,200.0%
__________
(a)Positive percentages represent income tax expense. Negative percentages represent income tax benefit.
(b)Generation recognized a loss before income taxes for the six months ended June 30, 2021. As a result, positive percentages represent an income tax benefit for the period presented.
(c)For BGE, the income tax benefit is primarily due to the Maryland multi-year plan which resulted in the acceleration of certain income tax benefits.
(d)For PECO, the lower effective tax rate is primarily attributable to plant basis differences attributable to tax repairs.
(e)For Exelon, "Other" is primarily driven by the consolidating income tax adjustment recorded at Exelon Corporate in the first quarter of 2021 that was required pursuant to GAAP interim reporting guidance. This incremental expense will reverse by year-end and will not have an impact on annual results.
97
 Three Months Ended June 30, 2019
 Exelon Generation ComEd PECO BGE PHI Pepco DPL ACE
U.S. Federal statutory rate21.0% 21.0% 21.0% 21.0% 21.0% 21.0% 21.0% 21.0% 21.0%
Increase (decrease) due to:                 
State income taxes, net of Federal income tax benefit5.4 5.5 8.2 (1.2) 6.5 4.8 2.0 7.0 7.0
Qualified NDT fund income5.1 16.2 — — — — — — —
Amortization of investment tax credit, including deferred taxes on basis difference(0.7) (1.9) (0.2) — (0.1) (0.2) (0.1) (0.2) (0.3)
Plant basis differences(1.7) — (0.6) (5.9) (1.5) (1.7) (2.1) (0.3) (2.2)
Production tax credits and other credits(0.9) (2.8) — — (0.1) — — — —
Noncontrolling interests0.1 0.4 — — — — — — —
Excess deferred tax amortization(7.8) — (9.0) (2.7) (7.9) (19.4) (18.3) (15.7) (23.1)
Other1.9 0.2 0.4 0.1 1.7 0.9 0.5 — (2.4)
Effective income tax rate22.4% 38.6% 19.8% 11.3% 19.6% 5.4% 3.0% 11.8% —%




90
COMBINED NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)
(Dollars in millions, except per share data, unless otherwise noted)

Note 910 — Income Taxes

 Six Months Ended June 30, 2020
 Exelon 
Generation(a)
 
ComEd(b)
 
PECO(c)
 
BGE(d)
 
PHI(d)
 
Pepco(d)
 
DPL(d)
 
ACE(e)
U.S. Federal statutory rate21.0% 21.0% 21.0% 21.0% 21.0% 21.0% 21.0% 21.0% 21.0%
Increase (decrease) due to:                 
State income taxes, net of Federal income tax benefit6.7 7.2 19.1 (1.6) 5.6 4.3 3.7 6.5 12.4
Qualified NDT fund income(5.7) (16.0) — — — — — — —
Deferred Prosecution Agreement payments4.8 — 22.2 — — — — — —
Amortization of investment tax credit, including deferred taxes on basis difference(1.0) (2.3) (0.4) — (0.1) (0.2) (0.1) (0.3) 7.2
Plant basis differences(3.7) — (1.4) (11.0) (2.0) (3.5) (2.7) (0.6) 146.2
Production tax credits and other credits(2.2) (5.5) (0.4) — (0.2) (0.1) (0.1) — 0.7
Noncontrolling interests1.1 3.2 — — — — — — —
Excess deferred tax amortization(20.9) — (20.2) (3.3) (16.1) (80.3) (41.6) (72.9) 2,613.8
Tax Settlements(9.3) (26.1) — — — — — — —
Other0.7 (0.3) 3.5 (0.3) (0.6) (1.5) (1.3) 0.8 398.7
Effective income tax rate(8.5)% (18.8)% 43.4% 4.8% 7.6% (60.3)% (21.1)% (45.5)% 3,200.0%
_________
(a)At Generation, the lower effective tax rate is primarily attributable to tax settlements.
(b)At ComEd, the higher effective tax rate is primarily related to the nondeductible Deferred Prosecution Agreement payments. See Note 14 — Commitments and Contingencies for additional information.
(c)At PECO, the lower effective tax rate is primarily related to an increase in plant basis differences attributable to storm repairs.
(d)At BGE, PHI, Pepco, and DPL, the lower effective tax rate is primarily attributable to accelerated amortization of transmission related deferred income tax regulatory liabilities as a result of regulatory settlements. See Note 2 — Regulatory Matters for additional information.
(e)ACE recognized a loss before income taxes for the six months ended June 30, 2020. As a result, a positive percentage at ACE represents an income tax benefit for the period presented. At ACE, the higher effective tax rate is primarily attributable to accelerated amortization of transmission related deferred income tax regulatory liabilities as a result of regulatory settlements. See Note 2 — Regulatory Matters for additional information.




91
Table of Contents(f)
COMBINED NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)
(Dollars in millions, except per share data, unless otherwise noted)

Note 9 — Income Taxes

 Six Months Ended June 30, 2019
 Exelon Generation ComEd PECO BGE PHI Pepco DPL ACE
U.S. Federal statutory rate21.0% 21.0% 21.0% 21.0% 21.0% 21.0% 21.0% 21.0% 21.0%
Increase (decrease) due to:                 
State income taxes, net of Federal income tax benefit4.4 3.6 8.2 0.2 6.4 4.7 2.0 6.7 6.9
Qualified NDT fund income6.5 14.7 — — — — — — —
Amortization of investment tax credit, including deferred taxes on basis difference(0.6) (1.1) (0.2) — (0.1) (0.2) (0.1) (0.2) (0.3)
Plant basis differences(1.5) — (0.6) (6.4) (1.0) (1.7) (2.0) (0.6) (2.2)
Production tax credits and other credits(0.8) (1.8) — — — — — — —
Noncontrolling interests(0.3) (0.8) — — — — — — —
Excess deferred tax amortization(5.8) — (8.8) (2.6) (7.9) (19.4) (18.1) (15.6) (23.4)
Other0.7 (0.4) 0.2 (0.1) 0.2 0.3 0.5 0.4 2.0
Effective income tax rate23.6% 35.2% 19.8% 12.1% 18.6% 4.7% 3.3% 11.7% 4.0%



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COMBINED NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)
(Dollars in millions, except per share data, unless otherwise noted)

Note 9 — Income Taxes

Accounting for Uncertainty in Income Taxes
Exelon, Generation, PHI and ACE have the following unrecognized tax benefits as of June 30, 2020 and December 31, 2019. ComEd, PECO, BGE, Pepco and DPL's amounts are not material.
 Exelon Generation PHI ACE
June 30, 2020$122
 $49
 $50
 $15
December 31, 2019507
 441
 48
 14

Exelon's and Generation'sGeneration’s unrecognized federal and state tax benefits decreased in the first quarter of 2020 by approximately $411$411 million due to the settlement of a federal refund claim with IRS Appeals. The recognition of these tax benefits resulted in an increase to Exelon's and Generation’s net income of $76 million and $73 million, respectively, in the first quarter of 2020, reflecting a decrease to Exelon's and Generation's income tax expense of $67 million.
(g)At ComEd, the higher effective tax rate is primarily related to the nondeductible Deferred Prosecution Agreement payments.
(h)At BGE, PHI, Pepco, and DPL, the lower effective tax rate is primarily attributable to accelerated amortization of transmission related deferred income tax regulatory liabilities as a result of regulatory settlements.
(i)ACE recognized a loss before income taxes for the six months ended June 30, 2020. As a result, a positive percentage at ACE represents an income tax benefit for the period presented. At ACE, the higher effective tax rate is primarily attributable to accelerated amortization of transmission related deferred income tax regulatory liabilities as a result of regulatory settlements.

Unrecognized Tax Benefits
PHI and ACE have the following unrecognized tax benefits as of June 30, 2021 and December 31, 2020. Exelon's, Generation's, ComEd's, PECO's, BGE's, Pepco's, and DPL's amounts are not material.
PHIACE
June 30, 2021$54 $16 
December 31, 202052 15 
Reasonably possible the total amount of unrecognized tax benefits could significantly increase or decrease within 12 months after the reporting date
The following table represents Exelon's, PHI's and ACE'sAs of June 30, 2021, ACE has approximately $14 million of unrecognized federal and state tax benefits that could significantly decrease within the 12 months after the reporting date as a result of completing audits, potential settlements, refund claims, andbased on the outcomesoutcome of pending court cases as of June 30, 2020. Generation's, ComEd's, PECO's, BGE's, Pepco'sinvolving other taxpayers. The unrecognized tax benefit, if recognized, may be included in future base rates and DPL's amounts are not material.that portion would have no impact to the effective tax rate.
Exelon PHI 
ACE(a)
$14
 $14
 $14
_________
(a)The unrecognized tax benefit related to ACE, if recognized, may be included in future base rates and that portion would have no impact to the effective tax rate.
Other Income Tax Matters
State Income Tax Law Changes
On June 5, 2019, the Governor of Illinois signed a tax bill which would increase the Illinois corporate income tax rate from 9.50% to 10.49% effective for tax years beginning on or after January 1, 2021. The tax rate is contingent upon ratification of state constitutional amendments in November 2020. The effect of the rate change will be recognized in the period in which the new legislation is enacted. Exelon, Generation and ComEd do not expect a material impact to their financial statements as a result of the rate change.
10.11. Retirement Benefits (All Registrants)
Defined Benefit Pension and OPEB
During the first quarter of 2020,2021, Exelon received an updated valuation of its pension and OPEB to reflect actual census data as of January 1, 2020.2021. This valuation resulted in an increase to the pension obligations of $33 million and a decrease to the OPEB obligations of $8 million and $31 million, respectively.$9 million. Additionally, accumulated other comprehensive loss increased by $7$1 million (after-tax) and regulatory assets and liabilities increased by $19$21 million and decreased by $10$1 million, respectively.
The majority of the 20202021 pension benefit cost for the Exelon-sponsored plans is calculated using an expected long-term rate of return on plan assets of 7.00% and a discount rate of 3.34%2.58%. The majority of the 20202021 OPEB cost is calculated using an expected long-term rate of return on plan assets of 6.69%6.46% for funded plans and a discount rate of 3.31%2.51%.

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Table of Contents
COMBINED NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)
(Dollars in millions, except per share data, unless otherwise noted)

Note 10 — Retirement Benefits

A portion of the net periodic benefit cost for all plans is capitalized within the Consolidated Balance Sheets. The following table presents the components of Exelon's net periodic benefit costs, prior to capitalization, for the three and six months ended June 30, 20202021 and 2019.2020.
 Pension Benefits
Three Months Ended June 30,		 OPEB
Three Months Ended June 30,
 2020 2019 2020 2019
Components of net periodic benefit cost:       
Service cost$96
 $89
 $22
 $24
Interest cost190
 221
 39
 47
Expected return on assets(318) (306) (40) (38)
Amortization of:       
Prior service cost (benefit)1
 —
 (31) (44)
Actuarial loss128
 103
 12
 10
Settlement charges6
 —
 —
 —
Net periodic benefit cost$103
 $107
 $2
 $(1)
98



Pension Benefits
Six Months Ended June 30,		 OPEB
Six Months Ended June 30,
 2020 2019 2020 2019
Components of net periodic benefit cost:

 

 

 

Service cost$193
 $178
 $45
 $47
Interest cost379
 442
 77
 94
Expected return on assets(636) (612) (81) (77)
Amortization of:       
Prior service cost (benefit)2
 —
 (62) (89)
Actuarial loss256
 206
 24
 23
Settlement charges6
 —
 —
 —
Net periodic benefit cost$200

$214

$3

$(2)

COMBINED NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)
(Dollars in millions, except per share data, unless otherwise noted)

Note 11 — Retirement Benefits
Pension BenefitsOPEB
Three Months Ended June 30,Three Months Ended June 30,
 2021202020212020
Components of net periodic benefit cost:
Service cost$111 $96 $20 $22 
Interest cost160 190 28 39 
Expected return on assets(333)(318)(39)(40)
Amortization of:
Prior service cost (credit)0 1 (9)(31)
Actuarial loss149 128 10 12 
Settlement charges4 6 0 0 
Net periodic benefit cost$91 $103 $10 $2 
Pension BenefitsOPEB
Six Months Ended June 30,Six Months Ended June 30,
2021202020212020
Components of net periodic benefit cost:
Service cost$220 $193 $40 $45 
Interest cost320 379 57 77 
Expected return on assets(667)(636)(79)(81)
Amortization of:
Prior service cost (credit)1 2 (17)(62)
Actuarial loss299 256 19 24 
Curtailment benefits0 0 (1)0 
Settlement charges4 6 0 0 
Net periodic benefit cost$177 $200 $19 $3 

The amounts below represent the Registrants' allocated pension and OPEB plan costs. For Exelon, the service cost component is included in Operating and maintenance expense and Property, plant, and equipment, net while the non-service cost components are included in Other, net and Regulatory assets. For Generation and the Utility Registrants, the service cost and non-service cost components are included in Operating and maintenance expense and Property, plant, and equipment, net in their consolidated financial statements.
 Three Months Ended June 30, Six Months Ended June 30, Three Months Ended June 30,Six Months Ended June 30,
Pension and OPEB Costs 2020 2019 2020 2019Pension and OPEB Costs2021202020212020
Exelon $105
 $106
 $203
 $212
Exelon$101 $105 $196 $203 
Generation 32
 31
 59
 62
Generation30 32 56 59 
ComEd 28
 23
 57
 47
ComEd32 28 64 57 
PECO 1
 3
 3
 5
PECO2 1 4 3 
BGE 16
 16
 31
 30
BGE16 16 31 31 
PHI 18
 24
 35
 48
PHI12 18 24 35 
Pepco 4
 6
 7
 12
Pepco2 4 3 7 
DPL 2
 4
 4
 8
DPL1 2 1 4 
ACE 3
 4
 7
 8
ACE3 3 5 7 


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Table of Contents
COMBINED NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)
(Dollars in millions, except per share data, unless otherwise noted)

Note 10 — Retirement Benefits

Defined Contribution Savings Plans
99



COMBINED NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)
(Dollars in millions, except per share data, unless otherwise noted)

Note 11 — Retirement Benefits
The Registrants participate in various 401(k) defined contribution savings plans that are sponsored by Exelon. The plans are qualified under applicable sections of the IRC and allow employees to contribute a portion of their pre-tax and/or after-tax income in accordance with specified guidelines. All Registrants match a percentage of the employee contributions up to certain limits. The following table presents the matching contributions to the savings plans duringfor the three and six months ended June 30, 20202021 and 2019,2020, respectively.
Three Months Ended June 30,Six Months Ended June 30,
Savings Plans Matching Contributions2021202020212020
Exelon$36 $34 $69 $67 
Generation13 14 26 27 
ComEd10 9 18 16 
PECO3 2 6 5 
BGE2 2 4 4 
PHI4 3 7 6 
Pepco1 1 2 2 
DPL1 0 2 1 
ACE1 1 1 1 
  Three Months Ended June 30, Six Months Ended June 30,
Savings Plan Matching Contributions 2020 2019 2020 2019
Exelon $34
 $33

$67

$64
Generation 14
 14
 27
 28
ComEd 9
 9
 16
 16
PECO 2
 2
 5
 5
BGE 2
 2
 4
 4
PHI 3
 3
 6
 6
Pepco 1
 1
 2
 2
DPL —
 1
 1
 1
ACE 1
 —
 1
 1

11.12. Derivative Financial Instruments (All Registrants)
The Registrants use derivative instruments to manage commodity price risk, interest rate risk, and foreign exchange risk related to ongoing business operations.
Authoritative guidance requires that derivative instruments be recognized as either assets or liabilities at fair value, with changes in fair value of the derivative recognized in earnings immediately. Other accounting treatments are available through special election and designation, provided they meet specific, restrictive criteria both at the time of designation and on an ongoing basis. These alternative permissible accounting treatments include NPNS, cash flow hedges, and fair value hedges. All derivative economic hedges related to commodities, referred to as economic hedges, are recorded at fair value through earnings at Generation and are offset by a corresponding regulatory asset or liability at ComEd. For all NPNS derivative instruments, accounts receivable or accounts payable are recorded when derivative settlesderivatives settle and revenue or expense is recognized in earnings as the underlying physical commodity is sold or consumed.
Authoritative guidance about offsetting assets and liabilities requires the fair value of derivative instruments to be shown in the Combined Notes to Consolidated Financial Statements on a gross basis, even when the derivative instruments are subject to legally enforceable master netting agreements and qualify for net presentation in the Consolidated Balance Sheets. A master netting agreement is an agreement between two counterparties that may have derivative and non-derivative contracts with each other providing for the net settlement of all referencingreferenced contracts via one payment stream, which takes place as the contracts deliver, when collateral is requested or in the event of default. In the tables below, thatwhich present fair value balances, Generation’s energy-related economic hedges and proprietary trading derivatives are shown gross. The impact of the netting of fair value balances with the same counterparty that are subject to legally enforceable master netting agreements, as well as netting of cash collateral, including margin on exchange positions, is aggregated in the collateral and netting columns.
Generation’s and ComEd’s use of cash collateral is generally unrestricted unless Generation or ComEd are downgraded below investment grade. Cash collateral held by PECO, BGE, Pepco, DPL, and ACE must be deposited in an unaffiliated major U.S. commercial bank or foreign bank with a U.S. branch office that meet certain qualifications.
Commodity Price Risk (All Registrants)
Each of the Registrants employ established policies and procedures to manage their risks associated with market fluctuations in commodity prices by entering into physical and financial derivative contracts, including swaps, futures, forwards, options, and short-term and long-term commitments to purchase and sell energy and commodity products.

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Note 1112 — Derivative Financial Instruments

commodity products. The Registrants believe these instruments, which are either determined to be non-derivative or classified as economic hedges, mitigate exposure to fluctuations in commodity prices.
Generation. To the extent the amount of energy Generation produces differs from the amount of energy it has contracted to sell, Exelon and Generation are exposed to market fluctuations in the prices of electricity, fossil fuels, and other commodities. Within Exelon, Generation has the most exposure to commodity price risk. As such, Generation uses a variety of derivative and non-derivative instruments to manage the commodity price risk of its electric generation facilities, including power and gas sales, fuel and power purchases, natural gas transportation and pipeline capacity agreements, and other energy-related products marketed and purchased. To manage these risks, Generation may enter into fixed-price derivative or non-derivative contracts to hedge the variability in future cash flows from expected sales of power and gas and purchases of power and fuel. The objectives for executing such hedges include fixing the price for a portion of anticipated future electricity sales at a level that provides an acceptable return. Generation is also exposed to differences between the locational settlement prices of certain economic hedges and the hedged generating units. This price difference is actively managed through other instruments which include derivative congestion products, whose changes in fair value are recognized in earnings each period, and auction revenue rights, which are accounted for on an accrual basis.
Additionally, Generation is exposed to certain market risks through its proprietary trading activities. The proprietary trading activities are a complement to Generation’s energy marketing portfolio but represent a small portion of Generation’s overall energy marketing activities and are subject to limits established by Exelon’s RMC.
Utility Registrants. The Utility Registrants procure electric and natural gas supply through a competitive procurement process approved by each of the respective state utility commissions. The Utility Registrants’ hedging programs are intended to reduce exposure to energy and natural gas price volatility and have no direct earnings impact as the costs are fully recovered from customers through regulatory-approved recovery
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Note 12 — Derivative Financial Instruments
mechanisms. The following table provides a summary of the Utility Registrants’ primary derivative hedging instruments, listed by commodity and accounting treatment.
RegistrantCommodityAccounting TreatmentHedging instrumentInstrument
ComEdElectricityNPNSFixed price contracts based on all requirements in the IPA procurement plans.
Electricity
Changes in fair value of economic hedge recorded to an offsetting regulatory asset or liability(a)
20-year floating-to-fixed energy swap contracts beginning June 2012 based on the renewable energy resource procurement requirements in the Illinois Settlement Legislation of approximately 1.3 million MWhs per year.
PECO(b)
GasElectricityNPNSFixed price contracts for default supply requirements through full requirements contracts.
GasNPNSFixed price contracts to cover about 20%10% of planned natural gas purchases in support of projected firm sales.
BGEElectricityNPNSFixed price contracts for all SOS requirements through full requirements contracts.
GasNPNSFixed price contracts for between 10-20% of forecasted system supply requirements for flowing (i.e., non-storage) gas for the November through March period.
PepcoElectricityNPNSFixed price contracts for all SOS requirements through full requirements contracts.
DPLElectricityNPNSFixed price contracts for all SOS requirements through full requirements contracts.
GasNPNSFixed and Index priced contracts through full requirements contracts.
Changes in fair value of economic hedge recorded to an offsetting regulatory asset or liability(c)(b)
Exchange traded future contracts for up to 50% of estimated monthly purchase requirements each month, including purchases for storage injections.
ACEElectricityNPNSFixed price contracts for all BGS requirements through full requirements contracts.
__________
(a)See Note 3 - Regulatory Matters of the 2019 Form 10-K for additional information.
(b)As part of its hedging program, PECO enters into electric supply procurement contracts that do not meet the definition of a derivative instrument.
(c)The fair value of the DPL economic hedge is not material as of June 30, 2020 and December 31, 2019 and is not presented in the fair value tables below.

(a)See Note 3 - Regulatory Matters of the 2020 Form 10-K for additional information.
(b)The fair value of the DPL economic hedge is not material as of June 30, 2021 and December 31, 2020 and is not presented in the fair value tables below.
The following table provides a summary of the derivative fair value balances recorded by Exelon, Generation, and ComEd as of June 30, 2021 and December 31, 2020:
ExelonGenerationComEd
June 30, 2021Total
Derivatives		Economic
Hedges		Proprietary
Trading
Collateral(a)(b)
Netting(a)
SubtotalEconomic
Hedges
Mark-to-market derivative assets
(current assets)		$748 $6,541 $64 $(241)$(5,616)$748 $0 
Mark-to-market derivative assets
(noncurrent assets)		438 1,997 10 (92)(1,477)438 0 
Total mark-to-market derivative assets1,186 8,538 74 (333)(7,093)1,186 0 
Mark-to-market derivative liabilities
(current liabilities)		(713)(6,075)(54)(177)5,616 (690)(23)
Mark-to-market derivative liabilities
(noncurrent liabilities)		(553)(1,739)(7)(42)1,477 (311)(242)
Total mark-to-market derivative liabilities(1,266)(7,814)(61)(219)7,093 (1,001)(265)
Total mark-to-market derivative net assets (liabilities)$(80)$724 $13 $(552)$0 $185 $(265)
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Note 1112 — Derivative Financial Instruments

ExelonGenerationComEd
December 31, 2020Total
Derivatives		Economic
Hedges		Proprietary
Trading
Collateral(a)(b)
Netting(a)
SubtotalEconomic
Hedges
Mark-to-market derivative assets
(current assets)		$639 $2,757 $40 $103 $(2,261)$639 $0 
Mark-to-market derivative assets
(noncurrent assets)		554 1,501 4 64 (1,015)554 0 
Total mark-to-market derivative assets1,193 4,258 44 167 (3,276)1,193 0 
Mark-to-market derivative liabilities
(current liabilities)		(293)(2,629)(23)131 2,261 (260)(33)
Mark-to-market derivative liabilities
(noncurrent liabilities)		(472)(1,335)(2)118 1,015 (204)(268)
Total mark-to-market derivative liabilities(765)(3,964)(25)249 3,276 (464)(301)
Total mark-to-market derivative net assets (liabilities)$428 $294 $19 $416 $0 $729 $(301)
The following table provides a summary of_________
(a)Exelon and Generation net all available amounts allowed under the derivative fair value balances recorded byauthoritative guidance in the balance sheet. These amounts include unrealized derivative transactions with the same counterparty under legally enforceable master netting agreements and cash collateral. In some cases Exelon and Generation may have other offsetting exposures, subject to a master netting or similar agreement, such as trade receivables and ComEdpayables, transactions that do not qualify as derivatives, letters of credit, and other forms of non-cash collateral. These amounts are not material and not reflected in the table above.
(b)Includes $858 million held and $209 million posted of variation margin with the exchanges as of June 30, 20202021 and December 31, 2019:
June 30, 2020 Exelon Generation ComEd
Derivatives Total
Derivatives		 
Economic
Hedges
 
Proprietary
Trading
 
Collateral

 (a)(b)
 
Netting (a)
 Subtotal 
Economic
Hedges
Mark-to-market derivative assets
(current assets)
 $570
 $3,240
 $70
 $179
 $(2,919) $570
 $—
Mark-to-market derivative assets
(noncurrent assets)
 466
 1,582
 20
 77
 (1,213) 466
 —
Total mark-to-market derivative assets 1,036
 4,822
 90
 256
 (4,132) 1,036
 —
Mark-to-market derivative liabilities
(current liabilities)
 (190) (3,243) (46) 211
 2,919
 (159) (31)
Mark-to-market derivative liabilities
(noncurrent liabilities)
 (421) (1,442) (14) 109
 1,213
 (134) (287)
Total mark-to-market derivative liabilities (611) (4,685) (60) 320
 4,132
 (293) (318)
Total mark-to-market derivative net assets (liabilities) $425
 $137
 $30
 $576
 $—
 $743
 $(318)
December 31, 2019 Exelon Generation ComEd
Description Total
Derivatives		 Economic
Hedges		 Proprietary
Trading		 Collateral

(a)(b)		 Netting (a) Subtotal Economic
Hedges
Mark-to-market derivative assets
(current assets)		 $675
 $3,506
 $72
 $287
 $(3,190) $675
 $—
Mark-to-market derivative assets
(noncurrent assets)		 508
 1,238
 25
 122
 (877) 508
 —
Total mark-to-market derivative assets 1,183
 4,744
 97
 409
 (4,067) 1,183
 —
Mark-to-market derivative liabilities
(current liabilities)		 (236) (3,713) (38) 357
 3,190
 (204) (32)
Mark-to-market derivative liabilities
(noncurrent liabilities)		 (380) (1,140) (11) 163
 877
 (111) (269)
Total mark-to-market derivative liabilities (616) (4,853) (49) 520
 4,067
 (315) (301)
Total mark-to-market derivative net assets (liabilities) $567
 $(109) $48
 $929
 $—
 $868
 $(301)
_________
(a)Exelon and Generation net all available amounts allowed under the derivative authoritative guidance in the balance sheet. These amounts include unrealized derivative transactions with the same counterparty under legally enforceable master netting agreements and cash collateral. In some cases Exelon and Generation may have other offsetting exposures, subject to a master netting or similar agreement, such as trade receivables and payables, transactions that do not qualify as derivatives, letters of credit and other forms of non-cash collateral. These amounts are not material and not reflected in the table above.
(b)Of the collateral posted/(received), $383 million and $511 million represents variation margin on the exchanges at June 30, 2020 and December 31, 2019 respectively.

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Note 11 — Derivative Financial Instruments

Economic Hedges (Commodity Price Risk)
Generation. For the three and six months ended June 30, 20202021 and 2019,2020, Exelon and Generation recognized the following net pre-tax commodity mark-to-market gains (losses) which are also located in the Net fair value changes related to derivatives line in the Consolidated Statements of Cash Flows.
  Three Months Ended
June 30,		 Six Months Ended
June 30,
  2020 2019 2020 2019
Income Statement Location Gain (Loss) Gain (Loss)
Operating revenues $24
 $40
 $199
 $(10)
Purchased power and fuel 63
 (114) 15
 (84)
Total Exelon and Generation $87
 $(74) $214
 $(94)

Three Months Ended
June 30,		Six Months Ended
June 30,
2021202020212020
Income Statement LocationGain (Loss)Gain (Loss)
Operating revenues$(240)$24 $(323)$199 
Purchased power and fuel552 63 817 15 
Total Exelon and Generation$312 $87 $494 $214 
In general, increases and decreases in forward market prices have a positive and negative impact, respectively, on Generation’s owned and contracted generation positions that have not been hedged. Generation hedges commodity price risk on a ratable basis over three-year periods. As of June 30, 2020,2021, the percentage of expected generation hedged for the Mid-Atlantic, Midwest, New York, and ERCOT reportable segments is 98%-101% and 76%-79% for 2020 and 2021, respectively.2021.
Proprietary Trading (Commodity Price Risk)
Generation also executes commodity derivatives for proprietary trading purposes. Proprietary trading includes all contracts executed with the intent of benefiting from shifts or changes in market prices as opposed to those executed with the intent of hedging or managing risk. Gains and losses associated with proprietary trading are reported as Operating revenues in Exelon’s and Generation’s Consolidated Statements of Operations and Comprehensive Income and are included in the Net fair value changes related to derivatives line in the Consolidated Statements of Cash Flows. For the three and six months ended June 30, 20202021 and 2019,2020, net pre-tax commodity mark-to-market gains (losses)and losses for Exelon and Generation were not material. The Utility Registrants do not execute derivatives for proprietary trading purposes.
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Note 12 — Derivative Financial Instruments
Interest Rate and Foreign Exchange Risk (Exelon and Generation)
Exelon and Generation utilizeutilizes interest rate swaps which are treated as economic hedges, to manage theirits interest rate exposure. On July 1, 2018, Exelon de-designated its fair value hedges related to interest rate riskexposure and Generation de-designated its cash flow hedges related to interest rate risk. The notional amounts were $1,219 million and $1,269 million at June 30, 2020 and December 31, 2019, respectively, for Exelon and $519 million and $569 million at June 30, 2020 and December 31, 2019, respectively, for Generation.
Generation utilizes foreign currency derivatives to manage foreign exchange rate exposure associated with international commodity purchases in currencies other than U.S. dollars, both of which are treated as economic hedges. The notional amounts were $160$629 million and $231$665 million atfor Exelon and Generation as of June 30, 20202021 and December 31, 2019,2020, respectively.
The mark-to-market derivative assets and liabilities as of June 30, 20202021 and December 31, 20192020 and the mark-to-market gains and losses for the three and six months ended June 30, 20202021 and 20192020 were not material for Exelon and Generation.
Credit Risk (All Registrants)
The Registrants would be exposed to credit-related losses in the event of non-performance by counterparties on executed derivative instruments. The credit exposure of derivative contracts, before collateral, is represented by the fair value of contracts at the reporting date.
Generation. For commodity derivatives, Generation enters into enabling agreements that allow for payment netting with its counterparties, which reduces Generation’s exposure to counterparty risk by providing for the offset of amounts payable to the counterparty against amounts receivable from the counterparty. Typically, each enabling agreement is for a specific commodity and so, with respect to each individual counterparty, netting is limited to transactions involving that specific commodity product, except where master netting agreements exist with a

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Note 11 — Derivative Financial Instruments

counterparty that allow for cross product netting. In addition to payment netting language in the enabling agreement, Generation’s credit department establishes credit limits, margining thresholds, and collateral requirements for each counterparty, which are defined in the derivative contracts. Counterparty credit limits are based on an internal credit review process that considers a variety of factors, including the results of a scoring model, leverage, liquidity, profitability, credit ratings by credit rating agencies, and risk management capabilities. To the extent that a counterparty’s margining thresholds are exceeded, the counterparty is required to post collateral with Generation as specified in each enabling agreement. Generation’s credit department monitors current and forward credit exposure to counterparties and their affiliates, both on an individual and an aggregate basis.
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Note 12 — Derivative Financial Instruments
The following tables provide information on Generation’s credit exposure for all derivative instruments, NPNS, and payables and receivables, net of collateral and instruments that are subject to master netting agreements, as of June 30, 2020.2021. The tables further delineate that exposure by credit rating of the counterparties and provide guidance on the concentration of credit risk to individual counterparties. The figuresamounts in the tables below exclude credit risk exposure from individual retail counterparties, nuclear fuel procurement contracts, and exposure through RTOs, ISOs, NYMEX, ICE, NASDAQ, NGX, and Nodal commodity exchanges. 
Rating as of June 30, 2020 Total Exposure Before Credit Collateral 
Credit Collateral(a)
 Net Exposure Number of Counterparties Greater than 10% of Net Exposure Net Exposure of Counterparties Greater than 10% of Net Exposure
Investment grade $772
 $25
 $747
 1
 $117
Non-investment grade 35
 26
 9
    
No external ratings          
Internally rated — investment grade 213
 1
 212
    
Internally rated — non-investment grade 130
 17
 113
    
Total $1,150
 $69
 $1,081
 1
 $117
Rating as of June 30, 2021Total Exposure Before Credit Collateral
Credit Collateral(a)
Net ExposureNumber of Counterparties Greater than 10% of Net ExposureNet Exposure of Counterparties Greater than 10% of Net Exposure
Investment grade$446 $56 $390 0 $0 
Non-investment grade15 1 14 
No external ratings
Internally rated — investment grade134 1 133 
Internally rated — non-investment grade126 35 91 
Total$721 $93 $628 0 $0 
Net Credit Exposure by Type of Counterparty As of
June 30, 2020
Financial institutions $29
Investor-owned utilities, marketers, power producers 834
Energy cooperatives and municipalities 173
Other 45
Total $1,081
_________ 
(a)Net Credit Exposure by Type of CounterpartyAs of June 30, 2020, credit collateral held from counterparties where Generation had credit exposure included $31 million of cash2021
Financial institutions$27 
Investor-owned utilities, marketers, power producers448 
Energy cooperatives and $38 million of letters of credit. The credit collateral does not include non-liquid collateral.municipalities85 
Other68 
Total$628 
_________ 
(a)As of June 30, 2021, credit collateral held from counterparties where Generation had credit exposure included $53 million of cash and $40 million of letters of credit. The credit collateral does not include non-liquid collateral.
Utility Registrants. The Utility Registrants have contracts to procure electric and natural gas supply that provide suppliers with a certain amount of unsecured credit. If the exposure on the supply contract exceeds the amount of unsecured credit, the suppliers may be required to post collateral. The net credit exposure is mitigated primarily by the ability to recover procurement costs through customer rates. As of June 30, 2020,2021, the Utility Registrants’ counterparty credit risk with suppliers was not material.
Credit-Risk-Related Contingent Features (All Registrants)
Generation.As part of the normal course of business, Generation routinely enters into physically or financially settled contracts for the purchase and sale of electric capacity, electricity, fuels, emissions allowances, and other energy-related products. Certain of Generation’s derivative instruments contain provisions that require Generation to post collateral. Generation also enters into commodity transactions on exchanges where the exchanges act as the counterparty to each trade. Transactions on the exchanges must adhere to comprehensive collateral and margining requirements. This collateral may be posted in the form of cash or credit support with thresholds contingent upon Generation’s credit rating from each of the major credit rating agencies. The collateral and credit support

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Note 11 — Derivative Financial Instruments

requirements vary by contract and by counterparty. These credit-risk-related contingent features stipulate that if Generation were to be downgraded or lose its investment grade credit rating (based on its senior unsecured debt rating), it would be required to provide additional collateral. This incremental collateral requirement allows for the offsetting of derivative instruments that are assets with the same counterparty, where the contractual right of offset exists under applicable master netting agreements. In the absence of expressly agreed-to provisions that specify the collateral that must be provided, collateral requested will be a function of the facts and circumstances of the situation at the time of the demand. In this case, Generation believes an amount of several months of future payments (i.e., capacity payments) rather than a calculation of fair value is the best estimate for the contingent collateral obligation, which has been factored into the disclosure below.
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Note 12 — Derivative Financial Instruments
The aggregate fair value of all derivative instruments with credit-risk related contingent features in a liability position that are not fully collateralized (excluding transactions on the exchanges that are fully collateralized) is detailed in the table below:
Credit-Risk Related Contingent Features June 30, 2020 December 31, 2019Credit-Risk Related Contingent FeaturesJune 30, 2021December 31, 2020
Gross fair value of derivative contracts containing this feature(a)
 $(969) $(956)
Gross fair value of derivative contracts containing this feature(a)
$(2,173)$(834)
Offsetting fair value of in-the-money contracts under master netting arrangements(b)
 697
 649
Offsetting fair value of in-the-money contracts under master netting arrangements(b)
1,151 537 
Net fair value of derivative contracts containing this feature(c)
 $(272) $(307)
Net fair value of derivative contracts containing this feature(c)
$(1,022)$(297)
_________
(a)Amount represents the gross fair value of out-of-the-money derivative contracts containing credit-risk related contingent features ignoring the effects of master netting agreements.
(b)Amount represents the offsetting fair value of in-the-money derivative contracts under legally enforceable master netting agreements with the same counterparty, which reduces the amount of any liability for which a Registrant could potentially be required to post collateral.
(c)Amount represents the net fair value of out-of-the-money derivative contracts containing credit-risk related contingent features after considering the mitigating effects of offsetting positions under master netting arrangements and reflects the actual net liability upon which any potential contingent collateral obligations would be based.
(a)Amount represents the gross fair value of out-of-the-money derivative contracts containing credit-risk related contingent features ignoring the effects of master netting agreements.
(b)Amount represents the offsetting fair value of in-the-money derivative contracts under legally enforceable master netting agreements with the same counterparty, which reduces the amount of any liability for which Generation could potentially be required to post collateral.
(c)Amount represents the net fair value of out-of-the-money derivative contracts containing credit-risk related contingent features after considering the mitigating effects of offsetting positions under master netting arrangements and reflects the actual net liability upon which any potential contingent collateral obligations would be based.
As of June 30, 20202021 and December 31, 2019,2020, Exelon and Generation posted or held the following amounts of cash collateral and letters of credit on derivative contracts with external counterparties, after giving consideration to offsetting derivative and non-derivative positions under master netting agreements.
  June 30, 2020 December 31, 2019
Cash collateral posted $645
 $982
Letters of credit posted 224
 264
Cash collateral held 110
 103
Letters of credit held 76
 112
Additional collateral required in the event of a credit downgrade below investment grade 1,319
 1,509

June 30, 2021December 31, 2020
Cash collateral posted$67 $511 
Letters of credit posted344 226 
Cash collateral held621 110 
Letters of credit held50 40 
Additional collateral required in the event of a credit downgrade below investment grade1,899 1,432 
Generation entered into supply forward contracts with certain utilities, including PECO and BGE, with one-sided collateral postings only from Generation. If market prices fall below the benchmark price levels in these contracts, the utilities are not required to post collateral. However, when market prices rise above the benchmark price levels, counterparty suppliers, including Generation, are required to post collateral once certain unsecured credit limits are exceeded.
Utility Registrants
The Utility Registrants’ electric supply procurement contracts do not contain provisions that would require them to post collateral.
PECO’s, BGE’s, and DPL’s natural gas procurement contracts contain provisions that could require PECO, BGE, and DPL to post collateral in the form of cash or credit support, which vary by contract and counterparty, with thresholds contingent upon PECO’s, BGE,BGE's, and DPL’s credit rating. As of June 30, 2020,2021, PECO, BGE, and DPL were not required to post collateral for any of these agreements. If PECO, BGE, or DPL lost their investment grade credit rating as of June 30, 2021, they could have been required to post incremental collateral to their counterparties of $22 million, $40 million and $12 million, respectively.

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Note 1113 — Derivative Financial InstrumentsDebt and Credit Agreements

credit ratings as of June 30, 2020, they could have been required to post incremental collateral to its counterparties of $24 million, $26 million and $10 million, respectively.
12.13. Debt and Credit Agreements (All Registrants)
Short-Term Borrowings
Exelon Corporate, ComEd, and BGE meet their short-term liquidity requirements primarily through the issuance of commercial paper. Generation and PECO meet their short-term liquidity requirements primarily through the issuance of commercial paper and borrowings from the Exelon intercompany money pool. Pepco, DPL, and ACE meet their short-term liquidity requirements primarily through the issuance of commercial paper and borrowings from the PHI intercompany money pool. PHI Corporate meets its short-term liquidity requirements primarily through the issuance of short-term notes and the Exelon intercompany money pool. The Registrants may use their respective credit facilities for general corporate purposes, including meeting short-term funding requirements and the issuance of letters of credit.
Commercial Paper
The following table reflects the Registrants' commercial paper programs as of June 30, 20202021 and December 31, 2019.2020. PECO and BGE had no0 commercial paper borrowings as of both June 30, 20202021 and December 31, 2019.2020.
 Outstanding Commercial
Paper as of		 Average Interest Rate on
Commercial Paper Borrowings as of
Commercial Paper IssuerJune 30, 2020 December 31, 2019 June 30, 2020 December 31, 2019
Exelon(a)
$19
 $870
 0.15% 2.25%
Generation—
 320
 —% 1.84%
ComEd—
 130
 —% 2.38%
BGE—
 76
 —% 2.46%
PHI(b)
19
 208
 0.15% N/A
PEPCO14
 82
 0.15% 2.56%
DPL—
 56
 —% 2.02%
ACE5
 70
 0.15% 2.43%

Outstanding Commercial
Paper as of		Average Interest Rate on
Commercial Paper Borrowings as of
Commercial Paper IssuerJune 30, 2021December 31, 2020June 30, 2021December 31, 2020
Exelon(a)
$365 $1,031 0.17 %0.25 %
Generation0 340 0 %0.27 %
ComEd33 323 0.15 %0.23 %
PHI(b)
332 368 0.17 %0.24 %
Pepco154 35 0.17 %0.22 %
DPL0 146 0 %0.24 %
ACE178 187 0.18 %0.25 %
__________
(a)
Includes
(a)Exelon Corporate had 0 outstanding commercial paper at Exelon Corporate of $136 million with average interest rates on commercial paper borrowings of 1.92% at December 31, 2019. Exelon Corporate had no outstanding commercial paper borrowings as of June 30, 2020.
(b)Includes the consolidated amounts of Pepco, DPL, and ACE.
On March 19, 2020, Generation borrowed $1.5 billion on its revolving credit facility due to disruptions in the commercial paper marketsborrowings as a result of COVID-19. The funds were used to refinance commercial paper. Generation repaid the $1.5 billion borrowed on the revolving credit facility on April 3, 2020. As ofboth June 30, 2020,2021 and December 31, 2020.
(b)Represents the available capacity on Generation’s revolving credit facility was consolidated amounts of Pepco, DPL, and ACE.
$5 billion. See Note 16—17 –Debt and Credit Agreements of the Exelon 20192020 Form 10-K for additional information on the Registrants’Registrants' credit facilities.
Short-Term Loan Agreements
On March 23, 2017, Exelon Corporate entered into a term loan agreement for $500 million. The loan agreement was renewed on March 19, 202017, 2021 and will expire on March 18,16, 2022. Pursuant to the loan agreement, loans made thereunder bear interest at a variable rate equal to LIBOR plus 0.65% and all indebtedness thereunder is unsecured. The loan agreement is reflected in Exelon's Consolidated Balance Sheets within Short-term borrowings.
On March 24, 2021, Exelon Corporate entered into a 9-month term loan agreement for $200 million. The loan agreement has an expiration of December 24, 2021. Pursuant to the loan agreement, loans made thereunder bear interest at a variable rate equal to LIBOR plus 0.65% and all indebtedness thereunder is unsecured. The loan agreement is reflected in Exelon's Consolidated Balance SheetSheets within Short-term borrowings.
On March 19, 2020, Generation31, 2021, Exelon Corporate entered into a 9-month and 364-day term loan agreement for $200 million.$150 million each with variable interest rates of LIBOR plus 0.65% and expiration dates of December 31, 2021 and March 30, 2022, respectively. The loan agreement has an expiration of March 18, 2021. Pursuant to the loan agreement, loans made thereunder bear interest at a variable rate equal to LIBOR plus 0.50% and all indebtedness thereunder is unsecured. The loan agreement isagreements are reflected in Generation'sExelon's Consolidated Balance SheetSheets within Short-term borrowings.

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COMBINED NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)
(Dollars in millions, except per share data, unless otherwise noted)

Note 1213 — Debt and Credit Agreements

On March 19, 2020, Generation entered into a term loan agreement for $200 million. The loan agreement was renewed on March 17, 2021 and will expire on March 16, 2022. Pursuant to the loan agreement, loans made thereunder bear interest at a variable rate equal to LIBOR plus 0.875% and all indebtedness thereunder is unsecured. The loan agreement is reflected in Exelon's and Generation's Consolidated Balance Sheets within Short-term borrowings.
On March 31, 2020, Generation entered into a term loan agreement for $300 million. The loan agreement has an expiration ofwas renewed on March 30, 2021.2021 and will expire on March 29, 2022. Pursuant to the loan agreement, loans made thereunder bear interest at a variable rate equal to LIBOR plus 0.75%0.70% and all indebtedness thereunder is unsecured. The loan agreement is reflected in Exelon's and Generation's Consolidated Balance SheetSheets within Short-term borrowings.
Revolving Credit Agreements
On April 24, 2020, Exelon CorporateJanuary 25, 2021, ComEd entered into a credit agreement establishing a $550two 90-day term loan agreements for $125 million 364-day revolving credit facility at a each with variable interest raterates of LIBOR plus 1.75%. This facility will be used by Exelon as an additional source of short-term liquidity as needed.0.50% and LIBOR plus 0.75%, respectively. ComEd repaid the term loans on March 9, 2021.
Bilateral Credit Agreements
On May 15, 2020,January 11, 2013, Generation entered into a bilateral credit agreement establishingfor $100 million. The agreement was renewed on March 1, 2021 with a $100 millionmaturity date of March 1, 2023.
On February 21, 2019, Generation entered into a bilateral credit facility. This facility will solely be used by Generation to issue letters of credit, and theagreement for $100 million. The agreement was renewed on March 31, 2021 with a maturity date is automaticallyof March 31, 2022.
On January 5, 2016, Generation entered into a bilateral credit agreement for $150 million. The agreement was renewed based on the contingency standards set within the agreement.April 2, 2021 with a maturity date of April 5, 2023.
See Note 17 – Debt and Credit Agreements of the Exelon 2020 Form 10-K for additional information on Generation's bilateral credit agreements.
Credit Agreements
On July 15, 2021, each of the Registrants' respective syndicated revolving credit facilities had their maturity dates extended to May 26, 2024.
Long-Term Debt
Issuance of Long-Term Debt
During the second quarter of 2020, CENG drew on its bilateral credit facility. As ofsix months ended June 30, 2020, there2021, the following long-term debt was issued:
108
$100 million outstanding at this facility. The bilateral credit facility with CENG is incorporated within Generation, and supports the issuance of letters of credit and funding for working capital.

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COMBINED NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)
(Dollars in millions, except per share data, unless otherwise noted)

Note 1213 — Debt and Credit Agreements

Long-Term Debt
Issuance of Long-Term Debt
During the six months ended June 30, 2020, the following long-term debt was issued:
Company(a)
 Type Interest Rate Maturity Amount Use of Proceeds
Exelon Notes 4.05% April 15, 2030 $1,250
 Repay existing indebtedness and for general corporate purposes.
Exelon Notes 4.70% April 15, 2050 750
 Repay existing indebtedness and for general corporate purposes.
Generation Senior Notes 3.25% June 1, 2025 900
 Repay existing indebtedness and for general corporate purposes.
Generation 
Energy Efficiency Project Financing(b) 
 3.95% August 31, 2020 2
 Funding to install energy conservation measures for the Fort Meade project.
Generation 
Energy Efficiency Project Financing(b)
 2.53% April 30, 2021 1
 Funding to install energy conservation measures for the Fort AP Hill project.
ComEd First Mortgage Bonds, Series 128 2.20% March 1, 2030 350
 Repay a portion of outstanding commercial paper obligations and fund other general corporate purposes.
ComEd First Mortgage Bonds, Series 129 3.00% March 1, 2050 650
 Repay a portion of outstanding commercial paper obligations and to fund general corporate purposes.
PECO First and Refunding Mortgage Bonds 2.80% June 15, 2050 350
 Funding for general corporate purposes.
BGE Senior Notes 2.90% June 15, 2050 400
 Repay commercial paper obligations and for general corporate purposes.
Pepco(c)
 First Mortgage Bonds 2.53% February 25, 2030 150
 Repay existing indebtedness and for general corporate purposes.
DPL First Mortgage Bonds 2.53% June 9, 2030 100
 Repay existing indebtedness and for general corporate purposes.
ACE Tax-Exempt First Mortgage Bonds 2.25% June 1, 2029 23
 Refinance existing indebtedness.
ACE First Mortgage Bonds 3.24% June 9, 2050 100
 Repay existing indebtedness and for general corporate purposes.

CompanyTypeInterest RateMaturityAmountUse of Proceeds
ExelonLong-Term Software License Agreements3.62 %December 1, 2025$4 Procurement of software licenses.
GenerationWest Medway II
Nonrecourse Debt		LIBOR + 3%(a)March 31, 2026150 Funding for general corporate purposes.
Generation
Energy Efficiency Project Financing(b)
2.53 %August 31, 20211 Funding to install energy conservation measures for the Fort AP Hill project.
ComEdFirst Mortgage Bonds, Series 1303.13 %March 15, 2051700 Repay a portion of outstanding commercial paper obligations and two outstanding term loans, and to fund other general corporate purposes.
PECOFirst and Refunding Mortgage Bonds3.05 %March 15, 2051375 Funding for general corporate purposes.
BGESenior Notes2.25 %June 15, 2031600 Repay a portion of outstanding commercial paper obligations, repay existing indebtedness, and to fund other general corporate purposes.
Pepco(c)
First Mortgage Bonds2.32 %March 30, 2031150 Repay existing indebtedness and for general corporate purposes.
DPLFirst Mortgage Bonds3.24 %March 30, 2051125 Repay existing indebtedness and for general corporate purposes.
ACEFirst Mortgage Bonds2.30 %March 15, 2031350 Refinance existing indebtedness, repay outstanding commercial paper obligations, and for general corporate purposes.
__________
(a)
On July 1, 2020, DPL issued $78 million of tax-exempt bonds maturing on January 1, 2031. The bonds have a 1.05% interest rate through July 2025.
(a)The nonrecourse debt has an average blended interest rate.
(b)For Energy Efficiency Project Financing, the maturity dates represent the expected date of project completion, upon which the respective customer assumes the outstanding debt.
(c)On March 30, 2021, Pepco entered into a purchase agreement of First Mortgage Bonds of $125 million at 3.29% due on September 28, 2051. The closing date of the issuance is expected to occur in September 2021.
(b)For Energy Efficiency Project Financing, the maturity dates represent the expected date of project completion, upon which the respective customer assumes the outstanding debt.
(c)
On February 25, 2020, Pepco entered into a purchase agreement of First Mortgage Bonds for $150 million at 3.28% due on September 23, 2050. The closing date of the issuance is expected to occur in September 2020.
Debt Covenants
As of June 30, 2020,2021, the Registrants are in compliance with debt covenants.
Nonrecourse Debt
Exelon and Generation have issued nonrecourse debt financing. Borrowings under these agreements are secured by the assets and equity of each respective project. The lenders do not have recourse against Exelon or Generation in the event of a default.
Antelope Valley Solar Ranch One. West Medway II, LLC. In December 2011, the DOE Loan Programs Office issuedOn May 13, 2021, West Medway II, LLC (West Medway II), an indirect subsidiary of Generation, entered into a guarantee for up to $646 millionfinancing agreement for a $150 million nonrecourse senior secured term loan from the Federal Financing Bankcredit facility with a maturity date of March 31, 2026. The term loan bears interest at an average blended interest rate of LIBOR plus 3%, paid quarterly. In addition to support the financing, West Medway II, entered into interest rate swaps with an initial notional amount of $113 million at an interest rate of 0.61%, paid quarterly, to manage a portion of the construction of the Antelope Valley facility.interest rate exposure in connection with financing. The project became fully operational in 2014. The loan will mature on January 5, 2037.net proceeds were distributed to Generation for general

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COMBINED NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)
(Dollars in millions, except per share data, unless otherwise noted)

Note 1213 — Debt and Credit Agreements

As of June 30, 2020, approximately $475 million was outstanding. In addition, Generation has issued letters of credit to support its equity investment in the project. As of June 30, 2020, Generation had $37 million in letters of credit outstanding related to the project. In 2017,corporate purposes. Generation’s interests in Antelope ValleyWest Medway II, were also contributed to and are pledged as collateral for the EGR IV financing structure referenced below.
Antelope Valley sells all of its output to PG&E through a PPA. On January 29, 2019, PG&E filed for protection under Chapter 11 of the U.S. Bankruptcy Code, which created an event of default for Antelope Valley’s nonrecourse debt that provided the lender with a right to accelerate amounts outstanding under the loan such that they would become immediately due and payable. As a result of the event of default and in the absence of a waiver from the lender foregoing their acceleration rights, the debt was reclassified as current in Exelon’s and Generation’s Consolidated Balance Sheets in the first quarter of 2019. Further, distributions from Antelope Valley to EGR IV were suspended.
The United States Bankruptcy Court entered an order on June 20, 2020 confirming PG&E’s plan of reorganization. On July 1, 2020 the plan became effective, and PG&E emerged from bankruptcy. On July 21, 2020, Antelope Valley received a waiver from the DOE for the event of default and, as such, the debt has been classified as noncurrent as of June 30, 2020 and distributions from Antelope Valley to EGR IV are now permitted.
See Note 8 — Asset Impairments for additional information.
ExGen Renewables IV.  In November 2017, EGR IV, an indirect subsidiary of Exelon and Generation, entered into an $850 million nonrecourse senior secured term loan credit facility agreement. Generation’s interests in EGRP, Antelope Valley, SolGen, and Albany Green Energy were all contributed to and are pledged as collateral for this financing. The loan is scheduled to mature on November 28, 2024. As of June 30, 2020,2021 approximately $775$150 million was outstanding.
See Note 16— 17 – Debt and Credit Agreements of the Exelon 20192020 Form 10-K for additional information on nonrecourse debt.debt and Note 12 – Derivative Financial Instruments for additional information on interest rate swaps.
13.14. Fair Value of Financial Assets and Liabilities (All Registrants)
Exelon measures and classifies fair value measurements in accordance with the hierarchy as defined by GAAP. The hierarchy prioritizes the inputs to valuation techniques used to measure fair value into three levels as follows:
•Level 1 - quoted prices (unadjusted) in active markets for identical assets or liabilities that the Registrants have the ability to liquidate as of the reporting date.
•Level 2 - inputs other than quoted prices included within Level 1 that are directly observable for the asset or liability or indirectly observable through corroboration with observable market data.
•Level 3 - unobservable inputs, such as internally developed pricing models or third-party valuations for the asset or liability due to little or no market activity for the asset or liability.

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Table of Contents
COMBINED NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)
(Dollars in millions, except per share data, unless otherwise noted)

Note 13 — Fair Value of Financial Assets and Liabilities

Fair Value of Financial Liabilities Recorded at Amortized Cost
The following tables present the carrying amounts and fair values of the Registrants’ short-term liabilities, long-term debt, SNF obligation, and trust preferred securities (long-term debt to financing trusts or junior subordinated debentures) as of June 30, 20202021 and December 31, 2019.2020. The Registrants have no financial liabilities classified as Level 1.
The carrying amounts of the Registrants’ short-term liabilities as presented on their Consolidated Balance Sheets are representative of their fair value (Level 2) because of the short-term nature of these instruments.
June 30, 2021December 31, 2020
Carrying AmountFair ValueCarrying AmountFair Value
Level 2Level 3TotalLevel 2Level 3Total
Long-Term Debt, including amounts due within one year(a)
Exelon$38,710 $40,956 $3,189 $44,145 $36,912 $40,688 $3,064 $43,752 
Generation6,178 5,776 1,145 6,921 6,087 5,648 1,208 6,856 
ComEd9,675 11,407 0 11,407 8,983 11,117 0 11,117 
PECO4,125 4,722 50 4,772 3,753 4,553 50 4,603 
BGE4,259 4,748 0 4,748 3,664 4,366 0 4,366 
PHI7,369 6,048 1,994 8,042 7,006 6,099 1,806 7,905 
Pepco3,318 3,240 860 4,100 3,165 3,336 748 4,084 
DPL1,804 1,434 556 1,990 1,677 1,484 455 1,939 
ACE1,515 1,117 578 1,695 1,413 1,018 602 1,620 
Long-Term Debt to Financing Trusts(a)
Exelon$390 $0 $482 $482 $390 $0 $467 $467 
ComEd205 0 253 253 205 0 246 246 
PECO184 0 229 229 184 0 221 221 
SNF Obligation
Exelon$1,209 $995 $0 $995 $1,208 $909 $0 $909 
Generation1,209 995 0 995 1,208 909 0 909 
  June 30, 2020 December 31, 2019
  Carrying Amount Fair Value Carrying Amount Fair Value
   Level 2 Level 3 Total  Level 2 Level 3 Total
Long-Term Debt, including amounts due within one year(a)

Exelon $38,626
 $41,531
 $3,080
 $44,611
 $36,039
 $37,453
 $2,580
 $40,033
Generation 7,433
 6,761
 1,418
 8,179
 7,974
 7,304
 1,366
 8,670
ComEd 9,480
 11,433
 —
 11,433
 8,491
 9,848
 —
 9,848
PECO 3,752
 4,453
 50
 4,503
 3,405
 3,868
 50
 3,918
BGE 3,663
 4,203
 —
 4,203
 3,270
 3,649
 —
 3,649
PHI 6,890
 6,016
 1,612
 7,628
 6,563
 5,902
 1,164
 7,066
Pepco 3,013
 3,270
 576
 3,846
 2,864
 3,198
 388
 3,586
DPL 1,675
 1,444
 443
 1,887
 1,567
 1,408
 311
 1,719
ACE 1,420
 1,040
 593
 1,633
 1,327
 1,026
 464
 1,490
Long-Term Debt to Financing Trusts(a)

Exelon $390
 $—
 $409
 $409
 $390
 $—
 $428
 $428
ComEd 205
 —
 216
 216
 205
 —
 227
 227
PECO 184
 —
 192
 192
 184
 —
 201
 201
SNF Obligation
Exelon $1,206
 $999
 $—
 $999
 $1,199
 $1,055
 $—
 $1,055
Generation 1,206
 999
 —
 999
 1,199
 1,055
 —
 1,055
__________
____(a)Includes unamortized debt issuance costs which are not fair valued.
(a)Includes unamortized debt issuance costs which are not fair valued.

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COMBINED NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)
(Dollars in millions, except per share data, unless otherwise noted)

Note 1314 — Fair Value of Financial Assets and Liabilities

Recurring Fair Value Measurements
The following tables present assets and liabilities measured and recorded at fair value in the Registrants' Consolidated Balance Sheets on a recurring basis and their level within the fair value hierarchy as of June 30, 20202021 and December 31, 2019:2020:
Exelon and Generation
 Exelon Generation
As of June 30, 2020Level 1 Level 2 Level 3 Not subject to leveling Total Level 1 Level 2 Level 3 Not subject to leveling Total
Assets                   
Cash equivalents(a)
$1,864
 $—
 $—
 $—
 $1,864
 $162
 $—
 $—
 $—
 $162
NDT fund investments        
         
Cash equivalents(b)
345
 78
 —
 —
 423
 345
 78
 —
 —
 423
Equities3,080
 1,599
 —

1,280
 5,959
 3,080
 1,599
 —

1,280
 5,959
Fixed income                   
Corporate debt—
 1,501
 270
 —
 1,771
 —
 1,501
 270
 —
 1,771
U.S. Treasury and agencies1,864
 116
 —
 —
 1,980
 1,864
 116
 —
 —
 1,980
Foreign governments—
 42
 —
 —
 42
 —
 42
 —
 —
 42
State and municipal debt—
 94
 —
 —
 94
 —
 94
 —
 —
 94
Other—
 29
 —
 965
 994
 —
 29
 —
 965
 994
Fixed income subtotal1,864

1,782

270
 965

4,881

1,864

1,782

270
 965

4,881
Private credit—
 —
 229
 510
 739
 —
 —
 229
 510
 739
Private equity—
 —
 —
 423
 423
 —
 —
 —
 423
 423
Real estate—
 —
 —
 647
 647
 —
 —
 —
 647
 647
NDT fund investments subtotal(c)(d)
5,289

3,459

499
 3,825

13,072

5,289

3,459

499
 3,825

13,072
Rabbi trust investments        
         
Cash equivalents50
 —
 —
 —
 50
 4
 —
 —
 —
 4
Mutual funds79
 —
 —
 —
 79
 25
 —
 —
 —
 25
Fixed income—
 10
 —
 —
 10
 —
 —
 —
 —
 —
Life insurance contracts—
 77
 43
 —
 120
 —
 24
 —
 —
 24
Rabbi trust investments subtotal129

87

43
 —

259

29

24

—
 —

53
Commodity derivative assets                   
Economic hedges770
 2,382
 1,670
 —
 4,822
 770
 2,382
 1,670
 —
 4,822
Proprietary trading—
 47
 43
 —
 90
 —
 47
 43
 —
 90
Effect of netting and allocation of collateral(e)(f)
(849) (2,124) (903) —
 (3,876) (849) (2,124) (903) —
 (3,876)
Commodity derivative assets subtotal(79)
305

810
 —

1,036

(79)
305

810
 —

1,036
DPP consideration—
 635
 —
 —
 635
 —
 635
 —
 —
 635
Total assets7,203

4,486

1,352

3,825

16,866

5,401

4,423

1,309

3,825

14,958

ExelonGeneration
As of June 30, 2021Level 1Level 2Level 3Not subject to levelingTotalLevel 1Level 2Level 3Not subject to levelingTotal
Assets
Cash equivalents(a)
$1,167 $0 $0 $0 $1,167 $162 $0 $0 $0 $162 
NDT fund investments
Cash equivalents(b)
552 75 0 0 627 552 75 0 0 627 
Equities4,770 1,720 0 1,671 8,161 4,770 1,720 0 1,671 8,161 
Fixed income
Corporate debt(c)
0 1,146 285 0 1,431 0 1,146 285 0 1,431 
U.S. Treasury and agencies2,052 39 0 0 2,091 2,052 39 0 0 2,091 
Foreign governments0 51 0 0 51 0 51 0 0 51 
State and municipal debt0 28 0 0 28 0 28 0 0 28 
Other32 31 0 1,113 1,176 32 31 0 1,113 1,176 
Fixed income subtotal2,084 1,295 285 1,113 4,777 2,084 1,295 285 1,113 4,777 
Private credit0 0 176 607 783 0 0 176 607 783 
Private equity0 0 0 580 580 0 0 0 580 580 
Real estate0 0 0 762 762 0 0 0 762 762 
NDT fund investments subtotal(d)(e)
7,406 3,090 461 4,733 15,690 7,406 3,090 461 4,733 15,690 
Rabbi trust investments
Cash equivalents65 0 0 0 65 4 0 0 0 4 
Mutual funds99 0 0 0 99 33 0 0 0 33 
Fixed income0 11 0 0 11 0 0 0 0 0 
Life insurance contracts0 94 34 0 128 0 31 0 0 31 
Rabbi trust investments subtotal164 105 34 0 303 37 31 0 0 68 
Investments in equities(f)
327 0 0 0 327 327 0 0 0 327 
Commodity derivative assets
Economic hedges1,781 3,917 2,840 0 8,538 1,781 3,917 2,840 0 8,538 
Proprietary trading0 62 12 0 74 0 62 12 0 74 
Effect of netting and allocation of collateral(g)(h)
(1,411)(3,502)(2,513)0 (7,426)(1,411)(3,502)(2,513)0 (7,426)
Commodity derivative assets subtotal370 477 339 0 1,186 370 477 339 0 1,186 
DPP consideration0 374 0 0 374 0 374 0 0 374 
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COMBINED NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)
(Dollars in millions, except per share data, unless otherwise noted)

Note 1314 — Fair Value of Financial Assets and Liabilities

ExelonGeneration
As of June 30, 2021Level 1Level 2Level 3Not subject to levelingTotalLevel 1Level 2Level 3Not subject to levelingTotal
Total assets9,434 4,046 834 4,733 19,047 8,302 3,972 800 4,733 17,807 
Liabilities
Commodity derivative liabilities
Economic hedges(1,245)(3,444)(3,390)0 (8,079)(1,245)(3,444)(3,125)0 (7,814)
Proprietary trading0 (45)(16)0 (61)0 (45)(16)0 (61)
Effect of netting and allocation of collateral(g)(h)
1,242 3,295 2,337 0 6,874 1,242 3,295 2,337 0 6,874 
Commodity derivative liabilities subtotal(3)(194)(1,069)0 (1,266)(3)(194)(804)0 (1,001)
Deferred compensation obligation0 (144)0 0 (144)0 (42)0 0 (42)
Total liabilities(3)(338)(1,069)0 (1,410)(3)(236)(804)0 (1,043)
Total net assets (liabilities)$9,431 $3,708 $(235)$4,733 $17,637 $8,299 $3,736 $(4)$4,733 $16,764 
ExelonGeneration
As of December 31, 2020Level 1Level 2Level 3Not subject to levelingTotalLevel 1Level 2Level 3Not subject to levelingTotal
Assets
Cash equivalents(a)
$686 $0 $0 $0 $686 $124 $0 $0 $0 $124 
NDT fund investments
Cash equivalents(b)
210 95 0 0 305 210 95 0 0 305 
Equities3,886 2,077 0 1,562 7,525 3,886 2,077 0 1,562 7,525 
Fixed income
Corporate debt(c)
0 1,485 285 0 1,770 0 1,485 285 0 1,770 
U.S. Treasury and agencies1,871 126 0 0 1,997 1,871 126 0 0 1,997 
Foreign governments0 56 0 0 56 0 56 0 0 56 
State and municipal debt0 101 0 0 101 0 101 0 0 101 
Other0 41 0 961 1,002 0 41 0 961 1,002 
Fixed income subtotal1,871 1,809 285 961 4,926 1,871 1,809 285 961 4,926 
Private credit0 0 212 629 841 0 0 212 629 841 
Private equity0 0 0 504 504 0 0 0 504 504 
Real estate0 0 0 679 679 0 0 0 679 679 
NDT fund investments subtotal(d)(e)
5,967 3,981 497 4,335 14,780 5,967 3,981 497 4,335 14,780 
Rabbi trust investments
Cash equivalents60 0 — 0 60 4 0 0 0 4 
Mutual funds91 0 0 0 91 29 0 0 0 29 
Fixed income0 11 0 0 11 0 0 0 0 0 
Life insurance contracts0 87 34 0 121 0 28 0 0 28 
Rabbi trust investments subtotal151 98 34 0 283 33 28 0 0 61 
Investments in equities(f)
195 0 0 0 195 195 0 0 0 195 
Commodity derivative assets
Economic hedges745 1,914 1,599 0 4,258 745 1,914 1,599 0 4,258 
Proprietary trading0 17 27 0 44 0 17 27 0 44 
112
 Exelon Generation
As of June 30, 2020Level 1 Level 2 Level 3 Not subject to leveling Total Level 1 Level 2 Level 3 Not subject to leveling Total
Liabilities                   
Commodity derivative liabilities                   
Economic hedges(933) (2,541) (1,529) —
 (5,003) (933) (2,541) (1,211) —
 (4,685)
Proprietary trading—
 (44) (16) —
 (60) —
 (44) (16) —
 (60)
Effect of netting and allocation of collateral(e)(f)
933
 2,443
 1,076
 —
 4,452
 933
 2,443
 1,076
 —
 4,452
Commodity derivative liabilities subtotal—
 (142) (469) —
 (611) —
 (142) (151) —
 (293)
Deferred compensation obligation—
 (127) —
 —
 (127) —
 (35) —
 —
 (35)
Total liabilities—

(269)
(469) —

(738)
—

(177)
(151) —

(328)
Total net assets$7,203

$4,217

$883
 $3,825

$16,128

$5,401

$4,246

$1,158
 $3,825

$14,630


107
COMBINED NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)
(Dollars in millions, except per share data, unless otherwise noted)

Note 1314 — Fair Value of Financial Assets and Liabilities

ExelonGeneration
As of December 31, 2020Level 1Level 2Level 3Not subject to levelingTotalLevel 1Level 2Level 3Not subject to levelingTotal
Effect of netting and allocation of collateral(g)(h)
(607)(1,597)(905)0 (3,109)(607)(1,597)(905)0 (3,109)
Commodity derivative assets subtotal138 334 721 0 1,193 138 334 721 0 1,193 
DPP consideration0 639 0 0 639 0 639 0 0 639 
Total assets7,137 5,052 1,252 4,335 17,776 6,457 4,982 1,218 4,335 16,992 
Liabilities
Commodity derivative liabilities
Economic hedges(682)(1,928)(1,655)0 (4,265)(682)(1,928)(1,354)0 (3,964)
Proprietary trading0 (21)(4)0 (25)0 (21)(4)0 (25)
Effect of netting and allocation of collateral(g)(h)
540 1,918 1,067 0 3,525 540 1,918 1,067 0 3,525 
Commodity derivative liabilities subtotal(142)(31)(592)0 (765)(142)(31)(291)0 (464)
Deferred compensation obligation0 (145)0 0 (145)0 (42)0 0 (42)
Total liabilities(142)(176)(592)0 (910)(142)(73)(291)0 (506)
Total net assets$6,995 $4,876 $660 $4,335 $16,866 $6,315 $4,909 $927 $4,335 $16,486 
__________    
(a)Exelon excludes cash of $728 million and $409 million at June 30, 2021 and December 31, 2020, respectively, and restricted cash of $114 million and $59 million at June 30, 2021 and December 31, 2020, respectively, and includes long-term restricted cash of $52 million and $53 million at June 30, 2021 and December 31, 2020, respectively, which is reported in Other deferred debits in the Consolidated Balance Sheets. Generation excludes cash of $407 million and $171 million at June 30, 2021 and December 31, 2020, respectively, and restricted cash of $32 million and $20 million at June 30, 2021 and December 31, 2020, respectively. 
(b)Includes $103 million and $116 million of cash received from outstanding repurchase agreements at June 30, 2021 and December 31, 2020, respectively, and is offset by an obligation to repay upon settlement of the agreement as discussed in (e) below.
(c)Includes investments in equities sold short of $(52) million and $(62) million as of June 30, 2021 and December 31, 2020, respectively, held in an investment vehicle primarily to hedge the equity option component of its convertible debt.
(d)Includes derivative assets of less than $1 million and $2 million, which have total notional amounts of $2,016 million and $1,043 million at June 30, 2021 and December 31, 2020, respectively. The notional principal amounts for these instruments provide one measure of the transaction volume outstanding as of the periods ended and do not represent the amount of Exelon and Generation's exposure to credit or market loss.
(e)Excludes net liabilities of $94 million and $181 million at June 30, 2021 and December 31, 2020, respectively, which include certain derivative assets that have notional amounts of $137 million and $104 million at June 30, 2021 and December 31, 2020, respectively. These items consist of receivables related to pending securities sales, interest and dividend receivables, repurchase agreement obligations, and payables related to pending securities purchases. The repurchase agreements are generally short-term in nature with durations generally of 30 days or less.
(f)Includes equity investments held by Generation which were previously designated as equity investments without readily determinable fair value but are now publicly traded and therefore have readily determinable fair values. The first investment became publicly traded in the fourth quarter of 2020. Generation recorded the fair value of these investments in Other current assets on Exelon's and Generation's Consolidated Balance Sheets based on the quoted market prices of the stocks at June 30, 2021, which resulted in unrealized gains for investments that became publicly traded during 2021 of $102 million and $220 million within Other, net in Exelon's and Generation's Consolidated Statements of Operations and Comprehensive Income for the three and six months ended June 30, 2021, respectively.
(g)Collateral (received) from counterparties, net of collateral paid to counterparties, totaled $(169) million, $(207) million, and $(176) million allocated to Level 1, Level 2, and Level 3 mark-to-market derivatives, respectively, as of June 30, 2021. Collateral (received)/posted from counterparties, net of collateral paid to counterparties, totaled $(67) million, $321 million, and $162 million allocated to Level 1, Level 2, and Level 3 mark-to-market derivatives, respectively, as of December 31, 2020.
(h)Includes $858 million held and $209 million posted of variation margin with the exchanges as of June 30, 2021 and December 31, 2020, respectively.
113
 Exelon Generation
As of December 31, 2019Level 1 Level 2 Level 3 Not subject to leveling Total Level 1
Level 2
Level 3 Not subject to leveling
Total
Assets                   
Cash equivalents(a)
$639
 $—
 $—
 $—
 $639
 $214
 $—
 $—
 $—
 $214
NDT fund investments                  

Cash equivalents(b)
365
 87
 —
 —
 452
 365
 87
 —
 —
 452
Equities3,353

1,753

—

1,388

6,494

3,353

1,753

—

1,388

6,494
Fixed income                   
Corporate debt—
 1,469
 257
 —
 1,726
 —
 1,469
 257
 —
 1,726
U.S. Treasury and agencies1,808
 131
 —
 —
 1,939
 1,808
 131
 —
 —
 1,939
Foreign governments—
 42
 —
 —
 42
 —
 42
 —
 —
 42
State and municipal debt—
 90
 —
 —
 90
 —
 90
 —
 —
 90
Other—
 33
 —
 953
 986
 —
 33
 —
 953
 986
Fixed income subtotal1,808

1,765

257
 953

4,783

1,808

1,765

257
 953

4,783
Private credit—
 —
 254
 508
 762
 —
 —
 254
 508
 762
Private equity—
 —
 —
 402
 402
 —
 —
 —
 402
 402
Real estate—
 —
 —
 607
 607
 —
 —
 —
 607
 607
NDT fund investments subtotal(c)(d)
5,526

3,605

511
 3,858

13,500

5,526

3,605

511
 3,858
 13,500
Rabbi trust investments                   
Cash equivalents50
 —
 —
 —
 50
 4
 —
 —
 —
 4
Mutual funds81
 —
 —
 —
 81
 25
 —
 —
 —
 25
Fixed income—
 12
 —
 —
 12
 —
 —
 —
 —
 —
Life insurance contracts—
 78
 41
 —
 119
 —
 25
 —
 —
 25
Rabbi trust investments subtotal131

90

41
 —

262

29

25

—
 —

54
Commodity derivative assets                   
Economic hedges768
 2,491
 1,485
 —
 4,744
 768
 2,491
 1,485
 —
 4,744
Proprietary trading—
 37
 60
 —
 97
 —
 37
 60
 —
 97
Effect of netting and allocation of collateral(e)(f)
(908) (2,162) (588) —
 (3,658) (908) (2,162) (588) —
 (3,658)
Commodity derivative assets subtotal(140)
366

957
 —

1,183

(140)
366

957
 —

1,183
Total assets6,156

4,061

1,509

3,858

15,584

5,629

3,996

1,468

3,858

14,951


108
COMBINED NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)
(Dollars in millions, except per share data, unless otherwise noted)

Note 1314 — Fair Value of Financial Assets and Liabilities

 Exelon Generation
As of December 31, 2019Level 1 Level 2 Level 3 Not subject to leveling Total Level 1
Level 2
Level 3 Not subject to leveling
Total
Liabilities        
         
Commodity derivative liabilities                   
Economic hedges(1,071) (2,855) (1,228) —
 (5,154) (1,071) (2,855) (927) —
 (4,853)
Proprietary trading—
 (34) (15) —
 (49) —
 (34) (15) —
 (49)
Effect of netting and allocation of collateral(e)(f)
1,071
 2,714
 802
 —
 4,587
 1,071
 2,714
 802
 —
 4,587
Commodity derivative liabilities subtotal—

(175)
(441) —

(616)
—

(175)
(140) —

(315)
Deferred compensation obligation—
 (147) —
 —
 (147) —
 (41) —
 —
 (41)
Total liabilities—

(322)
(441) —

(763)
—

(216)
(140) —

(356)
Total net assets$6,156

$3,739

$1,068
 $3,858

$14,821

$5,629

$3,780

$1,328
 $3,858

$14,595
_________
(a)Exelon excludes cash of $684 million and $373 million at June 30, 2020 and December 31, 2019, respectively, and restricted cash of $132 million and $110 million at June 30, 2020 and December 31, 2019, respectively, and includes long-term restricted cash of $178 million and $177 million at June 30, 2020 and December 31, 2019, respectively, which is reported in Other deferred debits in the Consolidated Balance Sheets. Generation excludes cash of $401 million and $177 million at June 30, 2020 and December 31, 2019, respectively, and restricted cash of $73 million and $58 million at June 30, 2020 and December 31, 2019, respectively. 
(b)Includes $101 million and $90 million of cash received from outstanding repurchase agreements at June 30, 2020 and December 31, 2019, respectively, and is offset by an obligation to repay upon settlement of the agreement as discussed in (d) below.
(c)Includes derivative assets of less than $1 million and $2 million, which have total notional amounts of $769 million and $724 million at June 30, 2020 and December 31, 2019, respectively. The notional principal amounts for these instruments provide one measure of the transaction volume outstanding as of the fiscal years ended and do not represent the amount of Exelon and Generation's exposure to credit or market loss.
(d)Excludes net liabilities of $155 million and $147 million at June 30, 2020 and December 31, 2019, respectively. These items consist of receivables related to pending securities sales, interest and dividend receivables, repurchase agreement obligations, and payables related to pending securities purchases. The repurchase agreements are generally short-term in nature with durations generally of 30 days or less.
(e)Collateral posted/(received) from counterparties totaled $84 million, $319 million and $173 million allocated to Level 1, Level 2 and Level 3 mark-to-market derivatives, respectively, as of June 30, 2020. Collateral posted/(received) from counterparties, net of collateral paid to counterparties, totaled $163 million, $551 million and $214 million allocated to Level 1, Level 2 and Level 3 mark-to-market derivatives, respectively, as of December 31, 2019.
(f)Of the collateral posted/(received), $383 million and $511 million represents variation margin on the exchanges as of June 30, 2020 and December 31, 2019, respectively.
As of June 30, 2020,2021, Exelon and Generation have outstanding commitments to invest in fixed income, private credit, private equity, and real estate investments of approximately $58$364 million, $147 million, $316$224 million, and $410$320 million, respectively. These commitments will be funded by Generation’s existing NDT funds.
Exelon and Generation holdheld investments without readily determinable fair values with carrying amounts of $76$38 million and $66$26 million as of June 30, 2021, respectively. Exelon and Generation held investments without readily determinable fair values with carrying amounts of $73 million and $55 million as of December 31, 2020, respectively. Changes in fair value, cumulative adjustments, and impairments were not material for the three and six months ended June 30, 2021 and for the year ended December 31, 2020.

109
114



COMBINED NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)
(Dollars in millions, except per share data, unless otherwise noted)

Note 1314 — Fair Value of Financial Assets and Liabilities

ComEd, PECO, and BGE
ComEdPECOBGE
As of June 30, 2021Level 1Level 2Level 3TotalLevel 1Level 2Level 3TotalLevel 1Level 2Level 3Total
Assets
Cash equivalents(a)
$264 $0 $0 $264 $230 $0 $0 $230 $334 $0 $0 $334 
Rabbi trust investments
Mutual funds0 0 0 0 10 0 0 10 14 0 0 14 
Life insurance contracts0 0 0 0 0 15 0 15 0 0 0 0 
Rabbi trust investments subtotal0 0 0 0 10 15 0 25 14 0 0 14 
Total assets264 0 0 264 240 15 0 255 348 0 0 348 
Liabilities
Deferred compensation obligation0 (9)0 (9)0 (8)0 (8)0 (6)0 (6)
Mark-to-market derivative liabilities(b)
0 0 (265)(265)0 0 0 0 0 0 0 0 
Total liabilities0 (9)(265)(274)0 (8)0 (8)0 (6)0 (6)
Total net assets (liabilities)$264 $(9)$(265)$(10)$240 $7 $0 $247 $348 $(6)$0 $342 
ComEdPECOBGE
ComEd PECO BGE
As of June 30, 2020Level 1 Level 2 Level 3 Total Level 1 Level 2 Level 3 Total Level 1 Level 2 Level 3 Total
As of December 31, 2020As of December 31, 2020Level 1Level 2Level 3TotalLevel 1Level 2Level 3TotalLevel 1Level 2Level 3Total
Assets                       Assets
Cash equivalents(a)
$578
 $—
 $—
 $578
 $353
 $—
 $—
 $353
 $188
 $—
 $—
 $188
Cash equivalents(a)
$285 $0 $0 $285 $8 $0 $0 $8 $120 $0 $0 $120 
Rabbi trust investments      
       
       
Rabbi trust investments
Mutual funds—
 —
 —
 —
 8
 —
 —
 8
 10
 —
 —
 10
Mutual funds0 0 0 0 9 0 0 9 10 0 0 10 
Life insurance contracts—
 —
 —
 —
 —
 11
 —
 11
 —
 —
 1
 1
Life insurance contracts0 0 0 0 0 13 0 13 0 0 0 0 
Rabbi trust investments subtotal—

—

—

—

8

11

—

19

10

—

1

11
Rabbi trust investments subtotal0 0 0 0 9 13 0 22 10 0 0 10 
Total assets578

—

—

578

361

11

—

372

198

—

1

199
Total assets285 0 0 285 17 13 0 30 130 0 0 130 
Liabilities      
       
       
Liabilities
Deferred compensation obligation—
 (6) —
 (6) —
 (8) —
 (8) —
 (5) —
 (5)Deferred compensation obligation0 (8)0 (8)0 (9)0 (9)0 (5)0 (5)
Mark-to-market derivative liabilities(b)
—
 —
 (318) (318) —
 —
 —
 —
 —
 —
 —
 —
Mark-to-market derivative liabilities(b)
0 0 (301)(301)0 0 0 0 0 0 0 0 
Total liabilities—
 (6) (318) (324) —
 (8) —
 (8) —
 (5) —
 (5)Total liabilities0 (8)(301)(309)0 (9)0 (9)0 (5)0 (5)
Total net assets (liabilities)$578
 $(6) $(318) $254
 $361
 $3
 $—
 $364
 $198
 $(5) $1
 $194
Total net assets (liabilities)$285 $(8)$(301)$(24)$17 $4 $0 $21 $130 $(5)$0 $125 
__________
(a)ComEd excludes cash of $44 million and $83 million at June 30, 2021 and December 31, 2020, respectively, and restricted cash of $46 million and $37 million at June 30, 2021 and December 31, 2020, respectively, and includes long-term restricted cash of $43 million at both June 30, 2021 and December 31, 2020, respectively, which is reported in Other deferred debits in the Consolidated Balance Sheets. PECO excludes cash of $154 million and $18 million at June 30, 2021 and December 31, 2020, respectively. BGE excludes cash of $34 million and $24 million at June 30, 2021 and December 31, 2020, respectively, and restricted cash of $3 million and $1 million at June 30, 2021 and December 31, 2020, respectively.
(b)The Level 3 balance consists of the current and noncurrent liability of $23 million and $242 million, respectively, at June 30, 2021 and $33 million and $268 million, respectively, at December 31, 2020 related to floating-to-fixed energy swap contracts with unaffiliated suppliers.

115
 ComEd PECO BGE
As of December 31, 2019Level 1 Level 2 Level 3 Total Level 1 Level 2 Level 3 Total Level 1 Level 2 Level 3 Total
Assets                       
Cash equivalents(a)
$280
 $—
 $—
 $280
 $15
 $—
 $—
 $15
 $—
 $—
 $—
 $—
Rabbi trust investments      
       
       
Mutual funds—
 —
 —
 —
 8
 —
 —
 8
 8
 —
 —
 8
Life insurance contracts—
 —
 —
 —
 —
 11
 —
 11
 —
 —
 —
 —
Rabbi trust investments subtotal—

—

—

—

8

11

—

19

8

—

—

8
Total assets280

—

—

280

23

11

—

34

8

—

—

8
Liabilities      
       
       
Deferred compensation obligation—
 (8) —
 (8) —
 (9) —
 (9) —
 (5) —
 (5)
Mark-to-market derivative liabilities(b)
—
 —
 (301) (301) —
 —
 —
 —
 —
 —
 —
 —
Total liabilities—
 (8) (301) (309) —
 (9) —
 (9) —
 (5) —
 (5)
Total net assets (liabilities)$280
 $(8) $(301) $(29) $23
 $2
 $—
 $25
 $8
 $(5) $—
 $3

_________
(a)ComEd excludes cash of $109 million and $90 million at June 30, 2020 and December 31, 2019, respectively, and restricted cash of $37 million and $33 million at June 30, 2020 and December 31, 2019, respectively, and includes long-term restricted cash of $166 million and $163 million at June 30, 2020 and December 31, 2019, respectively, which is reported in Other deferred debits in the Consolidated Balance Sheets.  PECO excludes cash of $34 million and $12 million at June 30, 2020 and December 31, 2019, respectively.  BGE excludes cash of $7 million and $24 million at June 30, 2020 and December 31, 2019, respectively, and restricted cash of $1 million at both June 30, 2020 and December 31, 2019.
(b)The Level 3 balance consists of the current and noncurrent liability of $31 million and $287 million, respectively, at June 30, 2020, and $32 million and $269 million, respectively, at December 31, 2019, related to floating-to-fixed energy swap contracts with unaffiliated suppliers.




110
COMBINED NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)
(Dollars in millions, except per share data, unless otherwise noted)

Note 1314 — Fair Value of Financial Assets and Liabilities

PHI, Pepco, DPL, and ACE
As of June 30, 2021As of December 31, 2020
PHILevel 1Level 2Level 3TotalLevel 1Level 2Level 3Total
Assets
Cash equivalents(a)
$46 $0 $0 $46 $86 $0 $0 $86 
Rabbi trust investments
Cash equivalents59 0 0 59 55 0 0 55 
Mutual funds14 0 0 14 14 0 0 14 
Fixed income0 11 0 11 0 11 0 11 
Life insurance contracts0 26 34 60 0 26 34 60 
Rabbi trust investments subtotal73 37 34 144 69 37 34 140 
Total assets119 37 34 190 155 37 34 226 
Liabilities
Deferred compensation obligation0 (16)0 (16)0 (17)0 (17)
Total liabilities0 (16)0 (16)0 (17)0 (17)
Total net assets$119 $21 $34 $174 $155 $20 $34 $209 
PepcoDPLACE
As of June 30, 2021As of June 30, 2021Level 1Level 2Level 3TotalLevel 1Level 2Level 3TotalLevel 1Level 2Level 3Total
AssetsAssets
Cash equivalents(a)
Cash equivalents(a)
$28 $0 $0 $28 $5 $0 $0 $5 $12 $0 $0 $12 
As of June 30, 2020 As of December 31, 2019
PHILevel 1 Level 2 Level 3 Total Level 1 Level 2 Level 3 Total
Assets               
Cash equivalents(a)
$50
 $—
 $—
 $50
 $124
 $—
 $—
 $124
Rabbi trust investments      
       
Rabbi trust investments
Cash equivalents44
 —
 —
 44
 44
 —
 —
 44
Cash equivalents57 0 0 57 0 0 0 0 0 0 0 0 
Mutual funds13
 —
 —
 13
 14
 —
 —
 14
Fixed income—
 10
 —
 10
 —
 12
 —
 12
Fixed income0 2 0 2 0 0 0 0 0 0 0 0 
Life insurance contracts—
 24
 43
 67
 —
 24
 41
 65
Life insurance contracts0 26 34 60 0 0 0 0 0 0 0 0 
Rabbi trust investments subtotal57

34

43

134

58

36

41

135
Rabbi trust investments subtotal57 28 34 119 0 0 0 0 0 0 0 0 
Total assets107

34

43

184
 182

36

41

259
Total assets85 28 34 147 5 0 0 5 12 0 0 12 
Liabilities      
       
Liabilities
Deferred compensation obligation—
 (16) —
 (16) —
 (19) —
 (19)Deferred compensation obligation0 (2)0 (2)0 0 0 0 0 0 0 0 
Total liabilities—

(16)
—

(16)
—

(19)
—

(19)Total liabilities0 (2)0 (2)0 0 0 0 0 0 0 0 
Total net assets$107

$18

$43

$168
 $182

$17

$41

$240
Total net assets$85 $26 $34 $145 $5 $0 $0 $5 $12 $0 $0 $12 
116
 Pepco DPL ACE
As of June 30, 2020Level 1 Level 2 Level 3 Total Level 1 Level 2 Level 3 Total Level 1 Level 2 Level 3 Total
Assets
 
 
 
 
 
 
 
 
 
 
 
Cash equivalents(a)
$34
 $—
 $—
 $34
 $—
 $—
 $—
 $—
 $14
 $—
 $—
 $14
Rabbi trust investments                       
Cash equivalents43
 —
 —
 43
 —
 —
 —
 —
 —
 —
 —
 —
Fixed income—
 2
 —
 2
 —
 —
 —
 —
 —
 —
 —
 —
Life insurance contracts—
 24
 42
 66
 —
 —
 —
 —
 —
 —
 —
 —
Rabbi trust investments subtotal43

26

42

111

—

—

—

—

—

—

—

—
Total assets77

26

42

145

—

—

—

—

14

—

—

14
Liabilities
 
 
 

 
 
 
 
 
 
 
 
Deferred compensation obligation—
 (2) —
 (2) —
 —
 —
 —
 —
 —
 —
 —
Total liabilities—

(2)
—

(2)
—

—

—

—

—

—

—

—
Total net assets$77
 $24
 $42
 $143
 $—
 $—
 $—
 $—
 $14
 $—
 $—
 $14


111
COMBINED NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)
(Dollars in millions, except per share data, unless otherwise noted)

Note 1314 — Fair Value of Financial Assets and Liabilities

PepcoDPLACE
As of December 31, 2020Level 1Level 2Level 3TotalLevel 1Level 2Level 3TotalLevel 1Level 2Level 3Total
Assets
Cash equivalents(a)
$35 $0 $0 $35 $0 $0 $0 $0 $13 $0 $0 $13 
Rabbi trust investments
Cash equivalents53 0 0 53 0 0 0 0 0 0 0 0 
Fixed income0 2 0 2 0 0 0 0 0 0 0 0 
Life insurance contracts0 26 34 60 0 0 0 0 0 0 0 0 
Rabbi trust investments subtotal53 28 34 115 0 0 0 0 0 0 0 0 
Total assets88 28 34 150 0 0 0 0 13 0 0 13 
Liabilities
Deferred compensation obligation0 (2)0 (2)0 0 0 0 0 0 0 0 
Total liabilities0 (2)0 (2)0 0 0 0 0 0 0 0 
Total net assets$88 $26 $34 $148 $0 $0 $0 $0 $13 $0 $0 $13 

Pepco DPL ACE
As of December 31, 2019Level 1 Level 2 Level 3 Total Level 1 Level 2 Level 3 Total Level 1 Level 2 Level 3 Total
Assets
 
 
 
 
 
 
 
 
 
 
 
Cash equivalents(a)
$34
 $—
 $—
 $34
 $—
 $—
 $—
 $—
 $16
 $—
 $—
 $16
Rabbi trust investments                       
Cash equivalents43
 —
 —
 43
 —
 —
 —
 —
 —
 —
 —
 —
Fixed income—
 2
 —
 2
 —
 —
 —
 —
 —
 —
 —
 —
Life insurance contracts—
 24
 41
 65
 —
 —
 —
 —
 —
 —
 —
 —
Rabbi trust investments subtotal43

26

41

110

—

—

—

—

—

—

—

—
Total assets77

26

41

144

—

—

—

—

16

—

—

16
Liabilities                       
Deferred compensation obligation—
 (2) —
 (2) —
 —
 —
 —
 —
 —
 —
 —
Total liabilities—
 (2) —
 (2) —
 —
 —
 —
 —
 —
 —
 —
Total net assets (liabilities)$77
 $24
 $41

$142
 $—
 $—
 $—
 $—
 $16
 $—
 $—
 $16
_________
(a)PHI excludes cash of $36 million and $57 million at June 30, 2020 and December 31, 2019, respectively, and includes long-term restricted cash of $11 million and $14 million at June 30, 2020 and December 31, 2019, respectively, which is reported in Other deferred debits in the Consolidated Balance Sheets.  Pepco excludes cash of $18 million and $29 million at June 30, 2020 and December 31, 2019, respectively. DPL excludes cash of $6 million and $13 million at June 30, 2020 and December 31, 2019, respectively. ACE excludes cash of $8 million and $12 million at June 30, 2020 and December 31, 2019, respectively, and includes long-term restricted cash of $11 million and $14 million at June 30, 2020 and December 31, 2019, respectively, which is reported in Other deferred debits in the Consolidated Balance Sheets.

112
Table of Contents__________
COMBINED NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (a)— (Continued)PHI excludes cash of $61 million and $74 million at June 30, 2021 and December 31, 2020, respectively, and restricted cash of $5 million and NaN at June 30, 2021 and December 31, 2020, respectively, and includes long-term restricted cash of $9 million and $10 million at June 30, 2021 and December 31, 2020, respectively, which is reported in Other deferred debits in the Consolidated Balance Sheets. Pepco excludes cash of $17 million and $30 million at June 30, 2021 and December 31, 2020, respectively, and restricted cash of $5 million and NaN at June 30, 2021 and December 31, 2020, respectively. DPL excludes cash of $17 million and $15 million at June 30, 2021 and December 31, 2020, respectively. ACE excludes cash of $11 million and $17 million at June 30, 2021 and December 31, 2020, respectively, and includes long-term restricted cash of $9 million and $10 million at June 30, 2021 and December 31, 2020, respectively, which is reported in Other deferred debits in the Consolidated Balance Sheets.
(Dollars in millions, except per share data, unless otherwise noted)

Note 13 — Fair Value of Financial Assets and Liabilities

Reconciliation of Level 3 Assets and Liabilities
The following tables present the fair value reconciliation of Level 3 assets and liabilities measured at fair value on a recurring basis during the three and six months ended June 30, 20202021 and 2019:2020:
ExelonGenerationComEdPHI and Pepco
Three Months Ended June 30, 2021TotalNDT Fund
Investments		Mark-to-Market
Derivatives		Total GenerationMark-to-Market
Derivatives		Life Insurance ContractsEliminated in Consolidation
Balance as of March 31, 2021$426 $479 $207 $686 $(295)$35 $0 
Total realized / unrealized gains (losses)
Included in net income(357)1 (359)(a)(358)0 1 0 
Included in noncurrent payables to affiliates0 6 0 6 0 0 (6)
Included in regulatory assets36 0 0 0 30 (b)0 6 
Change in collateral(282)0 (282)(282)0 0 0 
Purchases, sales, and settlements
Purchases7 1 6 7 0 0 0 
Sales1 0 1 1 0 0 0 
Settlements(28)(26)0 (26)0 (2)0 
Transfers into Level 31 0 1 (c)1 0 0 0 
Transfers out of Level 3(39)0 (39)(c)(39)0 0 0 
Balance at June 30, 2021$(235)$461 $(465)$(4)$(265)$34 $0 
The amount of total (losses) gains included in income attributed to the change in unrealized gains (losses) related to assets and liabilities as of June 30, 2021$(372)$1 $(374)$(373)$0 $1 $0 
117
              
 Exelon Generation ComEd PHI and Pepco  
Three Months Ended June 30, 2020Total 
NDT Fund
Investments
 
Mark-to-Market
Derivatives
 Total Generation 
Mark-to-Market
Derivatives
 Life Insurance Contracts Eliminated in Consolidation
              
Balance as of March 31, 2020$1,088
 $498
 $862
 $1,360
 $(314) $42
 $—
Total realized / unrealized gains (losses)
     
      
Included in net income(166) (1) (166)
(a) 
(167) —
 1
 —
Included in regulatory assets/liabilities(4) —
 —
 —
 (4)
(b) 
—
 —
Change in collateral(42) —
 (42) (42) —
 —
 —
Purchases, sales, issuances and settlements

     
      
Purchases30
 3
 27
 30
 —
 —
 —
Sales(2) —
 (2) (2) —
 —
 —
Settlements(1) (1) —
 (1) —
 —
 —
Transfers into Level 3(9) —
 (9)
(c) 
(9) —
 —
 —
Transfers out of Level 3(11) —
 (11)
(c) 
(11) —
 —
 —
Balance at June 30, 2020$883
 $499
 $659
 $1,158
 $(318) $43
 $—
The amount of total (losses) gains included in income attributed to the change in unrealized gains (losses) related to assets and liabilities as of June 30, 2020$(72) $(1) $(72) $(73) $—
 $1
 $—
 Exelon Generation ComEd PHI and Pepco  
Six months ended June 30, 2020Total 
NDT Fund
Investments
 
Mark-to-Market
Derivatives
 Total Generation 
Mark-to-Market
Derivatives
 Life Insurance Contracts Eliminated in Consolidation
Balance as of December 31, 2019$1,068
 $511
 $817
 $1,328
 $(301) $41
 $—
Total realized / unrealized gains (losses)

     

      
Included in net income(156) (2) (156)
(a) 
(158) —
 2
 —
Included in noncurrent payables to affiliates—
 (1) —
 (1) —
 —
 1
Included in regulatory assets(18) —
 —
 —
 (17)
(b) 
—
 (1)
Change in collateral(41) —
 (41) (41) —
 —
 —
Purchases, sales, issuances and settlements

     

      
Purchases71
 6
 65
 71
 —
 —
 —
Sales(24) —
 (24) (24) —
 —
 —
Settlements(15) (15) —
 (15) —
 —
 —
Transfers into Level 3(6) —
 (6)
(c) 
(6) —
 —
 —
Transfers out of Level 34
 —
 4
(c) 
4
 —
 —
 —
Balance as of June 30, 2020$883
 $499
 $659
 $1,158
 $(318) $43
 $—
The amount of total gains (losses) included in income attributed to the change in unrealized gains (losses) related to assets and liabilities as of June 30, 2020$115
 $(2) $115
 $113
 $—
 $2
 $—



113
COMBINED NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)
(Dollars in millions, except per share data, unless otherwise noted)

Note 1314 — Fair Value of Financial Assets and Liabilities

ExelonGenerationComEdPHI and Pepco
Six months ended June 30, 2021TotalNDT Fund
Investments		Mark-to-Market
Derivatives		Total GenerationMark-to-Market
Derivatives		Life Insurance ContractsEliminated in Consolidation
Balance as of December 31, 2020$660 $497 $430 $927 $(301)$34 $0 
Total realized / unrealized gains (losses)
Included in net income(632)2 (636)(a)(634)0 2 0 
Included in noncurrent payables to affiliates0 7 0 7 0 0 (7)
Included in regulatory assets43 0 0 0 36 (b)0 7 
Change in collateral(338)0 (338)(338)0 0 0 
Purchases, sales, and settlements
Purchases115 1 114 115 0 0 0 
Sales1 0 1 1 0 0 0 
Settlements(48)(46)0 (46)0 (2)0 
Transfers into Level 31 0 1 (c)1 0 0 0 
Transfers out of Level 3(37)0 (37)(c)(37)0 0 0 
Balance as of June 30, 2021$(235)$461 $(465)$(4)$(265)$34 $0 
The amount of total (losses) gains included in income attributed to the change in unrealized gains (losses) related to assets and liabilities as of June 30, 2021$(518)$2 $(522)$(520)$0 $2 $0 
ExelonGenerationComEdPHI and Pepco
Three Months Ended June 30, 2020TotalNDT Fund
Investments		Mark-to-Market
Derivatives		Total GenerationMark-to-Market
Derivatives		Life Insurance ContractsEliminated in Consolidation
Balance as of March 31, 2020$1,088 $498 $862 $1,360 $(314)$42 $0 
Total realized / unrealized gains (losses)
Included in net income(166)(1)(166)(a)(167)0 1 0 
Included in regulatory assets/liabilities(4)0 0 0 (4)(b)0 0 
Change in collateral(42)0 (42)(42)0 0 0 
Purchases, sales, and settlements
Purchases30 3 27 30 0 0 0 
Sales(2)0 (2)(2)0 0 0 
Settlements(1)(1)0 (1)0 0 0 
Transfers into Level 3(9)0 (9)(c)(9)0 0 0 
Transfers out of Level 3(11)0 (11)(c)(11)0 0 0 
Balance as of June 30, 2020$883 $499 $659 $1,158 $(318)$43 $0 
The amount of total (losses) gains included in income attributed to the change in unrealized gains (losses) related to assets and liabilities as of June 30, 2020$(72)$(1)$(72)$(73)$0 $1 $0 
              
 Exelon Generation ComEd PHI and Pepco  
Three Months Ended June 30, 2019Total 
NDT Fund
Investments
 
Mark-to-Market
Derivatives
 Total Generation 
Mark-to-Market
Derivatives
 Life Insurance Contracts Eliminated in Consolidation
Balance as of March 31, 2019$838
 $540
 $499
 $1,039
 $(240) $39
 $—
Total realized / unrealized gains (losses)      

      
Included in net income275
 2
 272
(a) 
274
 —
 1
 —
Included in noncurrent payables to affiliates—
 10
 —
 10
 —
 —
 (10)
Included in regulatory assets(23) —
 —
 —
 (33)
(b) 
—
 10
Change in collateral106
 —
 106
 106
 —
 —
 —
Purchases, sales, issuances and settlements
     

      
Purchases51
 40
 11
 51
 —
 —
 —
Sales(1) —
 (1) (1) —
 —
 —
Settlements(53) (53) —
 (53) —
 —
 —
Transfers into Level 33
 —
 3
(c) 
3
 —
 —
 —
Transfers out of Level 3(17) —
 (17)
(c) 
(17) —
 —
 —
Balance as of June 30, 2019$1,179
 $539

$873

$1,412

$(273)
$40
 $—
The amount of total gains (losses) included in income attributed to the change in unrealized gains (losses) related to assets and liabilities as of June 30, 2019$339
 $1
 $337
 $338
 $—
 $1
 $—
118

 Exelon Generation ComEd PHI and Pepco  
Six Months Ended June 30, 2019Total 
NDT Fund
Investments
 
Mark-to-Market
Derivatives
 Total Generation 
Mark-to-Market
Derivatives
 Life Insurance Contracts Eliminated in Consolidation
Balance as of December 31, 2018$907
 $543
 $575
 $1,118
 $(249) $38
 $—
Total realized / unrealized gains (losses)
     

      
Included in net income46
 3
 41
(a) 
44
 —
 2
 —
Included in noncurrent payables to affiliates—
 21
 —
 21
 —
 —
 (21)
Included in regulatory assets(3) —
 —
 —
 (24)
(b) 
—
 21
Change in collateral187
 —
 187
 187
 —
 —
 —
Purchases, sales, issuances and settlements
     

      
Purchases110
 42
 68
 110
 —
 —
 —
Sales(1) —
 (1) (1) —
 —
 —
Settlements(70) (70) —
 (70) —
 —
 —
Transfers into Level 33
 —
 3
(c) 
3
 —
 —
 —
Transfers out of Level 3—
 —
 —
(c) 
—
 —
 —
 —
Balance as of June 30, 2019$1,179
 $539
 $873
 $1,412

$(273) $40
 $—
The amount of total (losses) gains included in income attributed to the change in unrealized gains (losses) related to assets and liabilities as of June 30, 2019$191
 $3
 $186
 $189
 $—
 $2
 $—


114
COMBINED NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)
(Dollars in millions, except per share data, unless otherwise noted)

Note 1314 — Fair Value of Financial Assets and Liabilities

ExelonGenerationComEdPHI and Pepco
Six Months Ended June 30, 2020TotalNDT Fund
Investments		Mark-to-Market
Derivatives		Total GenerationMark-to-Market
Derivatives		Life Insurance ContractsEliminated in Consolidation
Balance as of December 31, 2019$1,068 $511 $817 $1,328 $(301)$41 $0 
Total realized / unrealized gains (losses)
Included in net income(156)(2)(156)(a)(158)0 2 0 
Included in noncurrent payables to affiliates0 (1)0 (1)0 0 1 
Included in regulatory assets(18)0 0 0 (17)(b)0 (1)
Change in collateral(41)0 (41)(41)0 0 0 
Purchases, sales, and settlements
Purchases71 6 65 71 0 0 0 
Sales(24)0 (24)(24)0 0 0 
Settlements(15)(15)0 (15)0 0 0 
Transfers into Level 3(6)0 (6)(c)(6)0 0 0 
Transfers out of Level 34 0 4 (c)4 0 0 0 
Balance as of June 30, 2020$883 $499 $659 $1,158 $(318)$43 $0 
The amount of total gains (losses) included in income attributed to the change in unrealized gains (losses) related to assets and liabilities as of June 30, 2020$115 $(2)$115 $113 $0 $2 $0 
__________
(a)Includes a reduction for the reclassification of $94 million and $271 million of realized losses due to the settlement of derivative contracts for the three and six months ended June 30, 2020. Includes a reduction for the reclassification of $65 million and $145 million of realized losses due to the settlement of derivative contracts for the three and six months ended June 30, 2019.
(b)Includes $12 million of decreases in fair value and an increase for realized losses due to settlements of $8 million recorded in purchased power expense associated with floating-to-fixed energy swap contracts with unaffiliated suppliers for the three months ended June 30, 2020. Includes $35 million of decreases in fair value and an increase for realized losses due to settlements of $18 million recorded in purchased power expense associated with floating-to-fixed energy swap contracts with unaffiliated suppliers for the six months ended June 30, 2020. Includes $41 million of decreases in fair value and an increase for realized losses due to settlements of $8 million recorded in purchased power expense associated with floating-to-fixed energy swap contracts with unaffiliated suppliers for the three months ended June 30, 2019. Includes $37 million of decreases in fair value and an increase for realized losses due to settlements of $13 million recorded in purchased power expense associated with floating-to-fixed energy swap contracts with unaffiliated suppliers for the six months ended June 30, 2019.
(c)Transfers into and out of Level 3 generally occur when the contract tenor becomes less and more observable respectively, primarily due to changes in market liquidity or assumptions for certain commodity contracts.
(a)Includes an addition of $15 million for realized losses and a reduction of $114 million for realized gains due to the settlement of derivative contracts for the three and six months ended June 30, 2021. Includes a reduction of $94 million and $271 million for realized gains due to the settlement of derivative contracts for the three and six months ended June 30, 2020.
(b)Includes $25 million of increases in fair value and an increase for realized losses due to settlements of $5 million recorded in purchased power expense associated with floating-to-fixed energy swap contracts with unaffiliated suppliers for the three months ended June 30, 2021. Includes $23 million of increases in fair value and an increase for realized losses due to settlements of $13 million recorded in purchased power expense associated with floating-to-fixed energy swap contracts with unaffiliated suppliers for the six months ended June 30, 2021. Includes $12 million of decreases in fair value and an increase for realized losses due to settlements of $8 million recorded in purchased power expense associated with floating-to-fixed energy swap contracts with unaffiliated suppliers for the three months ended June 30, 2020. Includes $35 million of decrease in fair value and an increase for realized losses due to settlements of $18 million recorded in purchased power expense associated with floating-to-fixed energy swap contracts with unaffiliated suppliers for the six months ended June 30, 2020.
(c)Transfers into and out of Level 3 generally occur when the contract tenor becomes less and more observable respectively, primarily due to changes in market liquidity or assumptions for certain commodity contracts.
The following tables present the income statement classification of the total realized and unrealized gains (losses) included in income for Level 3 assets and liabilities measured at fair value on a recurring basis during the three and six months ended June 30, 20202021 and 2019:2020:
ExelonGenerationPHI and Pepco
Operating
Revenues		Purchased
Power and
Fuel		Operating and MaintenanceOther, netOperating
Revenues		Purchased
Power and
Fuel		Other, netOperating and Maintenance
Total (losses) gains included in net income for the three months ended June 30, 2021$(555)$196 $1 $1 $(555)$196 $1 $1 
Total (losses) gain included in net income for the six months ended June 30, 2021(670)34 2 2 (670)34 2 2 
Total unrealized (losses) gains for the three months ended June 30, 2021(543)169 1 1 (543)169 1 1 
Total unrealized (losses) gains for the six months ended June 30, 2021(608)86 2 2 (608)86 2 2 
119
 Exelon Generation PHI and Pepco
 Operating
Revenues		 Purchased
Power and
Fuel		 Operating and Maintenance Other, net Operating
Revenues		 Purchased
Power and
Fuel		 Other, net Operating and Maintenance
Total realized (losses) gains for the three months ended June 30, 2020$(137) $(29) $1
 $—
 $(137) $(29) $—
 $1
Total realized (losses) gains for the six months ended June 30, 2020(65) (91) 2
 —
 (65) (91) —
 2
Total unrealized (losses) gains for the three months ended June 30, 2020(39) (33) 1
 (1) (39) (33) (1) 1
Total unrealized gains (losses) for the six months ended June 30, 2020166
 (51) 2
 (2) 166
 (51) (2) 2
 Exelon Generation PHI and Pepco
 Operating
Revenues		 Purchased
Power and
Fuel		 Operating and Maintenance Other, net 
Operating
Revenues
 
Purchased
Power and
Fuel
 Other, net Operating and Maintenance
Total realized gains (losses) for the three months ended June 30, 2019$275
 $(3) $1
 $2
 $275
 $(3) $2
 $1
Total realized gains (losses) for the six months ended June 30, 2019147
 (106) 2
 3
 147
 (106) 3
 2
Total unrealized gains (losses) for the three months ended June 30, 2019360
 (23) 1
 1
 360
 (23) 1
 1
Total unrealized gains (losses) gains for the six months ended June 30, 2019269
 (83)
2

3
 269
 (83) 3
 2


115
COMBINED NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)
(Dollars in millions, except per share data, unless otherwise noted)

Note 1314 — Fair Value of Financial Assets and Liabilities

ExelonGenerationPHI and Pepco
Operating
Revenues		Purchased
Power and
Fuel		Operating and MaintenanceOther, netOperating
Revenues		Purchased
Power and
Fuel		Other, netOperating and Maintenance
Total (losses) gains included in net income for the three months ended June 30, 2020$(137)$(29)$1 $0 $(137)$(29)$0 $1 
Total (losses) gains included in net income for the six months ended June 30, 2020(65)(91)2 0 (65)(91)0 2 
Total unrealized (losses) gains for the three months ended June 30, 2020(39)(33)1 (1)(39)(33)(1)1 
Total unrealized gains (losses) for the six months ended June 30, 2020166 (51)2 (2)166 (51)(2)2 
Valuation Techniques Used to Determine Fair Value
Exelon’s valuation techniques used to measure the fair value of the assets and liabilities shown in the tables below are in accordance with the policies discussed in Note 1718 — Fair Value of Financial Assets and Liabilities of the Exelon 20192020 Form 10-K.
Valuation Techniques Used to Determine Net asset Value (Exelon and Generation)
Certain NDT Fund Investments are not classified within the fair value hierarchy and are included under the heading “Not subject to leveling” in the table above. These investments are measured at fair value using NAV per share as a practical expedient and include commingled funds, mutual funds which are not publicly quoted, managed private credit funds, private equity and real estate funds.
For commingled funds and mutual funds, which are not publicly quoted, the fair value is primarily derived from the quoted prices in active markets on the underlying securities and can typically be redeemed monthly with 30 or less days of notice and without further restrictions. For managed private credit funds, the fair value is determined using a combination of valuation models including cost models, market models, and income models and typically cannot be redeemed until maturity of the term loan. Private equity and real estate investments include those in limited partnerships that invest in operating companies and real estate holding companies that are not publicly traded on a stock exchange, such as, leveraged buyouts, growth capital, venture capital, distressed investments, investments in natural resources, and direct investments in pools of real estate properties. These investments typically cannot be redeemed and are generally liquidated over a period of 8 to 10 years from the initial investment date, which is based on Exelon’s understanding of the investment funds. Private equity and real estate valuations are reported by the fund manager and are based on the valuation of the underlying investments, which include inputs such as cost, operating results, discounted future cash flows, market based comparable data, and independent appraisals from sources with professional qualifications. These valuation inputs are unobservable.
120
Deferred Purchase Price Consideration (Exelon and Generation)
Exelon and Generation have DPP consideration for the sale of certain receivables of retail electricity at Generation. This amount is valued based on the sales price of the receivables net of allowance for credit losses based on accounts receivable aging historical experience coupled with specific identification through a credit monitoring process, which considers current conditions and forward-looking information such as industry trends, macroeconomic factors, changes in the regulatory environment, external credit ratings, publicly available news, payment status, payment history, and the exercise of collateral calls. Since the DPP consideration is based on the sales price of the receivables, it is categorized as Level 2 in the fair value hierarchy. See Note 5 - Accounts Receivable for additional information on the sale of certain receivables.













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

Note 1314 — Fair Value of Financial Assets and Liabilities

Mark-to-Market Derivatives (Exelon, Generation, and ComEd)
The table below discloses the significant inputs to the forward curve used to value mark-to-market derivatives.
Type of tradeFair Value at June 30, 2021Fair Value at December 31, 2020Valuation
Technique		Unobservable
Input		2021 Range & Arithmetic Average2020 Range & Arithmetic Average
Mark-to-market derivatives — Economic Hedges (Exelon and Generation)(a)(b)
$(285)$245 Discounted
Cash Flow		Forward power
price		$7.13-$281$39$2.25-$163$30
Forward gas
price		$1.53-$12.51$3.10$1.57-$7.88$2.59
Option
Model		Volatility
percentage		11%-209%33%11%-237%32%
Mark-to-market derivatives — Proprietary trading (Exelon and Generation)(a)(b)
$(4)$23 Discounted
Cash Flow		Forward power
price		$10-$132$38$10-$106$27
Mark-to-market derivatives (Exelon and ComEd)$(265)$(301)Discounted
Cash Flow
Forward heat
rate(c)
9x-10x9.13x8x-9x8.85x
Marketability
reserve		3%-7%4.77%3%-8%4.93%
Renewable
factor		94%-122%99%91%-123%99%
Type of trade Fair Value at June 30, 2020 Fair Value at December 31, 2019 
Valuation
Technique
 
Unobservable
Input
 2020 Range & Arithmetic Average 2019 Range & Arithmetic Average
Mark-to-market derivatives — Economic Hedges (Exelon and Generation)(a)(b)
 $459
 $558
 Discounted
Cash Flow		 Forward power
price		 $7-$148$28 $9-$180$29
  

   
 Forward gas
price		 $1.45-$7.66$2.58 $0.83-$10.72$2.55
  

   Option
Model		 Volatility
percentage		 9%-522%92% 8%-236%70%
                   
Mark-to-market derivatives — Proprietary trading (Exelon and Generation)(a)(b)
 $27
 $45
 Discounted
Cash Flow		 Forward power
price		 $13-$148$32 $25-$180$33
                   
Mark-to-market derivatives (Exelon and ComEd) $(318) $(301) Discounted
Cash Flow		 
Forward heat
rate(c)
 8x-9x8.85x 9x-10x9.68x
        Marketability
reserve		 4%-8%5.24% 3%-7%4.95%
        Renewable
factor		 93%-122%100% 91%-123%99%
__________

(a)The valuation techniques, unobservable inputs, ranges and arithmetic averages are the same for the asset and liability positions.
_________(b)The fair values do not include cash collateral (received)/posted on level three positions of $(176) million and $162 million as of June 30, 2021 and December 31, 2020, respectively.
(a)The valuation techniques, unobservable inputs, ranges and arithmetic averages are the same for the asset and liability positions.
(b)The fair values do not include cash collateral posted on level three positions of $173 million and $214 million as of June 30, 2020 and December 31, 2019, respectively.
(c)Quoted forward natural gas rates are utilized to project the forward power curve for the delivery of energy at specified future dates. The natural gas curve is extrapolated beyond its observable period to the end of the contract’s delivery.
(c)Quoted forward natural gas rates are utilized to project the forward power curve for the delivery of energy at specified future dates. The natural gas curve is extrapolated beyond its observable period to the end of the contract’s delivery.
The inputs listed above, which are as of the balance sheet date, would have a direct impact on the fair values of the above instruments if they were adjusted. The significant unobservable inputs used in the fair value measurement of Generation’s commodity derivatives are forward commodity prices and for options is price volatility. Increases (decreases) in the forward commodity price in isolation would result in significantly higher (lower) fair values for long positions (contracts that give Generation the obligation or option to purchase a commodity), with offsetting impacts to short positions (contracts that give Generation the obligation or right to sell a commodity). Increases (decreases) in volatility would increase (decrease) the value for the holder of the option (writer of the option). Generally, a change in the estimate of forward commodity prices is unrelated to a change in the estimate of volatility of prices. An increase to the reserves listed above would decrease the fair value of the positions. An increase to the heat rate or renewable factors would increase the fair value accordingly. Generally, interrelationships exist between market prices of natural gas and power. As such, an increase in natural gas pricing would potentially have a similar impact on forward power markets.

14.
15. Commitments and Contingencies (All Registrants)
The following is an update to the current status of commitments and contingencies set forth in Note 1819 of the Exelon 20192020 Form 10-K.
Commitments
PHI Merger Commitments (Exelon, PHI, Pepco, DPL and ACE). Approval of the PHI Merger in Delaware, New Jersey, Maryland and the District of Columbia was conditioned upon Exelon and PHI agreeing to certain

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

Note 14 — Commitments and Contingencies

commitments. The following amounts represent total commitment costs that have been recorded since the acquisition date and the total remaining obligations for Exelon, PHI, Pepco, DPL, and ACE as of June 30, 2020:2021:
DescriptionExelon PHI Pepco DPL ACE
Total commitments$513
 $320
 $120
 $89
 $111
Remaining commitments(a)
91
 72
 60
 7
 5
121

_________
(a)Remaining commitments extend through 2026 and include rate credits, energy efficiency programs and delivery system modernization.

COMBINED NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)
(Dollars in millions, except per share data, unless otherwise noted)

Note 15 — Commitments and Contingencies
DescriptionExelonPHIPepcoDPLACE
Total commitments$513 $320 $120 $89 $111 
Remaining commitments(a)
76 63 52 7 4 
__________
(a)Remaining commitments extend through 2026 and include rate credits, energy efficiency programs and delivery system modernization.
In addition, Exelon is committed to develop or to assist in the commercial development of approximately 37 MWs of new solar generation in Maryland, District of Columbia, and Delaware at an estimated cost of approximately $127$135 million, which will generate future earnings at Exelon and Generation. Investment costs, which are expected to be primarily capital in nature, are recognized as incurred and recorded in Exelon's and Generation's financial statements. As of June 30, 2020, 272021, approximately 33 MWs of new generation were developed and Exelon and Generation have incurred costs of $123$121 million. Exelon has also committed to purchase 100 MWs of wind energy in PJM. DPL has committed to conducting three RFPs to procure up to a total of 120 MWs of wind RECs for the purpose of meeting Delaware's renewable portfolio standards. DPL has conducted two of the three wind REC RFPs. The first 40 MW wind REC tranche was conducted in 2017 and did not result in a purchase agreement. The second 40 MW wind REC tranche was conducted in 2018 and resulted in a proposed REC purchase agreement that was approved by the DPSC in 2019. The third and final 40 MW wind REC tranche will be conducted in 2022.

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COMBINED NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)
(Dollars in millions, except per share data, unless otherwise noted)

Note 1415 — Commitments and Contingencies

Commercial Commitments (All Registrants). The Registrants’ commercial commitments as of June 30, 2020,2021, representing commitments potentially triggered by future events were as follows:
Expiration within
Total202120222023202420252026 and beyond
Exelon
Letters of credit$1,751 $591 $1,160 $0 $0 $0 $0 
Surety bonds(a)
920 619 299 0 2 0 0 
Financing trust guarantees378 0 0 0 0 0 378 
Guaranteed lease residual values(b)
30 0 3 3 6 6 12 
Total commercial commitments$3,079 $1,210 $1,462 $3 $8 $6 $390 
Generation
Letters of credit$1,735 $578 $1,157 $0 $0 $0 $0 
Surety bonds(a)
772 514 258 0 0 0 0 
Total commercial commitments$2,507 $1,092 $1,415 $0 $0 $0 $0 
ComEd
Letters of credit$7 $7 $0 $0 $0 $0 $0 
Surety bonds(a)
17 9 6 0 2 0 0 
Financing trust guarantees200 0 0 0 0 0 200 
Total commercial commitments$224 $16 $6 $0 $2 $0 $200 
PECO
Surety bonds(a)
$3 $1 $2 $0 $0 $0 $0 
Financing trust guarantees178 0 0 0 0 0 178 
Total commercial commitments$181 $1 $2 $0 $0 $0 $178 
BGE
Letters of credit$2 $0 $2 $0 $0 $0 $0 
Surety bonds(a)
3 2 1 0 0 0 0 
Total commercial commitments$5 $2 $3 $0 $0 $0 $0 
PHI
Surety bonds(a)
$25 $8 $17 $0 $0 $0 $0 
Guaranteed lease residual values(b)
30 0 3 3 6 6 12 
Total commercial commitments$55 $8 $20 $3 $6 $6 $12 
Pepco
Surety bonds(a)
$17 $4 $13 $0 $0 $0 $0 
Guaranteed lease residual values(b)
10 0 1 1 2 2 4 
Total commercial commitments$27 $4 $14 $1 $2 $2 $4 
DPL
Surety bonds(a)
$4 $2 $2 $0 $0 $0 $0 
Guaranteed lease residual values(b)
13 0 1 1 3 3 5 
Total commercial commitments$17 $2 $3 $1 $3 $3 $5 
ACE
Surety bonds(a)
$4 $2 $2 $0 $0 $0 $0 
Guaranteed lease residual values(b)
7 0 1 1 1 1 3 
Total commercial commitments$11 $2 $3 $1 $1 $1 $3 
   Expiration within
 Total 2020 2021 2022 2023 2024 2025 and beyond
Exelon             
Letters of credit$1,291
 $475
 $816
 $—
 $—
 $—
 $—
Surety bonds(a)
902
 550
 335
 17
 —
 —
 —
Financing trust guarantees378
 —
 —
 —
 —
 —
 378
Guaranteed lease residual values(b)
28
 1
 2
 4
 3
 7
 11
Total commercial commitments$2,599
 $1,026
 $1,153
 $21
 $3

$7
 $389
              
Generation             
Letters of credit$1,276
 $467
 $809
 $—
 $—
 $—
 $—
Surety bonds(a)
754
 479
 258
 17
 —
 —
 —
Total commercial commitments$2,030
 $946
 $1,067
 $17
 $—
 $—
 $—
              
ComEd             
Letters of credit$7
 $4
 $3
 $—
 $—
 $—
 $—
Surety bonds(a)
15
 8
 7
 —
 —
 —
 —
Financing trust guarantees200
 —
 —
 —
 —
 —
 200
Total commercial commitments$222
 $12
 $10
 $—
 $—
 $—
 $200
              
PECO             
Surety bonds(a)
$6
 $4
 $2
 $—
 $—
 $—
 $—
Financing trust guarantees178
 —
 —
 —
 —
 —
 178
Total commercial commitments$184
 $4
 $2
 $—
 $—
 $—
 $178
              
BGE             
Letters of credit$2
 $2
 $—
 $—
 $—
 $—
 $—
Surety bonds(a)
3
 2
 1
 —
 —
 —
 —
Total commercial commitments$5
 $4
 $1
 $—
 $—
 $—
 $—
              
PHI             
Surety bonds(a)
$22
 $6
 $16
 $—
 $—
 $—
 $—
Guaranteed lease residual values(b)
28
 1
 2
 4
 3
 7
 11
Total commercial commitments$50
 $7
 $18
 $4
 $3
 $7
 $11
              
Pepco             
Surety bonds(a)
$14
 $1
 $13
 $—
 $—
 $—
 $—
Guaranteed lease residual values(b)
9
 —
 1
 1
 1
 2
 4
Total commercial commitments$23
 $1
 $14
 $1
 $1
 $2
 $4
              
DPL             
Surety bonds(a)
$4
 $3
 $1
 $—
 $—
 $—
 $—
Guaranteed lease residual values(b)
12
 —
 1
 2
 1
 4
 4
Total commercial commitments$16
 $3
 $2
 $2
 $1
 $4
 $4
              
ACE             
Surety bonds(a)
$4
 $2
 $2
 $—
 $—
 $—
 $—
Guaranteed lease residual values(b)
7
 1
 —
 1
 1
 1
 3
Total commercial commitments$11
 $3
 $2
 $1
 $1
 $1
 $3
__________
_________
(a)Surety bonds—Guarantees issued related to contract and commercial agreements, excluding bid bonds.

(a)Surety bonds—Guarantees issued related to contract and commercial agreements, excluding bid bonds.
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(Dollars in millions, except per share data, unless otherwise noted)

Note 1415 — Commitments and Contingencies

(b)Represents the maximum potential obligation in the event that the fair value of certain leased equipment and fleet vehicles is zero at the end of the maximum lease term. The lease term associated with these assets ranges from 1 to 8 years. The maximum potential obligation at the end of the minimum lease term would be $75 million guaranteed by Exelon and PHI, of which $26 million, $31 million, and $18 million is guaranteed by Pepco, DPL, and ACE, respectively. Historically, payments under the guarantees have not been made and PHI believes the likelihood of payments being required under the guarantees is remote.
(b)Represents the maximum potential obligation in the event that the fair value of certain leased equipment and fleet vehicles is zero at the end of the maximum lease term. The lease term associated with these assets ranges from 1 to 8 years. The maximum potential obligation at the end of the minimum lease term would be $74 million guaranteed by Exelon and PHI, of which $25 million, $31 million and $18 million is guaranteed by Pepco, DPL and ACE, respectively. Historically, payments under the guarantees have not been made and PHI believes the likelihood of payments being required under the guarantees is remote.
Environmental Remediation Matters
General (All Registrants). The Registrants’ operations have in the past, and may in the future, require substantial expenditures to comply with environmental laws. Additionally, under Federal and state environmental laws, the Registrants are generally liable for the costs of remediating environmental contamination of property now or formerly owned by them and of property contaminated by hazardous substances generated by them. The Registrants own or lease a number of real estate parcels, including parcels on which their operations or the operations of others may have resulted in contamination by substances that are considered hazardous under environmental laws. In addition, the Registrants are currently involved in a number of proceedings relating to sites where hazardous substances have been deposited and may be subject to additional proceedings in the future. Unless otherwise disclosed, the Registrants cannot reasonably estimate whether they will incur significant liabilities for additional investigation and remediation costs at these or additional sites identified by the Registrants, environmental agencies or others, or whether such costs will be recoverable from third parties, including customers. Additional costs could have a material, unfavorable impact on the Registrants' financial statements.
MGP Sites (Exelon and the Utility Registrants). ComEd, PECO, BGE, and DPL have identified sites where former MGP or gas purification activities have or may have resulted in actual site contamination. For almost all of these sites, there are additional PRPs that may share responsibility for the ultimate remediation of each location.
•ComEd has 21 sites that are currently under some degree of active study and/or remediation. ComEd expects the majority of the remediation at these sites to continue through at least 2025.2026.
•PECO has 87 sites that are currently under some degree of active study and/or remediation. PECO expects the majority of the remediation at these sites to continue through at least 2022.2023.
•BGE has 4 sites that currently require some level of remediation and/or ongoing activity. BGE expects the majority of the remediation at these sites to continue through at least 2021.2023.
•DPL has 1 site that is currently under study and the required cost at the site is not expected to be material.
The historical nature of the MGP and gas purification sites and the fact that many of the sites have been buried and built over, impacts the ability to determine a precise estimate of the ultimate costs prior to initial sampling and determination of the exact scope and method of remedial activity. Management determines its best estimate of remediation costs using all available information at the time of each study, including probabilistic and deterministic modeling for ComEd and PECO, and the remediation standards currently required by the applicable state environmental agency. Prior to completion of any significant clean up, each site remediation plan is approved by the appropriate state environmental agency.
ComEd, pursuant to an ICC order, and PECO, pursuant to settlements of natural gas distribution rate cases with the PAPUC, are currently recovering environmental remediation costs of former MGP facility sites through customer rates. While BGE and DPL do not have riders for MGP clean-up costs, they have historically received recovery of actual clean-up costs in distribution rates.

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

Note 1415 — Commitments and Contingencies

As of June 30, 20202021 and December 31, 2019,2020, the Registrants had accrued the following undiscounted amounts for environmental liabilities in Other current liabilities and Other deferred credits and other liabilities within their respective Consolidated Balance Sheets:
June 30, 2020 December 31, 2019June 30, 2021December 31, 2020
Total environmental
investigation and
remediation liabilities
 
Portion of total related to
MGP investigation and
remediation
 
Total environmental
investigation and
remediation liabilities
 
Portion of total related to
MGP investigation and
remediation
Total environmental
investigation and
remediation liabilities		Portion of total related to
MGP investigation and
remediation		Total environmental
investigation and
remediation liabilities		Portion of total related to
MGP investigation and
remediation
Exelon$463

$309
 $478

$320
Exelon$461 $297 $483 $314 
Generation103
 —
 105
 —
Generation117 0 121 0 
ComEd293
 292
 304
 303
ComEd273 272 293 293 
PECO19
 17
 19
 17
PECO22 20 23 21 
BGE2
 —
 2
 —
BGE6 5 2 0 
PHI46

—
 48

—
PHI43 0 44 0 
Pepco44
 —
 46
 —
Pepco41 0 42 0 
DPL1
 —
 1
 —
DPL1 0 1 0 
ACE1
 —
 1
 —
ACE1 0 1 0 
Cotter Corporation (Exelon and Generation). The EPA has advised Cotter Corporation (Cotter), a former ComEd subsidiary, that it is potentially liable in connection with radiological contamination at a site known as the West Lake Landfill in Missouri. In 2000, ComEd sold Cotter to an unaffiliated third-party. As part of the sale, ComEd agreed to indemnify Cotter for any liability arising in connection with the West Lake Landfill. In connection with Exelon’s 2001 corporate restructuring, this responsibility to indemnify Cotter was transferred to Generation. Including Cotter, there are three PRPs participating in the West Lake Landfill remediation proceeding. Investigation by Generation has identified a number of other parties who also may be PRPs and could be liable to contribute to the final remedy. Further investigation is ongoing.
In September 2018, the EPA issued its Record of Decision (ROD) Amendment (RODA) for the selection of a final remedy. The ROD AmendmentRODA modified the remedy previously selected by EPA in its 2008 ROD.Record of Decision (ROD). While the ROD required only that the radiological materials and other wastes at the site be capped, the ROD Amendment2018 RODA requires partial excavation of the radiological materials in addition to the previously selected capping remedy. The ROD AmendmentRODA also allows for variation in depths of excavation depending on radiological concentrations. The EPA and the PRPs have entered into a Consent Agreement to perform the Remedial Design, which is expected to be completed by early 2022. In March 2019 the PRPs received Special Notice Letters from the EPA to perform the Remedial Action work. On October 8, 2019, Cotter (Generation’s indemnitee) provided a non-binding good faith offer to conduct, or finance, a portion of the remedy, subject to certain conditions. The total estimated cost of the remedy, taking into account the current EPA technical requirements and the total costs expected to be incurred collectively by the PRPs in fully executing the remedy, is approximately $280 million, including cost escalation on an undiscounted basis, which would be allocated among the final group of PRPs. Generation has determined that a loss associated with the EPA’s partial excavation and enhanced landfill cover remedy is probable and has recorded a liability included in the table above, that reflects management’s best estimate of Cotter’s allocable share of the ultimate cost. Given the joint and several nature of this liability, the magnitude of Generation’s ultimate liability will depend on the actual costs incurred to implement the required remedy as well as on the nature and terms of any cost-sharing arrangements with the final group of PRPs. Therefore, it is reasonably possible that the ultimate cost and Cotter's associated allocable share could differ significantly once these uncertainties are resolved, which could have a material impact on Exelon's and Generation's future financial statements.
One of the other PRPs has indicated it will be making a contribution claim against Cotter for costs that it has incurred to prevent thea subsurface fire from spreading to those areas of the West Lake Landfill where radiological materials are believed to have been disposed. At this time, Exelon and Generation do not possess sufficient information to assess this claim and therefore are unable to estimate a range of loss, if any. As such, no liability has been recorded for the potential contribution claim. It is reasonably possible, however, that resolution of this matter could have a material, unfavorable impact on Exelon’s and Generation's financial statements.
In January 2018, the PRPs were advised by the EPA that it will begin an additional investigation and evaluation of groundwater conditions at the West Lake Landfill. In September 2018, the PRPs agreed to an Administrative

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

Note 1415 — Commitments and Contingencies

Settlement Agreement and Order on Consent for the performance by the PRPs of the groundwater Remedial Investigation (RI)/and Feasibility Study (FS)(RI/FS). The purpose of this RI/FS is to define the nature and extent of any groundwater contamination from the West Lake Landfill site and evaluate remedial alternatives. Generation estimates the undiscounted cost for the groundwater RI/FS to be approximately $20$30 million. Generation determined a loss associated with the RI/FS is probable and has recorded a liability included in the table above that reflects management’s best estimate of Cotter’s allocable share of the cost among the PRPs. At this time Generation cannot predict the likelihood or the extent to which, if any, remediation activities may be required and therefore cannot estimate a reasonably possible range of loss for response costs beyond those associated with the RI/FS component. It is reasonably possible, however, that resolution of this matter could have a material, unfavorable impact on Exelon’s and Generation’s future financial statements.
In August 2011, Cotter was notified by the DOJ that Cotter is considered a PRP with respect to the government’s clean-up costs for contamination attributable to low level radioactive residues at a former storage and reprocessing facility named Latty Avenue near St. Louis, Missouri. The Latty Avenue site is included in ComEd’s (now Generation's) indemnification responsibilities discussed above as part of the sale of Cotter. The radioactive residues had been generated initially in connection with the processing of uranium ores as part of the U.S. Government’s Manhattan Project. Cotter purchased the residues in 1969 for initial processing at the Latty Avenue facility for the subsequent extraction of uranium and metals. In 1976, the NRC found that the Latty Avenue site had radiation levels exceeding NRC criteria for decontamination of land areas. Latty Avenue was investigated and remediated by the United States Army Corps of Engineers pursuant to funding under FUSRAP. Pursuant to a series of annual agreements since 2011, the DOJ and the PRPs have tolled the statute of limitations until February 28,August 31, 2021 so that settlement discussions can proceed. On August 3, 2020, the DOJ advised Cotter and the other PRPs that it is seeking approximately $90 million from all the PRPs and has directed that the PRPs must submit a good faith joint proposed settlement offer. At this time, the DOJ has stayed their request for a good faith offer by December 1, 2020.while the parties review cost documentation associated with the cost claim. Generation has determined that a loss associated with this matter is probable under its indemnification agreement with Cotter and has recorded an estimated liability, which is included in the table above.
Benning Road Site (Exelon, Generation, PHI, and Pepco). In September 2010, PHI received a letter from EPA identifying the Benning Road site as one of six land-based sites potentially contributing to contamination of the lower Anacostia River. A portion of the site was formerly the location of a Pepco Energy Services electric generating facility, which was deactivated in June 2012. The remaining portion of the site consists of a Pepco transmission and distribution service center that remains in operation. In December 2011, the U.S. District Court for the District of Columbia approved a Consent Decree entered into by Pepco and Pepco Energy Services with the DOEE, which requires Pepco and Pepco Energy Services to conduct a RI/FS for the Benning Road site and an approximately 10 to 15-acre portion of the adjacent Anacostia River.
Since 2013, Pepco and Pepco Energy Services (now Generation, pursuant to Exelon's 2016 acquisition of PHI) have been performing RI work and have submitted multiple draft RI reports to the DOEE. In September 2019, Pepco and Generation issued a draft “final” RI report which DOEE approved and on October 4, 2019 released this document for review and comment by the public. The 45-day comment period ended on November 18, 2019 and a public meeting was held by Pepco on November 2, 2019.February 3, 2020. Pepco and Generation will proceed to developare developing a FS to evaluate possible remedial alternatives for submission to DOEE. The Court has established a schedule for completion of the FS, and approval by the DOEE, by SeptemberMarch 16, 2021.
2022. After completion and approval of the FS, DOEE will then prepare a Proposed Plan for public comment and then issue a Record of DecisionROD identifying any further response actions determined to be necessary, after considering public comment on the Proposed Plan.necessary. PHI, Pepco, and Generation have determined that a loss associated with this matter is probable and have accrued an estimated liability, which is included in the table above.
Anacostia River Tidal Reach (Exelon, PHI, and Pepco). Contemporaneous with the Benning Road site RI/FS being performed by Pepco and Generation, DOEE and the National Park ServiceNPS have been conducting a separate RI/FS focused on the entire tidal reach of the Anacostia River extending from just north of the Maryland-District of Columbia boundary line to the confluence of the Anacostia and Potomac Rivers. The river-wide RI incorporated the results of the river sampling performed by Pepco and Pepco Energy Services as part of the Benning RI/FS, as well as similar sampling efforts conducted by owners of other sites adjacent to this segment of the river and supplemental river sampling conducted by DOEE’s contractor. DOEE asked Pepco, along with parties responsible for other sites along the river, to participate in a "Consultative Working Group" to provide input into the process for future remedial actions and to ensure proper coordination with the other river cleanup efforts currently underway, including cleanup of the river segment adjacent to the Benning Road site resulting from the Benning Road site RI/FS. In addition, the

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

Note 14 — Commitments and Contingencies

District of Columbia Council directed DOEE to form an official advisory committee made up of members of federal, state and local environmental regulators, community and environmental groups and various academic and technical experts to provide guidance and support to DOEE as the project progressed. This group, called the Anacostia Leadership Council, has met regularly since it was formed. Pepco has participated in the Consultative Working Group. In April 2018, DOEE released a draft RI report for public review and comment. Pepco submitted written comments to the draft RI and participated in a public hearing.
Pepco has determined that it is probable that costs for remediation will be incurred and recorded a liability in the third quarter 2019 for management’s best estimate of its share of those costs based on DOEE’s stated position following a seriescosts. On September 30, 2020, DOEE
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COMBINED NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)
(Dollars in millions, except per share data, unless otherwise noted)

Note 15 — Commitments and the Consultative Working Group. On December 27, 2019, DOEE Contingencies
released for review and comment by the public a Focused Feasibility Study (FFS) and a Proposed Plan (PP).its Interim ROD. The FFS and PP will be the basis for the Interim ROD which is expected to be completed in September 2020. The FFS and PP are consistent with the DOEE’s stated position to followreflects an adaptive management approach which will allowrequire several identified “hot spots” in the river to be addressed first while continuing to conduct studies and to monitor the river to evaluate improvements and determine potential future remediation plans. The adaptive management process chosen by DOEE is less intrusive, provides more long-term environmental certainty, is less costly, and allows for site specific remediation plans already underway, including the plan for the Benning Road site to proceed to conclusion. Pepco concluded that incremental exposure remains reasonably possible, howeverbut management cannot reasonably estimate a range of loss beyond the amounts recorded, which are included in the table above.
On July 12, 2021, DOEE and NPS held a virtual meeting with the PRP's in response to a General Notice Letter sent by each agency inviting the PRP's to participate in discussions, which PEPCO attended.
In addition to the activities associated with the remedial process outlined above, CERCLA separately requires federal and state (here including Washington, D.C.) Natural Resource Trustees (federal or state agencies designated by the President or the relevant state, respectively, or Indian tribes) to conduct an assessment of any damages to natural resources within their jurisdiction as a result of the contamination that is being remediated. The Trustees can seek compensation from responsible parties for such damages, including restoration costs. The Natural Resource Damages (NRD) assessment typically takes place following cleanup because cleanups sometimes also effectively restore affected natural resources. During the second quarter of 2018, Pepco became aware that the Trustees are in the beginning stages of thisa Natural Resources Damages (NRD) assessment, a process that often takes many years beyond the remedial decision to complete. Pepco has concluded that a loss associated with the eventual NRD assessment is reasonably possible. Due to the very early stage of the assessment process, Pepco cannot reasonably estimate the range of loss.
Litigation and Regulatory Matters
Asbestos Personal Injury Claims (Exelon and Generation). Generation maintains a reserve for claims associated with asbestos-related personal injury actions in certain facilities that are currently owned by Generation or were previously owned by ComEd and PECO. The estimated liabilities are recorded on an undiscounted basis and exclude the estimated legal costs associated with handling these matters, which could be material.
At June 30, 20202021 and December 31, 2019,2020, Exelon and Generation had recorded estimated liabilities of approximately $92$85 million and $83$89 million, respectively, in total for asbestos-related bodily injury claims. As of June 30, 2020,2021, approximately $26$21 million of this amount related to 268230 open claims presented to Generation, while the remaining $66$64 million is for estimated future asbestos-related bodily injury claims anticipated to arise through 2055, based on actuarial assumptions and analyses, which are updated on an annual basis. On a quarterly basis, Generation monitors actual experience against the number of forecasted claims to be received and expected claim payments and evaluates whether adjustments to the estimated liabilities are necessary.
It is reasonably possible that additional exposure to estimated future asbestos-related bodily injury claims in excess of the amount accrued could have a material, unfavorable impact on Exelon’s and Generation’s financial statements. However, management cannot reasonably estimate a range of loss beyond the amounts recorded.
City of Everett Tax Increment FinancingDeferred Prosecution Agreement (Exelon(DPA) and Generation). On April 10, 2017, the City of Everett petitioned the Massachusetts Economic Assistance Coordinating Council (EACC) to revoke the 1999 tax increment financing agreement (TIF Agreement) relating to Mystic Units 8 and 9 on the grounds that the total investment in Mystic Units 8 and 9 materially deviates from the investment set forth in the TIF Agreement. On October 31, 2017, a three-member panel of the EACC conducted an administrative hearing on the City’s petition. On November 30, 2017, the hearing panel issued a tentative decision denying the City’s petition, finding that there was no material misrepresentation that would justify revocation of the TIF Agreement. On December 13, 2017, the tentative decision was adopted by the full EACC. On January 12, 2018, the City filed a complaint in Massachusetts

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

Note 14 — Commitments and Contingencies

Superior Court requesting, among other things, that the court set aside the EACC’s decision, grant the City’s request to decertify the Project and the TIF Agreement, and award the City damages for alleged underpaid taxes over the period of the TIF Agreement. On January 8, 2020, the Massachusetts Superior Court affirmed the decision of the EACC denying the City's petition. The City had until March 9, 2020 to appeal the decision and did not. As a result, the decision is final and the case is resolved. It is reasonably possible that property taxes assessed in future periods, including those following the expiration of the TIF Agreement on June 30, 2020, could be material to Generation’s financial statements.
SubpoenasRelated Matters (Exelon and ComEd).Exelon and ComEd received a grand jury subpoena in the second quarter of 2019 from the U.S. Attorney’s Office for the Northern District of Illinois (USAO) requiring production of information concerning their lobbying activities in the State of Illinois. On October 4, 2019, Exelon and ComEd received a second grand jury subpoena from the USAO requiring production of records of any communications with certain individuals and entities. On October 22, 2019, the SEC notified Exelon and ComEd that it had also opened an investigation into their lobbying activities. On July 17, 2020, ComEd entered into a Deferred Prosecution Agreement (DPA)DPA with the USAO to resolve the USAO investigation. 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 StatesU.S. 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 were recorded within Operating and maintenance expensewhich was paid in Exelon’s and ComEd’s Consolidated Statements of Operations and Comprehensive Income in the second quarter ofNovember 2020. 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.
Exelon was not made a party to the DPA, and therefore the investigation by the USAO into Exelon’s activities endsended with no charges being brought against Exelon.
The SEC’s investigation remains ongoing and Exelon and ComEd have cooperated fully and intend to continue to cooperate fully with the SEC. Exelon and ComEd cannot predict the outcome of the SEC investigation. No loss contingency has been
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COMBINED NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)
(Dollars in millions, except per share data, unless otherwise noted)

Note 15 — Commitments and Contingencies
reflected in Exelon's and ComEd's consolidated financial statements with respect to the SEC investigation, as this contingency is neither probable nor reasonably estimable at this time. Management is currently unable to estimate a range of reasonably possible loss as this matter is subject to change.
Subsequent to Exelon announcing the receipt of the subpoenas, avarious lawsuits were filed, and various demand letters were received related to the subject of the subpoenas, the conduct described in the DPA and the SEC's investigation, including:
•A putative class action lawsuit was filed against Exelon and certain officers of Exelon and ComEd was filed in federal court in December 2019 alleging misrepresentations orand omissions purportingin Exelon’s SEC filings related to relateComEd’s lobbying activities and the related investigations. The complaint was amended on September 16, 2020, to matters that are the subjectdismiss two of the subpoenasoriginal defendants and add other defendants, including ComEd. Defendants filed a motion to dismiss in November 2020. The court denied the motion in April 2021. On May 26, 2021, defendants moved the court to certify its order denying the motion to dismiss for interlocutory appeal. Briefing on the motion was completed in June 2021 and the SEC investigation. In addition, a derivative shareholder lawsuit wasmotion remains pending. While that motion remains pending, the litigation has proceeded and in May 2021, the parties each filed against Exelon, its directorsrespective initial discovery disclosures. On June 9, 2021, defendants filed their answer and certain officers of Exelon and ComEd alleging, among other things, breaches of fiduciary duties also purportingaffirmative defenses to relate to matters thatthe complaint. The parties are the subject of the subpoenas and the SEC investigation. On July 28, 2020, plaintiff voluntarily dismissed this derivative action without prejudice to refile. Two additional putative class actions have been filed on July 27 and July 28, 2020. The firstcurrently engaged in discovery.
•Three putative class action lawsuitlawsuits against ComEd and Exelon has beenwere filed in Illinois state court and seeksin the third quarter of 2020 seeking restitution and compensatory damages on behalf of ComEd customers. The secondcases were consolidated into a single action in October of 2020. In November 2020, the Citizens Utility Board (CUB) filed a motion to intervene in the cases pursuant to an Illinois statute allowing CUB to intervene as a party or otherwise participate on behalf of utility consumers in any proceeding which affects the interest of utility consumers. On November 23, 2020, the court allowed CUB’s intervention, but denied CUB’s request to stay these cases. Plaintiffs subsequently filed a consolidated complaint, and ComEd and Exelon filed a motion to dismiss on jurisdictional and substantive grounds on January 11, 2021. Briefing on that motion was completed on March 2, 2021. The parties agreed, on March 25, 2021, along with the federal court plaintiffs, to jointly engage in mediation. The parties participated in a one-day mediation on June 7, 2021 but no settlement was reached. Oral argument on the state court motion to dismiss was held on August 4, 2021. No ruling has yet been issued.
•Four putative class action lawsuitlawsuits against ComEd has beenand Exelon were filed in federal court and allegesin the third quarter of 2020 alleging, among other things, civil violations of federal racketeering laws. On AugustIn addition, CUB filed a motion to intervene in these cases on October 22, 2020 which was granted on December 23, 2020. In addition, on December 2, 2020, the court appointed interim lead plaintiffs in the federal cases which consisted of counsel for three of the four federal cases. These plaintiffs filed a consolidated complaint on January 5, 2021. CUB also filed its own complaint against ComEd only on the same day. The remaining federal case, Potter, et al. v. Exelon et al, differed from the other lawsuits as it named additional individual defendants not named in the consolidated complaint. The Potter plaintiffs decided not to move forward with their separate lawsuit requested thatat this time and voluntarily dismissed their complaint without prejudice on April 5, 2021. ComEd waive service, which would make ComEd’s response due in October 2020. Both putativeand Exelon moved to dismiss the consolidated class action lawsuits relatecomplaint and CUB’s complaint on February 4, 2021. Briefing on that motion was completed on March 22, 2021. As noted above, on March 25, 2021, the parties agreed, along with the state court plaintiffs, to jointly engage in mediation. The parties participated in a one-day mediation on June 7, 2021 but no settlement was reached. On June 14, 2021, plaintiffs filed a motion for leave to file a sur-reply to defendants' motion to dismiss, to which ComEd and Exelon objected. The court has taken the motion for leave under advisement.
•Five shareholders sent letters to the Exelon Board of Directors between 2020 and 2021 demanding, among other things, that the Exelon Board of Directors investigate and address alleged breaches of fiduciary duties and other alleged violations by Exelon and ComEd officers and directors related to the conduct allegeddescribed in the DPA. In the first quarter of 2021, the Exelon Board of Directors appointed a Special Litigation Committee (“SLC”) consisting of disinterested and independent parties to investigate and address these shareholders’ allegations and make recommendations to the Exelon Board of Directors based on the outcome of the SLC’s investigation. In July, one of the demand letter shareholders filed a derivative action against current and former Exelon and ComEd officers and directors, and against Exelon, as nominal defendant, asserting the same claims made in its demand letter.
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COMBINED NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)
(Dollars in millions, except per share data, unless otherwise noted)

Note 15 — Commitments and Contingencies
No loss contingencies have been reflectedreflected in Exelon’s and ComEd’s consolidated financial statements with respect to these matters, as such contingencies are neither probable nor reasonably estimable at this time. Management is currently unable to estimate a range of reasonably possible loss due to the early stages
Impacts of the lawsuits.February 2021 Extreme Cold Weather Event and Texas-based Generating Assets Outages (Exelon and Generation). 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 outages as a result of extreme cold weather conditions. In addition, those weather conditions drove increased demand for service, dramatically increased wholesale power prices, and also increased gas prices in certain regions. See Note 3 — Regulatory Matters for additional information.
Various lawsuits have been filed against Generation since March 2021 related to these events, including:
•On March 5, 2021, Generation, along with more than 160 power generators and transmission and distribution companies, was sued by approximately 160 individually named plaintiffs, purportedly on behalf of all Texans who allegedly suffered loss of life or sustained personal injury, property damage or other losses as a result of the weather events. The plaintiffs allege that the defendants failed to properly prepare for the cold weather and failed to properly conduct their operations, seeking compensatory as well as punitive damages. On April 26, 2021, another multi-plaintiff lawsuit was filed on behalf of approximately 90 plaintiffs against more than 300 defendants, including Generation, involving similar allegations of liability and claims of personal injury and property damage. Since March 2021, approximately 60 additional lawsuits, naming multiple defendants including Generation, were filed by individual or multiple plaintiffs in different Texas counties, all arising out of the February weather events. These additional lawsuits allege wrongful death, property damage, or other losses. Co-defendants in these lawsuits include ERCOT, transmission and distribution utilities and other generators. Generation disputes liability and denies that it is responsible for any of plaintiffs’ alleged claims and is vigorously contesting them. No loss contingencies have been reflected in Exelon’s and Generation’s consolidated financial statements with respect to these matters, as such contingencies are neither probable nor reasonably estimable at this time.
•On March 22, 2021, a LDC filed a lawsuit in Missouri federal court against Generation for breach of contract and unjust enrichment, seeking damages of approximately $40 million. The plaintiff claims that Generation failed to deliver gas to its customers in February of 2021, causing the plaintiff to incur damages by forcing it to purchase gas for Generation’s customers and by Generation’s refusal to pay the resulting penalties. On March 26, 2021, Generation filed a complaint with the MPSC against the LDC to void the OFO penalties, or alternatively to grant a waiver or variance from the tariff requirements, to prohibit the LDC from billing or otherwise attempting to collect from Generation or any Missouri customer any portion of the penalties claimed by the LDC until the resolution of the complaint, and to prohibit the LDC from taking any retaliatory measure, including termination of service. The MPSC has scheduled an evidentiary hearing for January 2022. Based on the penalty provisions within the tariff that was in effect at the relevant time, Exelon and Generation have recorded a liability of approximately $40 million as of June 30, 2021.
General (All Registrants). The Registrants are involved in various other litigation matters that are being defended and handled in the ordinary course of business. The assessment of whether a loss is probable or reasonably possible, and whether the loss or a range of loss is estimable, often involves a series of complex judgments about future events. The Registrants maintain accruals for such losses that are probable of being incurred and subject to reasonable estimation. Management is sometimes unable to estimate an amount or range of reasonably possible loss, particularly where (1) the damages sought are indeterminate, (2) the proceedings are in the early stages, or

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

Note 14 — Commitments and Contingencies

(3) the matters involve novel or unsettled legal theories. In such cases, there is considerable uncertainty regarding the timing or ultimate resolution of such matters, including a possible eventual loss.
15. Changes in Accumulated Other Comprehensive Income (Exelon)
The following tables present changes in Exelon's AOCI, net of tax, by component:
129



Three Months Ended June 30, 2020Losses on Cash Flow Hedges 
Pension and
Non-Pension
Postretirement
Benefit Plan
Items (a)
 
Foreign
Currency
Items
 Total
Beginning balance$(3) $(3,135) $(35) $(3,173)
OCI before reclassifications—
 2
 2
 4
Amounts reclassified from AOCI—
 37
 —
 37
Net current-period OCI—
 39
 2
 41
Ending balance$(3) $(3,096) $(33) $(3,132)
Three Months Ended June 30, 2019Losses on Cash Flow Hedges 
Pension and
Non-Pension
Postretirement
Benefit Plan
Items (a)
 
Foreign
Currency
Items
 
AOCI of
Investments in Unconsolidated Affiliates (b)
 Total
Beginning balance$(2) $(2,978) $(31) $(1) $(3,012)
OCI before reclassifications—
 (1) 2
 (1) —
Amounts reclassified from AOCI—
 22
 —
 —
 22
Net current-period OCI—
 21
 2
 (1) 22
Ending balance$(2) $(2,957) $(29) $(2) $(2,990)
Six Months Ended June 30, 2020Losses on Cash Flow Hedges 
Pension and
Non-Pension
Postretirement
Benefit Plan
Items (a)
 
Foreign
Currency
Items
 Total
Beginning balance$(2) $(3,165) $(27) $(3,194)
OCI before reclassifications(1) (5) (6) (12)
Amounts reclassified from AOCI—
 74
 —
 74
Net current-period OCI(1) 69
 (6) 62
Ending balance$(3) $(3,096) $(33) $(3,132)

Six Months Ended June 30, 2019Losses on Cash Flow Hedges 
Pension and
Non-Pension
Postretirement
Benefit Plan
Items (a)
 
Foreign
Currency
Items
 
AOCI of
Investments in Unconsolidated Affiliates (b)
 Total
Beginning balance$(2) $(2,960) $(33) $—
 $(2,995)
OCI before reclassifications—
 (39) 4
 (2) (37)
Amounts reclassified from AOCI—
 42
 —
 —
 42
Net current-period OCI—
 3
 4
 (2) 5
Ending balance$(2) $(2,957) $(29) $(2) $(2,990)

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COMBINED NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)
(Dollars in millions, except per share data, unless otherwise noted)

Note 1516 — Changes in Accumulated Other Comprehensive Income

16. Changes in Accumulated Other Comprehensive Income (Exelon)
_________The following tables present changes in Exelon's AOCI, net of tax, by component:
(a)AOCI amounts are included in the computation of net periodic pension and OPEB cost. See Note 10 — Retirement Benefits for additional information. See Exelon's Statements of Operations and Comprehensive Income for individual components of AOCI.
(b)All amounts are net of noncontrolling interests.
Three Months Ended June 30, 2021Losses on Cash Flow Hedges
Pension and
Non-Pension
Postretirement
Benefit Plan
Items (a)
Foreign
Currency
Items		Total
Beginning balance$(5)$(3,319)$(22)$(3,346)
OCI before reclassifications0 0 2 2 
Amounts reclassified from AOCI0 55 0 55 
Net current-period OCI0 55 2 57 
Ending balance$(5)$(3,264)$(20)$(3,289)
Three Months Ended June 30, 2020Losses on Cash Flow Hedges
Pension and
Non-Pension
Postretirement
Benefit Plan
Items (a)
Foreign
Currency
Items		Total
Beginning balance$(3)$(3,135)$(35)$(3,173)
OCI before reclassifications0 2 2 4 
Amounts reclassified from AOCI0 37 0 37 
Net current-period OCI0 39 2 41 
Ending balance$(3)$(3,096)$(33)$(3,132)
Six Months Ended June 30, 2021Losses on Cash Flow Hedges
Pension and
Non-Pension
Postretirement
Benefit Plan
Items (a)
Foreign
Currency
Items		Total
Beginning balance$(5)$(3,372)$(23)$(3,400)
OCI before reclassifications0 (2)3 1 
Amounts reclassified from AOCI0 110 0 110 
Net current-period OCI0 108 3 111 
Ending balance$(5)$(3,264)$(20)$(3,289)
Six Months Ended June 30, 2020Losses on Cash Flow Hedges
Pension and
Non-Pension
Postretirement
Benefit Plan
Items (a)
Foreign
Currency
Items		Total
Beginning balance$(2)$(3,165)$(27)$(3,194)
OCI before reclassifications(1)(5)(6)(12)
Amounts reclassified from AOCI0 74 0 74 
Net current-period OCI(1)69 (6)62 
Ending balance$(3)$(3,096)$(33)$(3,132)
______
(a)AOCI amounts are included in the computation of net periodic pension and OPEB cost. See Note 11 — Retirement Benefits for additional information. See Exelon's Statements of Operations and Comprehensive Income for individual components of AOCI.
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COMBINED NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)
(Dollars in millions, except per share data, unless otherwise noted)

Note 16 — Changes in Accumulated Other Comprehensive Income
The following table presents income tax benefit (expense) allocated to each component of Exelon's other comprehensive income (loss):
Three Months Ended June 30,Six Months Ended June 30,
2021202020212020
Pension and non-pension postretirement benefit plans:
Prior service benefit reclassified to periodic benefit cost$1 $4 $2 $8 
Actuarial loss reclassified to periodic benefit cost(19)(17)(38)(34)
Pension and non-pension postretirement benefit plans valuation adjustment(1)0 (1)3 
 Three Months Ended June 30, Six Months Ended June 30,
 2020 2019 2020 2019
Pension and non-pension postretirement benefit plans:       
Prior service benefit reclassified to periodic benefit cost$4
 $6
 $8
 $12
Actuarial loss reclassified to periodic benefit cost(17) (13) (34) (26)
Pension and non-pension postretirement benefit plans valuation adjustment—
 —
 3
 14

16.17. Variable Interest Entities (Exelon, Generation, PHI and ACE)
At June 30, 20202021 and December 31, 2019,2020, Exelon, Generation, PHI, and ACE collectively consolidated several VIEs or VIE groups for which the applicable Registrant was the primary beneficiary (see Consolidated VIEs below) and had significant interests in several other VIEs for which the applicable Registrant does not have the power to direct the entities’ activities and, accordingly, was not the primary beneficiary (see Unconsolidated VIEs below). Consolidated and unconsolidated VIEs are aggregated to the extent that the entities have similar risk profiles.
Consolidated VIEs
The table below shows the carrying amounts and classification of the consolidated VIEs’ assets and liabilities included in the consolidated financial statements of Exelon, Generation, PHI, and ACE as of June 30, 20202021 and December 31, 2019.2020. The assets, except as noted in the footnotes to the table below, can only be used to settle obligations of the VIEs. The liabilities, except as noted in the footnote to the table below, are such that creditors, or beneficiaries, do not have recourse to the general credit of Exelon, Generation, PHI, and ACE.

131

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COMBINED NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)
(Dollars in millions, except per share data, unless otherwise noted)
Note 1617 — Variable Interest Entities



June 30, 2020 December 31, 2019June 30, 2021December 31, 2020
Exelon
Generation
PHI (a)
 ACE Exelon Generation 
PHI (a)
 ACEExelonGeneration
PHI (a)
ACEExelonGeneration
PHI (a)
ACE
Cash and cash equivalents$114
 $114
 $—
 $—
 $163
 $163
 $—
 $—
Cash and cash equivalents$233 $233 $0 $0 $98 $98 $0 $0 
Restricted cash and cash equivalents105
 102
 3
 3
 88
 85
 3
 3
Restricted cash and cash equivalents57 54 3 3 47 44 3 3 
Accounts receivable               Accounts receivable
Customer145
 145
 —
 —
 151
 151
 —
 —
Customer169 169 0 0 148 148 0 0 
Other38
 38
 —
 —
 39
 39
 —
 —
Other44 44 0 0 36 36 0 0 
Unamortized energy contract assets (b)
22
 22
 —
 —
 23
 23
 —
 —
Unamortized energy contract assetsUnamortized energy contract assets22 22 0 0 22 22 0 0 
Inventories, net               Inventories, net
Materials and supplies236
 236
 —
 —
 227
 227
 —
 —
Materials and supplies255 255 0 0 244 244 0 0 
Assets held for sale(b)
Assets held for sale(b)
0 0 0 0 101 101 0 0 
Other current assets675
 671
 4
 —
 32
 31
 1
 —
Other current assets408 404 4 0 674 669 5 0 
Total current assets1,335

1,328

7
 3
 723

719

4
 3
Total current assets1,188 1,181 7 3 1,370 1,362 8 3 
Property, plant and equipment, net (c)
5,939
 5,939
 —
 —
 6,022
 6,022
 —
 —
Property, plant, and equipment, netProperty, plant, and equipment, net5,656 5,656 0 0 5,803 5,803 0 0 
Nuclear decommissioning trust funds2,642
 2,642
 —
 —
 2,741
 2,741
 —
 —
Nuclear decommissioning trust funds3,215 3,215 0 0 3,007 3,007 0 0 
Unamortized energy contract assets (b)
258
 258
 —
 —
 250
 250
 —
 —
Unamortized energy contract assetsUnamortized energy contract assets237 237 0 0 249 249 0 0 
Other noncurrent assets44
 30
 14
 11
 89
 73
 16
 14
Other noncurrent assets35 26 9 9 52 42 10 10 
Total noncurrent assets8,883

8,869

14
 11
 9,102

9,086

16
 14
Total noncurrent assets9,143 9,134 9 9 9,111 9,101 10 10 
Total assets$10,218

$10,197

$21
 $14
 $9,825

$9,805

$20
 $17
Total assets(c)
Total assets(c)
$10,331 $10,315 $16 $12 $10,481 $10,463 $18 $13 
Long-term debt due within one year$191
 $167
 $24
 $20
 $544
 $523
 $21
 $20
Long-term debt due within one year$84 $69 $15 $11 $94 $68 $26 $21 
Accounts payable71
 71
 —
 —
 106
 106
 —
 —
Accounts payable67 67 0 0 81 81 0 0 
Accrued expenses60
 60
 —
 —
 70
 70
 —
 —
Accrued expenses56 56 0 0 70 70 0 0 
Unamortized energy contract liabilities6
 6
 —
 —
 8
 8
 —
 —
Unamortized energy contract liabilities1 1 0 0 4 4 0 0 
Liabilities held for sale(b)
Liabilities held for sale(b)
0 0 0 0 16 16 0 0 
Other current liabilities6
 6
 —
 —
 3
 3
 —
 —
Other current liabilities1 1 0 0 5 5 0 0 
Total current liabilities334
 310
 24
 20
 731
 710
 21
 20
Total current liabilities209 194 15 11 270 244 26 21 
Long-term debt947
 934
 13
 11
 527
 504
 23
 21
Long-term debt860 860 0 0 889 889 0 0 
Asset retirement obligations (d)
2,182
 2,182
 —
 —
 2,128
 2,128
 —
 —
Unamortized energy contract liabilities1
 1
 —
 —
 1
 1
 —
 —
Asset retirement obligationsAsset retirement obligations2,377 2,377 0 0 2,318 2,318 0 0 
Other noncurrent liabilities80
 80
 —
 —
 89
 89
 —
 —
Other noncurrent liabilities133 133 0 0 129 129 0 0 
Total noncurrent liabilities3,210
 3,197
 13
 11
 2,745
 2,722
 23
 21
Total noncurrent liabilities3,370 3,370 0 0 3,336 3,336 0 0 
Total liabilities$3,544
 $3,507
 $37
 $31
 $3,476
 $3,432
 $44
 $41
Total liabilities(d)
Total liabilities(d)
$3,579 $3,564 $15 $11 $3,606 $3,580 $26 $21 
_________
(a)Includes certain purchase accounting adjustments not pushed down to the ACE standalone entity.
(b)These are unrestricted assets to Exelon and Generation.
(c)Exelon’s and Generation’s balances include unrestricted assets of $1 million and $20 million as of June 30, 2020 and December 31, 2019.
(d)Exelon’s and Generation’s balances include liabilities with recourse of $2 million and $3 million as of June 30, 2020 and December 31, 2019, respectively.
(a)Includes certain purchase accounting adjustments from the PHI merger not pushed down to ACE.
(b)In the fourth quarter of 2020, Generation entered into an agreement for the sale of a significant portion of Generation's solar business, and as a result of this transaction, Exelon and Generation reclassified the consolidated VIEs' solar assets and liabilities as held for sale. Completion of the transaction occurred in the first quarter of 2021. Refer to Note 2 - Mergers, Acquisitions, and Dispositions for additional information on the solar business.
(c)Exelon’s and Generation’s balances include unrestricted assets for current unamortized energy contract assets of $22 million and $22 million, non-current unamortized energy contract assets of $216 million and $249 million, assets held for sale of $0 millionand $9 million, and other unrestricted assets of $0 million and $1 million as of June 30, 2021 and December 31, 2020, respectively
(d)Exelon’s and Generation’s balances include liabilities with recourse of $1 million and $8 million as of June 30, 2021 and December 31, 2020, respectively.

127
132



COMBINED NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)
(Dollars in millions, except per share data, unless otherwise noted)
Note 1617 — Variable Interest Entities



As of June 30, 20202021 and December 31, 2019,2020, Exelon's and Generation's consolidated VIEs consist of:
Consolidated VIE or VIE groups:Reason entity is a VIE:Reason Generation is primary beneficiary:
CENG - A joint venture between Generation and EDF. Generation has a 50.01% equity ownership in CENG. See additional discussion below.Disproportionate relationship between equity interest and operational control as a result of the NOSA described further below.Generation conducts the operational activities.
EGRP - A collection of wind and solar project entities. Generation has a 51% equity ownership in EGRP. See additional discussion below.Similar structure to a limited partnership and the limited partners do not have kick out rights with respect to the general partner.Generation conducts the operational activities.
Bluestem Wind Energy Holdings, LLC - A Tax Equity structure which is consolidated by EGRP. Generation ishas a minority interest holder.noncontrolling interest.Similar structure to a limited partnership and the limited partners do not have kick out rights with respect to the general partner.Generation conducts the operational activities.
Antelope Valley - A solar generating facility, which is 100% owned by Generation. Antelope Valley sells all of its output to PG&E through a PPA.The PPA contract absorbs variability through a performance guarantee.Generation conducts all activities.
Equity investment in distributed energy company -
Generation has a 31% equity ownership. This distributed energy company has an interest in an unconsolidated VIE (seeVIE. (See Unconsolidated VIEs disclosure below).

Generation fully impaired this investment in the third quarter of 2019. See Note 11— Asset Impairments of the Exelon 2019 Form 10-K for additional information.
Similar structure to a limited partnership and the limited partners do not have kick out rights with respect to the general partner.Generation conducts the operational activities.
NER - A bankruptcy remote, special purpose entity which is 100% owned by Generation, which purchases certain of Generation’s customer accounts receivable arising from the sale of retail electricity.

NER’s assets will be available first and foremost to satisfy the claims of the creditors of NER. See Note 56 - Accounts Receivable for additional information on the sale of receivables.

Equity capitalization is insufficient to support its operations.



Generation conducts all activities.

CENG - On April 1, 2014, Generation, CENG, and subsidiaries of CENG executed the NOSA pursuant to which Generation conducts all activities associated with the operations of the CENG fleet and provides corporate and administrative services to CENG and the CENG fleet for the remaining life of the CENG nuclear plants as if they were a part of the Generation nuclear fleet, subject to the CENG member rights of EDF.
EDF has the option to sell its 49.99% equity interest in CENG to Generation exercisable beginning on January 1, 2016 and thereafter until June 30, 2022.Generation. On November 20, 2019, Generation received notice of EDF's intention to exercise the put option to sell its interest 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 paid2020. Refer to EDF for its interest in CENG. The transaction will require approval by the NYPSC and the FERC. The process and regulatory approvals could take one to two years or more to complete.
See Note 2 - Mergers, Acquisitions, and Dispositions of the Exelon 2019 Form 10-K for additional information regarding the Put Option Agreement with EDF.information.
Exelon and Generation, where indicated, provide the following support to CENG:
•
Generation executed an Indemnity Agreement pursuant to which Generation agreed to indemnify EDF against third-party claims that may arise from any future nuclear incident (as defined in the Price-Anderson Act) in connection with the CENG nuclear plants or their operations. Exelon guarantees Generation’s obligations under this Indemnity Agreement. See Note 18 — Commitments and Contingencies of the Exelon 2019Generation executed an Indemnity Agreement pursuant to which Generation agreed to indemnify EDF against third-party claims that may arise from any future nuclear incident (as defined in the Price-Anderson Act) in connection with the CENG nuclear plants or their operations. Exelon guarantees Generation’s obligations under this Indemnity Agreement. See Note 19 — Commitments and Contingencies of the Exelon 2020 Form 10-K for more details,

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COMBINED NOTES TO CONSOLIDATED FINANCIAL STATEMENTS •— (Continued)
(Dollars in millions, except per share data, unless otherwise noted)
Note 16 — Variable Interest Entities



Generation and EDF share in the $688 million of contingent payment obligations for the payment of contingent retrospective premium adjustments for the nuclear liability insurance, and
•Exelon has executed an agreement to provide up to $245 million to support the operations of CENG as well as a $165 million guarantee of CENG’s cash pooling agreement with its subsidiaries.
EGRP - EGRP is a collection of wind and solar project entities and some of these project entities are VIEs that are consolidated by EGRP. Generation owns a number of limited liability companies that build, own, and operate solar and wind power facilities some of which are owned by EGRP. While Generation or EGRP owns 100% of the solar entities and 100% of the majority of the wind entities, it has been determined that certain of the solar and
133



COMBINED NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)
(Dollars in millions, except per share data, unless otherwise noted)
Note 17 — Variable Interest Entities


wind entities are VIEs because the entities require additional subordinated financial support in the form of a parental guarantee of debt, loans from the customers in order to obtain the necessary funds for construction of the solar facilities, or the customers absorb price variability from the entities through the fixed price power and/or REC purchase agreements. Generation is the primary beneficiary of these solar and wind entities that qualify as VIEs because Generation controls the design, construction, and operation of the facilities. Generation provides operating and capital funding to the solar and wind entities for ongoing construction, operations and maintenance and thereThere is limited recourse related to Generation related to certain solar and wind entities.
In 2017, Generation’s interests in EGRP were contributed to and are pledged for the ExGen Renewables IV non-recourse debt project financing structure. Refer to Note 12—17 — Debt and Credit Agreements of the Exelon 2020 Form 10-K for additional information on ExGen Renewables IV.
As of June 30, 20202021 and December 31, 2019,2020, Exelon's, PHI's and ACE's consolidated VIE consists of:
Consolidated VIEs:Reason entity is a VIE:Reason ACE is the primary beneficiary:
ACE Funding - A special purpose entity formed by ACE for the purpose of securitizing authorized portions of ACE’s recoverable stranded costs through the issuance and sale of Transition Bonds. Proceeds from the sale of each series of Transition Bonds by ATF were transferred to ACE in exchange for the transfer by ACE to ATF of the right to collect a non-bypassable Transition Bond Charge from ACE customers pursuant to bondable stranded costs rate orders issued by the NJBPU in an amount sufficient to fund the principal and interest payments on Transition Bonds and related taxes, expenses and fees.ACE’s equity investment is a variable interest as, by design, it absorbs any initial variability of ATF. The bondholders also have a variable interest for the investment made to purchase the Transition Bonds.ACE controls the servicing activities.
Unconsolidated VIEs
Exelon’s and Generation’s variable interests in unconsolidated VIEs generally include equity investments and energy purchase and sale contracts. For the equity investments, the carrying amount of the investments is reflected in Exelon’s and Generation’s Consolidated Balance Sheets in Investments. For the energy purchase and sale contracts (commercial agreements), the carrying amount of assets and liabilities in Exelon’s and Generation’s Consolidated Balance Sheets that relate to their involvement with the VIEs are predominately related to working capital accounts and generally represent the amounts owed by, or owed to, Exelon and Generation for the deliveries associated with the current billing cycles under the commercial agreements.
As of June 30, 20202021 and December 31, 2019,2020, Exelon and Generation had significant unconsolidated variable interests in several VIEs for which Exelon or Generation, as applicable, was not the primary beneficiary. These interests include certain equity method investments and certain commercial agreements.

The following table presents summary information about Exelon's and Generation’s significant unconsolidated VIE entities:
June 30, 2021December 31, 2020
Commercial
Agreement
VIEs		Equity
Investment
VIEs		TotalCommercial
Agreement
VIEs		Equity
Investment
VIEs		Total
Total assets(a)
$786 $378 $1,164 $777 $401 $1,178 
Total liabilities(a)
95 210 305 61 223 284 
Exelon's ownership interest in VIE(a)
0 149 149 0 157 157 
Other ownership interests in VIE(a)
691 19 710 716 21 737 
_________
(a)These items represent amounts on the unconsolidated VIE balance sheets, not in Exelon’s or Generation’s Consolidated Balance Sheets. These items are included to provide information regarding the relative size of the unconsolidated VIEs. Exelon and Generation do not have any exposure to loss as they do not have a carrying amount in the equity investment VIEs as of June 30, 2021 and December 31, 2020.
129
134



COMBINED NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)
(Dollars in millions, except per share data, unless otherwise noted)
Note 1617 — Variable Interest Entities



The following table presents summary information about Exelon's and Generation’s significant unconsolidated VIE entities:
 June 30, 2020 December 31, 2019
 
Commercial
Agreement
VIEs
 
Equity
Investment
VIEs
 Total 
Commercial
Agreement
VIEs
 
Equity
Investment
VIEs
 Total
Total assets(a)
$705
 $417
 $1,122
 $636
 $443
 $1,079
Total liabilities(a)
172
 227
 399
 33
 227
 260
Exelon's ownership interest in VIE(a)
—
 168
 168
 —
 191
 191
Other ownership interests in VIE(a)
533
 22
 555
 604
 25
 629
_________
(a)These items represent amounts on the unconsolidated VIE balance sheets, not in Exelon’s or Generation’s Consolidated Balance Sheets. These items are included to provide information regarding the relative size of the unconsolidated VIEs. Exelon and Generation do not have any exposure to loss as they do not have a carrying amount in the equity investment VIEs as of June 30, 2020 and December 31, 2019.
As of June 30, 20202021 and December 31, 2019,2020, Exelon's and Generation's unconsolidated VIEs consist of:
Unconsolidated VIE groups:Reason entity is a VIE:Reason Generation is not the primary beneficiary:
Equity investments in distributed energy companies -

1) Generation has a 90% equity ownership in a distributed energy company.
2) Generation, via a consolidated VIE, has a 90% equity ownership in another distributed energy company (See Consolidated VIEs disclosure above).

Generation fully impaired this investment in the third quarter of 2019. See Note 11— Asset Impairments of the Exelon 2019 Form 10-K for additional information.
Similar structures to a limited partnership and the limited partners do not have kick out rights with respect to the general partner.Generation does not conduct the operational activities.
Energy Purchase and Sale agreements - Generation has several energy purchase and sale agreements with generating facilities.PPA contracts that absorb variability through fixed pricing.Generation does not conduct the operational activities.


135

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Table of Contents
COMBINED NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)
(Dollars in millions, except per share data, unless otherwise noted)

Note 1718 — Supplemental Financial Information

17.18. Supplemental Financial Information (All Registrants)
Supplemental Statement of Operations Information
The following tables provide additional information about material items recorded in the Registrants' Consolidated Statements of Operations and Comprehensive Income.
Operating revenues
ExelonGenerationPHIDPL
Three Months Ended June 30, 2021
Operating lease income$13 $12 $1 $1 
Variable lease income74 74 0 0 
Three Months Ended June 30, 2020
Operating lease income$14 $12 $1 $1 
Variable lease income80 79 1 1 
Six Months Ended June 30, 2021
Operating lease income$17 $15 $2 $2 
Variable lease income137 137 0 0 
Six Months Ended June 30, 2020
Operating lease income$18 $15 $2 $2 
Variable lease income149 148 1 1 
 Operating revenues
 Exelon Generation ComEd PECO BGE PHI Pepco DPL ACE
Three Months Ended June 30, 2020                
Operating lease income$14
 $12
 $—
 $—
 $—
 $1
 $—
 $1
 $—
Variable lease income80
 79
 —
 —
 —
 1
 —
 1
 —
                  
Three Months Ended June 30, 2019                
Operating lease income$14
 $12
 $—
 $—
 $—
 $1
 $—
 $1
 $—
Variable lease income77
 74
 —
 —
 —
 3
 —
 3
 —
                  
Six Months Ended June 30, 2020                
Operating lease income$18
 $15
 $—
 $—
 $—
 $2
 $—
 $2
 $—
Variable lease income149
 148
 —
 —
 —
 1
 —
 1
 —
                  
Six Months Ended June 30, 2019                
Operating lease income$18
 $15
 $—
 $—
 $—
 $2
 $—
 $2
 $—
Variable lease income129
 126
 —
 —
 —
 3
 —
 3
 —
Taxes other than income taxes
ExelonGenerationComEdPECOBGEPHIPepcoDPLACE
Three Months Ended June 30, 2021
Utility taxes(a)
$206 $22 $61 $32 $20 $71 $65 $5 $0 
Property153 66 8 4 43 31 20 10 1 
Payroll61 30 6 4 5 7 1 1 1 
Three Months Ended June 30, 2020
Utility taxes(a)
$196 $23 $55 $31 $18 $69 $64 $5 $0 
Property149 64 8 4 40 33 21 11 1 
Payroll61 28 7 4 4 7 2 1 1 
Six Months Ended June 30, 2021
Utility taxes(a)
$423 $46 $121 $66 $45 $145 $132 $11 $1 
Property307 133 16 9 85 63 42 19 1 
Payroll122 58 13 8 9 14 3 3 2 
Six Months Ended June 30, 2020
Utility taxes(a)
$414 $49 $114 $62 $44 $145 $133 $10 $1 
Property297 133 15 8 79 62 41 20 1 
Payroll125 60 14 8 9 15 4 2 2 
__________
(a)Generation’s utility tax represents gross receipts tax related to its retail operations, and the Utility Registrants' utility taxes represents municipal and state utility taxes and gross receipts taxes related to their operating revenues. The offsetting collection of utility taxes from customers is recorded in revenues in the Registrants’ Consolidated Statements of Operations and Comprehensive Income.
136


 Taxes other than income taxes
 Exelon Generation ComEd PECO BGE PHI Pepco DPL ACE
Three Months Ended June 30, 2020                
Utility taxes(a)
$196
 $23
 $55
 $31
 $18
 $69
 $64
 $5
 $—
Property149
 64
 8
 4
 40
 33
 21
 11
 1
Payroll61
 28
 7
 4
 4
 7
 2
 1
 1
                  
Three Months Ended June 30, 2019                
Utility taxes(a)
$209
 $32
 $55
 $30
 $21
 $71
 $67
 $4
 $—
Property148
 68
 9
 4
 37
 30
 21
 8
 1
Payroll61
 30
 7
 4
 4
 7
 2
 1
 1
                  
Six Months Ended June 30, 2020                
Utility taxes(a)
$414
 $49
 $114
 $62
 $44
 $145
 $133
 $10
 $1
Property297
 133
 15
 8
 79
 62
 41
 20
 1
Payroll125
 60
 14
 8
 9
 15
 4
 2
 2
                  
Six Months Ended June 30, 2019                
Utility taxes(a)
$432
 $58
 $118
 $63
 $48
 $145
 $136
 $9
 $—
Property296
 138
 15
 8
 75
 60
 43
 16
 1
Payroll127
 64
 14
 7
 8
 14
 3
 2
 2

_________
(a)Generation’s utility tax represents gross receipts tax related to its retail operations, and the Utility Registrants' utility taxes represents municipal and state utility taxes and gross receipts taxes related to their operating revenues. The offsetting collection of utility taxes from customers is recorded in revenues in the Registrants’ Consolidated Statements of Operations and Comprehensive Income.

131
COMBINED NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)
(Dollars in millions, except per share data, unless otherwise noted)

Note 1718 — Supplemental Financial Information

Other, Net
ExelonGenerationComEdPECOBGE PHIPepcoDPLACE
Three Months Ended June 30, 2021
Decommissioning-related activities:
Net realized income on NDT funds(a)
Regulatory Agreement Units$144 $144 $0 $0 $0 $0 $0 $0 $0 
Non-Regulatory Agreement Units87 87 0 0 0 0 0 0 0 
Net unrealized gains on NDT funds
Regulatory Agreement Units361 361 0 0 0 0 0 0 0 
Non-Regulatory Agreement Units193 193 0 — 0 0 0 0 0 
Regulatory offset to NDT fund-related activities(b)
(402)(402)0 0 0 0 0 0 0 
Decommissioning-related activities383 383 0 0 0 0 0 0 0 
AFUDC — Equity35 0 9 6 7 12 10 1 1 
Non-service net periodic benefit cost26 0 0 0 0 0 0 0 0 
Net unrealized gains from equity investments(c)
119 119 0 0 0 0 0 0 0 
Three Months Ended June 30, 2020
Decommissioning-related activities:
Net realized income on NDT funds(a)
Regulatory Agreement Units$30 $30 $0 $0 $0 $0 $0 $0 $0 
Non-Regulatory Agreement Units23 23 0 0 0 0 0 0 0 
Net unrealized gains on NDT funds
Regulatory Agreement Units645 645 0 0 0 0 0 0 0 
Non-Regulatory Agreement Units452 452 0 0 0 0 0 0 0 
Regulatory offset to NDT fund-related activities(b)
(542)(542)0 0 0 0 0 0 0 
Decommissioning-related activities608 608 0 0 0 0 0 0 0 
AFUDC — Equity26 0 8 4 6 8 6 1 1 
Non-service net periodic benefit cost14 0 0 0 0 0 0 0 0 
137
 
 Other, Net
 Exelon Generation ComEd PECO BGE PHI Pepco DPL ACE
Three Months Ended June 30, 2020                
Decommissioning-related activities:                 
Net realized income on NDT funds(a)
                 
Regulatory agreement units$30
 $30
 $—
 $—
 $—
 $—
 $—
 $—
 $—
Non-regulatory agreement units23
 23
 —
 —
 —
 —
 —
 —
 —
Net unrealized gains on NDT funds                 
Regulatory agreement units645
 645
 —
 —
 —
 —
 —
 —
 —
Non-regulatory agreement units452
 452
 —
 —
 —
 —
 —
 —
 —
Regulatory offset to NDT fund-related activities(b)
(542) (542) —
 —
 —
 —
 —
 —
 —
Decommissioning-related activities608
 608
 —
 —
 —

—
 —
 —
 —
AFUDC — Equity26
 —
 8
 4
 6
 8
 6
 1
 1
Non-service net periodic benefit cost14
 —
 —
 —
 —
 —
 —
 —
 —
                  
Three Months Ended June 30, 2019                
Decommissioning-related activities:                 
Net realized income on NDT funds(a)
                 
Regulatory agreement units$77
 $77
 $—
 $—
 $—
 $—
 $—
 $—
 $—
Non-regulatory agreement units230
 230
 —
 —
 —
 —
 —
 —
 —
Net unrealized (losses) gains on NDT funds                 
Regulatory agreement units98
 98
 —
 —
 —
 —
 —
 —
 —
Non-regulatory agreement units(98) (98) —
 —
 —
 —
 —
 —
 —
Regulatory offset to NDT fund-related activities(b)
(141) (141) —
 —
 —
 —
 —
 —
 —
Decommissioning-related activities166
 166
 —
 —
 —

—

—
 —
 —
AFUDC — Equity21
 —
 4
 3
 5
 9
 6
 1
 2
Non-service net periodic benefit cost5
 —
 —
 —
 —
 —
 —
 —
 —


132
COMBINED NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)
(Dollars in millions, except per share data, unless otherwise noted)

Note 1718 — Supplemental Financial Information

Other, net
ExelonGenerationComEdPECOBGEPHIPepcoDPLACE
Six Months Ended June 30, 2021
Decommissioning-related activities:
Net realized income on NDT funds(a)
Regulatory Agreement Units$435 $435 $0 $0 $0 $0 $0 $0 $0 
Non-Regulatory Agreement Units290 290 0 0 0 0 0 0 0 
Net unrealized gains on NDT funds
Regulatory Agreement Units279 279 0 0 0 0 0 0 0 
Non-Regulatory Agreement Units126 126 0 0 0 0 0 0 0 
Regulatory offset to NDT fund-related activities(b)
(569)(569)0 0 0 0 0 0 0 
Decommissioning-related activities561 561 0 0 0 0 0 0 0 
AFUDC — Equity64 0 13 12 14 25 20 3 2 
Non-service net periodic benefit cost46 0 0 0 0 0 0 0 0 
Net unrealized gains from equity investments(c)
96 96 0 0 0 0 0 0 0 
Six Months Ended June 30, 2020
Decommissioning-related activities:
Net realized income on NDT funds(a)
Regulatory Agreement Units$77 $77 $0 $0 $0 $0 $0 $0 $0 
Non-Regulatory Agreement Units104 104 0 0 0 0 0 0 0 
Net unrealized gains on NDT funds
Regulatory Agreement Units(287)(287)0 0 0 0 0 0 0 
Non-Regulatory Agreement Units(253)(253)0 0 0 0 0 0 0 
Regulatory offset to NDT fund-related activities(b)
167 167 0 0 0 0 0 0 0 
Decommissioning-related activities(192)(192)0 0 0 0 0 0 0 
AFUDC — Equity49 0 14 7 10 17 13 2 2 
Non-service net periodic benefit cost24 0 0 0 0 0 0 0 0 
__________
(a)Realized income includes interest, dividends and realized gains and losses on sales of NDT fund investments.
(b)Includes the elimination of decommissioning-related activities for the Regulatory Agreement Units except for decommissioning-related impacts that were not offset for the Byron units in the second quarter of 2021, including the elimination of income taxes related to all NDT fund activity for those units. See Note 10 — Asset Retirement Obligations of the Exelon 2020 Form 10-K for additional information regarding the accounting for nuclear decommissioning and Note 8 — Nuclear Decommissioning for additional information on the contractual offset suspension for the Byron units.
(c)Net unrealized gains from equity investments that became publicly traded entities in the fourth quarter of 2020 and the first half of 2021.
138
 Other, net
 Exelon Generation ComEd PECO BGE PHI Pepco DPL ACE
Six Months Ended June 30, 2020                
Decommissioning-related activities:                 
Net realized income on NDT funds(a)
                 
Regulatory agreement units$77
 $77
 $—
 $—
 $—
 $—
 $—
 $—
 $—
Non-regulatory agreement units104
 104
 —
 —
 —
 —
 —
 —
 —
Net unrealized gains on NDT funds                 
Regulatory agreement units(287) (287) —
 —
 —
 —
 —
 —
 —
Non-regulatory agreement units(253) (253) —
 —
 —
 —
 —
 —
 —
Regulatory offset to NDT fund-related activities(b)
167
 167
 —
 —
 —
 —
 —
 —
 —
Decommissioning-related activities(192) (192) —
 —
 —
 —
 —
 —
 —
AFUDC — Equity49
 —
 14
 7
 10
 17
 13
 2
 2
Non-service net periodic benefit cost24
 —
 —
 —
 —
 —
 —
 —
 —
                  
Six Months Ended June 30, 2019                
Decommissioning-related activities:                 
Net realized income on NDT funds(a)
                 
Regulatory agreement units$131
 $131
 $—
 $—
 $—
 $—
 $—
 $—
 $—
Non-regulatory agreement units283
 283
 —
 —
 —
 —
 —
 —
 —
Net unrealized losses on NDT funds                 
Regulatory agreement units476
 476
 —
 —
 —
 —
 —
 —
 —
Non-regulatory agreement units182
 182
 —
 —
 —
 —
 —
 —
 —
Regulatory offset to NDT fund-related activities(b)
(487) (487) —
 —
 —
 —
 —
 —
 —
Decommissioning-related activities585
 585
 —
 —
 —
 —

—
 —
 —
AFUDC — Equity43
 —
 9
 6
 10
 18
 12
 2
 4
Non-service net periodic benefit cost10
 —
 —
 —
 —
 —
 —
 —
 —

_________
(a)Realized income includes interest, dividends and realized gains and losses on sales of NDT fund investments.
(b)Includes the elimination of decommissioning-related activities for the Regulatory Agreement Units, including the elimination of income taxes related to all NDT fund activity for those units. See Note 9 — Asset Retirement Obligations of the Exelon 2019 Form 10-K for additional information regarding the accounting for nuclear decommissioning.

133
COMBINED NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)
(Dollars in millions, except per share data, unless otherwise noted)

Note 1718 — Supplemental Financial Information

Supplemental Cash Flow Information
The following tables provide additional information about material items recorded in the Registrants' Consolidated Statements of Cash Flows.
Depreciation, amortization and accretion
ExelonGenerationComEdPECOBGEPHIPepcoDPLACE
Six Months Ended June 30, 2021
Property, plant, and equipment(a)
$3,043 $1,844 $480 $165 $215 $309 $135 $84 $76 
Amortization of regulatory assets(a)
291 0 109 8 78 95 64 20 11 
Amortization of intangible assets, net(a)
29 25 0 0 0 0 0 0 0 
Amortization of energy contract assets and liabilities(b)
13 13 0 0 0 0 0 0 0 
Nuclear fuel(c)
549 549 0 0 0 0 0 0 0 
ARO accretion(d)
255 255 0 0 0 0 0 0 0 
Total depreciation, amortization and accretion$4,180 $2,686 $589 $173 $293 $404 $199 $104 $87 
Six Months Ended June 30, 2020
Property, plant, and equipment(a)
$1,715 $577 $458 $159 $195 $289 $126 $76 $69 
Amortization of regulatory assets(a)
277 0 89 14 77 96 60 18 17 
Amortization of intangible assets, net(a)
31 27 0 0 0 0 0 0 0 
Amortization of energy contract assets and liabilities(b)
12 10 0 0 0 0 0 0 0 
Nuclear fuel(c)
459 459 0 0 0 0 0 0 0 
ARO accretion(d)
247 247 0 0 0 0 0 0 0 
Total depreciation, amortization and accretion$2,741 $1,320 $547 $173 $272 $385 $186 $94 $86 
 Depreciation, amortization and accretion
 Exelon Generation ComEd PECO BGE PHI Pepco DPL ACE
Six Months Ended June 30, 2020                
Property, plant and equipment(a)
$1,715
 $577
 $458
 $159
 $195
 $289
 $126
 $76
 $69
Amortization of regulatory assets(a)
277
 —
 89
 14
 77
 96
 60
 18
 17
Amortization of intangible assets, net(a)
31
 27
 —
 —
 —
 —
 —
 —
 —
Amortization of energy contract assets and liabilities(b)
12
 10
 —
 —
 —
 —
 —
 —
 —
Nuclear fuel(c)
459
 459
 —
 —
 —
 —
 —
 —
 —
ARO accretion(d)
247
 247
 —
 —
 —
 —
 —
 —
 —
Total depreciation, amortization and accretion$2,741

$1,320

$547

$173

$272
 $385
 $186

$94

$86
                  
Six Months Ended June 30, 2019                
Property, plant and equipment(a)
$1,859
 $789
 $439
 $149
 $173
 $266
 $117
 $71
 $57
Amortization of regulatory assets(a)
266
 —
 69
 15
 79
 103
 69
 20
 14
Amortization of intangible assets, net(a)
29
 25
 —
 —
 —
 —
 —
 —
 —
Amortization of energy contract assets and liabilities(b)
5
 5
 —
 —
 —
 —
 —
 —
 —
Nuclear fuel(c)
513
 513
 —
 —
 —
 —
 —
 —
 —
ARO accretion(d)
250
 248
 —
 —
 —
 —
 —
 —
 —
Total depreciation, amortization and accretion$2,922

$1,580

$508

$164

$252
 $369
 $186

$91

$71
__________
_________(a)Included in Depreciation and amortization in the Registrants' Consolidated Statements of Operations and Comprehensive Income.
(a)Included in Depreciation and amortization in the Registrants' Consolidated Statements of Operations and Comprehensive Income.
(b)Included in Operating revenues or Purchased power and fuel expense in the Registrants’ Consolidated Statements of Operations and Comprehensive Income.
(c)Included in Purchased power and fuel expense in the Registrants’ Consolidated Statements of Operations and Comprehensive Income.
(d)Included in Operating and maintenance expense in the Registrants’ Consolidated Statements of Operations and Comprehensive Income.

(b)Included in Operating revenues or Purchased power and fuel expense in the Registrants’ Consolidated Statements of Operations and Comprehensive Income.
(c)Included in Purchased power and fuel expense in the Registrants’ Consolidated Statements of Operations and Comprehensive Income.
(d)Included in Operating and maintenance expense in the Registrants’ Consolidated Statements of Operations and Comprehensive Income.
134
139



COMBINED NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)
(Dollars in millions, except per share data, unless otherwise noted)

Note 1718 — Supplemental Financial Information
Other non-cash operating activities
ExelonGenerationComEdPECOBGEPHIPepcoDPLACE
Six Months Ended June 30, 2021
Pension and non-pension postretirement benefit costs$196 $56 $64 $4 $29 $24 $3 $1 $5 
Allowance for credit losses100 46 24 17 4 9 5 2 2 
Other decommissioning-related activity(a)
(636)(636)0 0 0 0 0 0 0 
Energy-related options(b)
20 20 0 0 0 0 0 0 0 
True-up adjustments to decoupling mechanisms and formula rates(c)
(176)0 (64)(17)(8)(88)(46)(19)(23)
Long-term incentive plan62 0 0 0 0 0 0 0 0 
Amortization of operating ROU asset83 51 1 0 15 14 3 5 2 
AFUDC — Equity(64)0 (13)(12)(14)(25)(20)(3)(2)
Six Months Ended June 30, 2020
Pension and non-pension postretirement benefit costs$203 $58 $57 $3 $31 $35 $7 $4 $7 
Allowance for credit losses92 13 17 29 10 22 12 8 2 
Other decommissioning-related activity(a)
(60)(60)0 0 0 0 0 0 0 
Energy-related options(b)
27 27 0 0 0 0 0 0 0 
True-up adjustments to decoupling mechanisms and formula rates(c)
55 0 13 (5)0 47 (2)24 25 
Long-term incentive plan(10)0 0 0 0 0 0 0 0 
Amortization of operating ROU asset112 80 1 0 15 14 3 4 2 
Deferred Prosecution Agreement payments(d)
200 0 200 0 0 0 0 0 0 
AFUDC — Equity(49)0 (14)(7)(10)(17)(13)(2)(2)
__________
(a)Includes the elimination of decommissioning-related activities for the Regulatory Agreement Units except for decommissioning-related impacts that were not offset for the Byron units in the second quarter of 2021, including the elimination of operating revenues, ARO accretion, ARC amortization, investment income, and income taxes related to all NDT fund activity for these units. See Note 10 — Asset Retirement Obligations of the Exelon 2020 Form 10-K for additional information regarding the accounting for nuclear decommissioning and Note 8 — Nuclear Decommissioning for additional information on the contractual offset suspension for the Byron units.
(b)Includes option premiums reclassified to realized at the settlement of the underlying contracts and recorded to results of operations.
(c)For ComEd, reflects the true-up adjustments in regulatory assets and liabilities associated with its distribution, energy efficiency, distributed generation, and transmission formula rates. For BGE, Pepco, and DPL, reflects the change in regulatory assets and liabilities associated with their decoupling mechanisms and transmission formula rates. For PECO and ACE, reflects the change in regulatory assets and liabilities associated with their transmission formula rates. See Note 3 — Regulatory Matters for additional information.
(d)See Note 15 — Commitments and Contingencies for additional information related to the Deferred Prosecution Agreement.

 Other non-cash operating activities
 Exelon Generation ComEd PECO BGE PHI Pepco DPL ACE
Six Months Ended June 30, 2020                
Pension and non-pension postretirement benefit costs$203
 $58
 $57
 $3
 $31
 $35
 $7
 $4
 $7
Provision for uncollectible accounts92
 13
 17
 29
 10
 22
 12
 8
 2
Other decommissioning-related activity(a)
(60) (60) —
 —
 —
 —
 —
 —
 —
Energy-related options(b)
27
 27
 —
 —
 —
 —
 —
 —
 —
True-up adjustments to decoupling mechanisms and formula rates(c)

55
 —
 13
 (5) —
 47
 (2) 24
 25
Long-term incentive plan(10) —
 —
 —
 —
 —
 —
 —
 —
Amortization of operating ROU asset112
 80
 1
 —
 15
 14
 3
 4
 2
Deferred Prosecution Agreement payments(d)
200
 —
 200
 —
 —
 —
 —
 —
 —
                  
Six Months Ended June 30, 2019                
Pension and non-pension postretirement benefit costs$212
 $62
 $47
 $5
 $29
 $48
 $12
 $8
 $8
Provision for uncollectible accounts45
 12
 16
 10
 4
 3
 2
 1
 —
Other decommissioning-related activity(a)
(260) (261) —
 —
 —
 —
 —
 —
 —
Energy-related options(b)
43
 43
 —
 —
 —
 —
 —
 —
 —
True-up adjustments to decoupling mechanisms and formula rates(e)

14
 —
 24
 —
 —
 (10) (8) (2) —
Long-term incentive plan35
 —
 —
 —
 —
 —
 —
 —
 —
Amortization of operating ROU asset115
 78
 1
 —
 15
 17
 4
 5
 2
140
_______
(a)Includes the elimination of decommissioning-related activities for the Regulatory Agreement Units, including the elimination of operating revenues, ARO accretion, ARC amortization, investment income and income taxes related to all NDT fund activity for these units. See Note 9 — Asset Retirement Obligations of the Exelon 2019 Form 10-K for additional information regarding the accounting for nuclear decommissioning.
(b)Includes option premiums reclassified to realized at the settlement of the underlying contracts and recorded to results of operations.
(c)For ComEd, reflects the true-up adjustments in regulatory assets and liabilities associated with its distribution, energy efficiency and transmission formula rates. For BGE, Pepco and DPL, reflects the change in regulatory assets and liabilities associated with their decoupling mechanisms and transmission formula rates. For PECO and ACE, reflects the change in regulatory assets and liabilities associated with their transmission formula rates. See Note 2 — Regulatory Matters for additional information.
(d)See Note 14 — Commitments and Contingencies for additional information related to the Deferred Prosecution Agreement.
(e)For ComEd, reflects the true-up adjustments in regulatory assets and liabilities associated with its distribution and energy efficiency formula rates. For Pepco and DPL, reflects the change in regulatory assets and liabilities associated with their decoupling mechanisms. See Note 2 — Regulatory Matters for additional information.


135
COMBINED NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)
(Dollars in millions, except per share data, unless otherwise noted)

Note 1718 — Supplemental Financial Information

The following tables provide a reconciliation of cash, cash equivalents and restricted cash reported within the Registrants’ Consolidated Balance Sheets that sum to the total of the same amounts in their Consolidated Statements of Cash Flows.
ExelonGenerationComEdPECOBGEPHIPepcoDPLACE
June 30, 2021June 30, 2021
Cash and cash equivalentsCash and cash equivalents$1,578 $542 $71 $376 $368 $61 $17 $17 $11 
Restricted cash and cash equivalentsRestricted cash and cash equivalents379 59 240 8 3 42 33 5 3 
Restricted cash included in other long-term assetsRestricted cash included in other long-term assets52 0 43 0 0 9 0 0 9 
Total cash, restricted cash, and cash equivalentsTotal cash, restricted cash, and cash equivalents$2,009 $601 $354 $384 $371 $112 $50 $22 $23 
December 31, 2020December 31, 2020
Cash and cash equivalentsCash and cash equivalents$663 $226 $83 $19 $144 $111 $30 $15 $17 
Restricted cash and cash equivalentsRestricted cash and cash equivalents438 89 279 7 1 39 35 0 3 
Restricted cash included in other long-term assetsRestricted cash included in other long-term assets53 0 43 0 0 10 0 0 10 
Cash, restricted cash, and cash equivalents - Held for SaleCash, restricted cash, and cash equivalents - Held for Sale12 12 0 0 0 0 0 0 0 
Total cash, restricted cash, and cash equivalentsTotal cash, restricted cash, and cash equivalents$1,166 $327 $405 $26 $145 $160 $65 $15 $30 
Exelon Generation ComEd PECO BGE PHI Pepco DPL ACE
June 30, 2020                 June 30, 2020
Cash and cash equivalents$2,129
 $483
 $403
 $380
 $195
 $39
 $19
 $6
 $8
Cash and cash equivalents$2,129 $483 $403 $380 $195 $39 $19 $6 $8 
Restricted cash373
 153
 155
 7
 1
 36
 33
 —
 3
Restricted cash and cash equivalentsRestricted cash and cash equivalents373 153 155 7 1 36 33 0 3 
Restricted cash included in other long-term assets178
 —
 166
 —
 —
 11
 —
 —
 11
Restricted cash included in other long-term assets178 0 166 0 0 11 0 0 11 
Total cash, cash equivalents and restricted cash$2,680
 $636
 $724
 $387
 $196
 $86
 $52
 $6
 $22
Total cash, restricted cash, and cash equivalentsTotal cash, restricted cash, and cash equivalents$2,680 $636 $724 $387 $196 $86 $52 $6 $22 
                 
December 31, 2019                 December 31, 2019
Cash and cash equivalents$587
 $303
 $90
 $21
 $24
 $131
 $30
 $13
 $12
Cash and cash equivalents$587 $303 $90 $21 $24 $131 $30 $13 $12 
Restricted cash358
 146
 150
 6
 1
 36
 33
 —
 2
Restricted cash and cash equivalentsRestricted cash and cash equivalents358 146 150 6 1 36 33 0 2 
Restricted cash included in other long-term assets177
 —
 163
 —
 —
 14
 —
 —
 14
Restricted cash included in other long-term assets177 0 163 0 0 14 0 0 14 
Total cash, cash equivalents and restricted cash$1,122
 $449
 $403
 $27
 $25
 $181
 $63
 $13
 $28
                 
June 30, 2019                 
Cash and cash equivalents$735
 $575
 $65
 $20
 $8
 $54
 $18
 $3
 $4
Restricted cash252
 122
 77
 6
 1
 37
 34
 1
 2
Restricted cash included in other long-term assets191
 —
 174
 —
 —
 17
 —
 —
 17
Total cash, cash equivalents and restricted cash$1,178
 $697
 $316
 $26
 $9
 $108
 $52
 $4
 $23
                 
December 31, 2018                 
Cash and cash equivalents$1,349
 $750
 $135
 $130
 $7
 $124
 $16
 $23
 $7
Restricted cash247
 153
 29
 5
 6
 43
 37
 1
 4
Restricted cash included in other long-term assets185
 —
 166
 —
 —
 19
 —
 —
 19
Total cash, cash equivalents and restricted cash$1,781
 $903
 $330
 $135
 $13
 $186
 $53
 $24
 $30
Total cash, restricted cash, and cash equivalentsTotal cash, restricted cash, and cash equivalents$1,122 $449 $403 $27 $25 $181 $63 $13 $28 
For additional information on restricted cash see Note 1 — Significant Accounting Policies of the Exelon 20192020 Form 10-K.

141

136

COMBINED NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)
(Dollars in millions, except per share data, unless otherwise noted)

Note 1718 — Supplemental Financial Information

Supplemental Balance Sheet Information
The following tables provide additional information about material items recorded in the Registrants' Consolidated Balance Sheets.
Accrued expenses
ExelonGenerationComEdPECOBGEPHIPepcoDPLACE
June 30, 2021
Compensation-related accruals(a)
$730 $255 $136 $51 $55 $85 $28 $16 $13 
Taxes accrued473 242 77 31 35 86 58 9 9 
Interest accrued339 43 116 40 45 51 27 8 12 
December 31, 2020
Compensation-related accruals(a)
$1,069 $426 $170 $73 $84 $109 $36 $18 $17 
Taxes accrued527 229 94 16 73 117 90 18 12 
Interest accrued331 44 109 37 46 51 26 7 12 
 Accrued expenses
 Exelon Generation ComEd PECO BGE PHI Pepco DPL ACE
June 30, 2020                 
Compensation-related accruals(a)
$744
 $277
 $135
 $50
 $52
 $92
 $32
 $18
 $14
Taxes accrued396
 229
 61
 2
 19
 73
 54
 5
 8
Interest accrued357
 53
 119
 37
 46
 51
 25
 8
 13
                  
December 31, 2019                 
Compensation-related accruals(a)
$1,052
 $422
 $171
 $58
 $78
 $101
 $28
 $19
 $15
Taxes accrued414
 222
 83
 3
 26
 117
 90
 14
 8
Interest accrued337
 65
 110
 37
 46
 49
 23
 8
 12
__________
_________(a)Primarily includes accrued payroll, bonuses and other incentives, vacation and benefits.
(a)Primarily includes accrued payroll, bonuses and other incentives, vacation and benefits.

18.
19. Related Party Transactions (All Registrants)
Operating revenues from affiliates
Generation
The following table presents Generation’s Operating revenues from affiliates, which are primarily recorded as Purchased power from affiliates and an immaterial amount recorded as Operating and maintenance expense from affiliates at the Utility Registrants:
 Three Months Ended June 30,Six Months Ended June 30,
 2021202020212020
Operating revenues from affiliates:
ComEd(a)(b)
$75 $80 $153 $170 
PECO(c)
41 41 83 78 
BGE(d)
58 70 130 169 
PHI77 78 176 182 
Pepco(e)
55 60 130 139 
DPL(f)
17 16 37 38 
ACE(g)
5 2 9 5 
Other3 2 7 2 
Total operating revenues from affiliates (Generation)$254 $271 $549 $601 
 Three Months Ended June 30, Six Months Ended June 30,
 2020 2019 2020
2019
Operating revenues from affiliates:       
ComEd(a)(b)
$80
 $89
 $170
 $183
PECO(c)
41
 35
 78
 80
BGE(d)
70
 57
 169
 133
PHI78
 69
 182
 170
Pepco(e)
60
 52
 139
 122
DPL(f)
16
 12
 38
 35
ACE(g)
2
 5
 5
 13
Other2
 2
 2
 3
Total operating revenues from affiliates (Generation)$271
 $252
 $601
 $569
__________
__________(a)Generation has an ICC-approved RFP contract with ComEd to provide a portion of ComEd’s electricity supply requirements. Generation also sells RECs and ZECs to ComEd.
(a)Generation has an ICC-approved RFP contract with ComEd to provide a portion of ComEd’s electricity supply requirements. Generation also sells RECs and ZECs to ComEd.
(b)For the three and six months ended June 30, 2020 , respectively, ComEd’s Purchased power from Generation of $84 million and $181 million is recorded as Operating revenues from ComEd of $80 million and $170 million and as Purchased power and fuel from ComEd of $4 million and $11 million at Generation. For the three and six months ended June 30, 2019 , respectively, ComEd’s Purchased power from Generation of $90 million and $187 million is recorded as Operating revenues from ComEd of $89 million and $183 million and as Purchased power and fuel from ComEd of $1 million and $4 million at Generation.
(c)Generation provides electric supply to PECO under contracts executed through PECO’s competitive procurement process. In addition, Generation has a ten-year agreement with PECO to sell solar AECs.

(b)For the three and six months ended June 30, 2021, respectively, ComEd’s Purchased power from Generation of $78 million and $163 million is recorded as Operating revenues from ComEd of $75 million and $153 million and as Purchased power and fuel from ComEd of $3 million and $10 million at Generation. For the three and six months ended June 30, 2020, respectively, ComEd’s Purchased power from Generation of $84 million and$181 million is recorded as Operating revenues from ComEd of $80 million and $170 million and as Purchased power and fuel from ComEd of $4 million and $11 million at Generation.
(c)Generation provides electric supply to PECO under contracts executed through PECO’s competitive procurement process. In addition, Generation has a ten-year agreement with PECO to sell solar AECs.
(d)Generation provides a portion of BGE’s energy requirements under its MDPSC-approved market-based SOS and gas commodity programs.
137
142



COMBINED NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)
(Dollars in millions, except per share data, unless otherwise noted)

Note 1819 — Related Party Transactions


(e)Generation provides electric supply to Pepco under contracts executed through Pepco's competitive procurement process approved by the MDPSC and DCPSC.
(d)Generation provides a portion of BGE’s energy requirements under its MDPSC-approved market-based SOS and gas commodity programs.
(e)Generation provides electric supply to Pepco under contracts executed through Pepco's competitive procurement process approved by the MDPSC and DCPSC.
(f)Generation provides a portion of DPL's energy requirements under its MDPSC and DPSC approved market based SOS and gas commodity programs.
(g)Generation provides electric supply to ACE under contracts executed through ACE's competitive procurement process.
(f)Generation provides a portion of DPL's energy requirements under its MDPSC and DPSC-approved market-based SOS commodity programs.
(g)Generation provides electric supply to ACE under contracts executed through ACE's competitive procurement process.
PHI
PHI’s Operating revenues from affiliates are primarily with BSC for services that PHISCO provides to BSC.
Operating and maintenance expense from affiliatesService Company Costs for Corporate Support
The Registrants receive a variety of corporate support services from BSC. Pepco, DPL, and ACE also receive corporate support services from PHISCO. See Note 1 - Significant Accounting Policies for additional information regarding BSC and PHISCO.
The following table presents the service company costs allocated to the Registrants:
Operating and maintenance from affiliatesCapitalized costs
Three Months Ended June 30,Six Months Ended June 30,Three Months Ended June 30,Six Months Ended June 30,
20212020202120202021202020212020
Exelon
   BSC$124 $129 $282 $242 
   PHISCO17 16 36 30 
Generation
   BSC$135 $133 $280 $273 10 14 33 25 
ComEd
   BSC72 67 143 138 45 41 102 83 
PECO
   BSC40 36 80 73 17 18 44 33 
BGE
   BSC45 40 88 82 20 30 43 58 
PHI
   BSC37 35 76 72 32 26 60 43 
   PHISCO0 0 0 0 17 16 36 30 
Pepco
   BSC23 20 45 41 13 9 25 15 
   PHISCO28 32 57 62 7 7 15 13 
DPL
   BSC15 13 29 26 10 9 19 14 
   PHISCO24 25 49 49 5 5 11 9 
ACE
   BSC12 11 24 21 8 8 15 12 
   PHISCO21 23 43 44 5 4 10 8 
  Operating and maintenance from affiliates Capitalized costs
  Three Months Ended June 30, Six Months Ended June 30, Three Months Ended June 30, Six Months Ended June 30,
  2020 2019 2020 2019 2020 2019 2020 2019
Exelon                
BSC         $129
 $132
 $242
 $232
PHISCO         16
 19
 30
 40
Generation                
   BSC $133
 $148
 $273
 $297
 14
 14
 25
 26
ComEd                
   BSC 67
 60
 138
 122
 41
 36
 83
 61
PECO                
   BSC 36
 37
 73
 74
 18
 24
 33
 46
BGE                
   BSC 40
 39
 82
 77
 30
 38
 58
 59
PHI                
   BSC 35
 34
 72
 66
 26
 20
 43
 40
   PHISCO —
 —
 —
 —
 16
 19
 30
 40
Pepco                
   BSC 20
 22
 41
 43
 9
 9
 15
 17
   PHISCO 32
 31
 62
 63
 7
 9
 13
 17
DPL                
   BSC 13
 13
 26
 26
 9
 6
 14
 11
   PHISCO 25
 25
 49
 50
 5
 5
 9
 12
ACE                
   BSC 11
 11
 21
 21
 8
 4
 12
 8
   PHISCO 23
 22
 44
 45
 4
 5
 8
 11
143


138
COMBINED NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)
(Dollars in millions, except per share data, unless otherwise noted)

Note 1819 — Related Party Transactions


Current Receivables from/Payables to affiliates
The following tables present current receivables from affiliates and current payables to affiliates:
June 30, 2021
Receivables from affiliates:
Payables to affiliates:GenerationComEdPECOBGEPepcoDPLACEBSCPHISCOOtherTotal
Generation$20 $0 $0 $0 $0 $0 $84 $0 $15 $119 
ComEd$52 (a)0 0 0 0 0 50 0 7 109 
PECO22 0 0 0 0 0 24 0 4 50 
BGE8 0 0 0 0 0 31 0 2 41 
PHI0 0 0 0 0 0 0 4 0 10 14 
Pepco12 0 0 0 0 0 14 14 2 42 
DPL3 0 0 0 0 0 9 10 1 23 
ACE12 0 0 0 0 0 8 10 0 30 
Other8 2 0 0 0 0 1 0 0 11 
Total$117 $22 $0 $0 $0 $0 $1 $224 $34 $41 $439 
December 31, 2020
Receivables from affiliates:
Payables to affiliates:GenerationComEdPECOBGEPepcoDPLACEBSCPHISCOOtherTotal
Generation$13 $0 $0 $0 $0 $0 $72 $0 $22 $107 
ComEd$78 (a)0 0 0 0 0 59 0 9 146 
PECO17 1 0 0 0 0 28 0 4 50 
BGE11 0 0 0 0 0 47 0 3 61 
PHI0 0 0 0 0 0 0 4 0 11 15 
Pepco13 2 0 1 0 0 25 14 0 55 
DPL3 1 0 0 0 0 21 10 1 36 
ACE6 0 0 0 0 0 15 9 1 31 
Other25 5 2 2 2 1 6 0 0 43 
Total$153 $22 $2 $3 $2 $1 $6 $271 $33 $51 $544 
  Receivables from affiliates:  
Payables to affiliates: Generation ComEd PECO BGE Pepco DPL ACE BSC PHISCO Other Total
Generation   $16
 $—
 $—
 $—
 $—
 $—
 $75
 $—
 $22
 $113
ComEd $49
(a)  —
 —
 —
 —
 —
 42
 —
 8
 99
PECO 20
 6
   —
 —
 1
 —
 25
 —
 5
 57
BGE 11
 —
 —
   —
 —
 —
 28
 —
 2
 41
PHI —
 —
 —
 —
 —
 —
 —
 4
 —
 10
 14
Pepco 15
 —
 —
 —
 

 —
 —
 12
 18
 1
 46
DPL 3
 —
 —
 —
 2
 

 —
 10
 11
 1
 27
ACE 11
 —
 —
 —
 —
 —
   8
 11
 1
 31
Other 9
 1
 —
 —
 —
 —
 1
 —
 —
   11
Total $118
 $23
 $—
 $—
 $2
 $1
 $1
 $204
 $40
 $50
 $439
__________
(a)As of June 30, 2021 and December 31, 20192020, Generation had a contract liability with ComEd for $7 million and $50 million, respectively, that was included in Other current liabilities on Generation’s Consolidated Balance Sheets. At June 30, 2021 and December 31, 2020, ComEd had a Current Payable to Generation of $45 million and $28 million, respectively, on its Consolidated Balance Sheets, which consisted of Generation’s Current Receivable from ComEd, partially offset by Generation’s contract liability with ComEd.
  Receivables from affiliates:  
Payables to affiliates: Generation ComEd PECO BGE Pepco DPL ACE BSC PHISCO Other Total
Generation   $27
 $—
 $—
 $—
 $—
 $—
 $67
 $—
 $23
 $117
ComEd $78
(a)  —
 —
 —
 —
 —
 54
 —
 8
 140
PECO 27
 —
 

 —
 —
 —
 —
 25
 —
 3
 55
BGE 28
 —
 —
   —
 —
 —
 34
 —
 4
 66
PHI —
 —
 —
 —
 —
 —
 —
 4
 —
 10
 14
Pepco 34
 —
 —
 —
   —
 —
 16
 15
 1
 66
DPL 7
 —
 —
 —
 —
 

 3
 10
 11
 1
 32
ACE 7
 —
 —
 —
 —
 —
   7
 10
 1
 25
Other 9
 1
 1
 1
 —
 —
 1
 —
 —
   13
Total $190
 $28
 $1
 $1
 $—
 $—
 $4
 $217
 $36
 $51
 $528
__________
(a)As of June 30, 2020 and December 31, 2019, Generation had a contract liability with ComEd for $7 million and $37 million, respectively, that was included in Other current liabilities on Generation’s Consolidated Balance Sheets. At June 30, 2020 and December 31, 2019, ComEd had a Current Payable to Generation of $42 million and $41 million, respectively, on its Consolidated Balance Sheets, which consisted of Generation’s Current Receivable from ComEd, partially offset by Generation’s contract liability with ComEd.
Borrowings from Exelon/PHI intercompany money pool
To provide an additional short-term borrowing option that will generally be more favorable to the borrowing participants than the cost of external financing both Exelon and PHI operate an intercompany money pool. Generation, ComEd, PECO, and PHI Corporate participate in the Exelon money pool. Pepco, DPL, and ACE participate in the PHI intercompany money pool.
Noncurrent Receivables from/Payables to affiliates

139
Table of Contents
COMBINED NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)
(Dollars in millions, except per share data, unless otherwise noted)

Note 18 — Related Party Transactions


Generation has long-term payables to ComEd and PECO as a result of the nuclear decommissioning contractual construct whereby, to the extent NDT funds are greater than the underlying ARO at the end of decommissioning, such amounts are due back to ComEd and PECO, as applicable, for payment to their respective customers. See Note 910 — Asset Retirement Obligations of the Exelon 20192020 Form 10-K for additional information.
144



COMBINED NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)
(Dollars in millions, except per share data, unless otherwise noted)

Note 19 — Related Party Transactions

The following table presents noncurrent receivables from affiliates at ComEd and PECO which are recorded as noncurrent payables to affiliates at Generation:
 June 30, 2020 December 31, 2019
ComEd$2,374
 $2,622
PECO376
 480
Other1
 1
Total:$2,751
 $3,103

June 30, 2021December 31, 2020
ComEd$2,439 $2,541 
PECO571 475 
Long-term debt to financing trusts
The following table presents Long-term debt to financing trusts:
 June 30, 2020 December 31, 2019
 Exelon ComEd PECO Exelon ComEd PECO
ComEd Financing III$206
 $205
 $—
 $206
 $205
 $—
PECO Trust III81
 —
 81
 81
 —
 81
PECO Trust IV103
 —
 103
 103
 —
 103
Total$390
 $205
 $184
 $390
 $205
 $184

June 30, 2021December 31, 2020
ExelonComEdPECOExelonComEdPECO
ComEd Financing III$206 $205 $0 $206 $205 $0 
PECO Trust III81 0 81 81 0 81 
PECO Trust IV103 0 103 103 0 103 
Total$390 $205 $184 $390 $205 $184 
Long-term debt to affiliates
In connection with the debt obligations assumed by Exelon as part of the Constellation merger, Exelon and subsidiaries of Generation (former Constellation subsidiaries) assumed intercompany loan agreements that mirror the terms and amounts of the third-party debt obligations of Exelon, resulting in intercompany notes payable included in Long-term debt to affiliates in Generation’s Consolidated Balance Sheets and intercompany notes receivable at Exelon Corporate.

19. Subsequent Events (Exelon, PHI, Pepco, DPL,
20. Planned Separation

On February 21, 2021, Exelon’s Board of Directors approved a plan to separate the Utility Registrants and ACE)
SaleGeneration, creating two publicly traded companies. Under the separation plan, Exelon shareholders will retain their current shares of Transmission Tower Attachment Agreements
On July 1, 2020, Pepco, DPLExelon stock and ACE each entered into an agreement to sellreceive a 60% undivided interest in their respective portfoliospro-rata distribution of transmission tower attachment agreements with telecommunications companies to an unrelated owner and manager of communication infrastructure (the Buyer). As partshares of the new company’s stock in a transaction that is expected to be tax-free to Exelon and its shareholders for U.S. federal income tax purposes. The actual number of shares to be distributed to Exelon shareholders will be determined prior to closing.

Exelon is targeting to complete the Buyer will manageseparation in the day-to-day operationsfirst 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 transaction is subject to approval by the FERC, NRC, and NYPSC and receipt of a private letter ruling from the IRS and tax opinion from Exelon’s tax advisors.

On February 25, 2021, Exelon and Generation filed applications with the FERC, NYPSC, and NRC seeking approvals for the separation of Generation. On March 25, 2021, Exelon filed a request for a private letter ruling with the IRS to confirm the tax-free treatment of the jointly-owned agreements with telecommunications companies forplanned separation. Exelon and Generation expect a period of 35 years. In addition, for an initial period of three years for two, two-year extensions that are subject to certain conditions,decision from the Buyer has the exclusive right to enter into new agreements with telecommunications companies and to receive a 30% undivided interest in those new agreements. As a result of the transaction, Pepco, DPL, and ACE received cash and recorded liabilities of $98 million, $13 million, and $13 million, respectively,IRS in the third quarter of 2020.2021, the FERC in the second half of 2021, the NRC in the fourth quarter of 2021, and have requested a decision from the NYPSC before the end of 2021. Exelon and Generation cannot predict if the applications will be approved as filed.

There can be no assurance that any separation transaction will ultimately occur or, if one does occur, of its terms or timing.


Item 2.Management’s Discussion and Analysis of Financial Condition and Results of Operations
145



ITEM 2.    MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS
(Dollars in millions except per share data, unless otherwise noted)
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 45 — 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 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.
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. We have implemented work from home policies where appropriate, and imposed travel limitations on our 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 have been no changes in internal control over financial reporting to date in 2020 as of 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 4. Controls and Procedures for additional information.
The estimated impact to Generation’s and the Utility Registrants’ Net income as a result of COVID-19 is approximately $100 million and $50 million, respectively, for the three and six months ended June 30, 2020 and primarily reflects the impact of reduction in load, incremental credit loss expense and direct costs related to COVID-19 as further discussed below.
Unfavorable economic conditions due to COVID-19 have impacted the demand for electricity and natural gas in the second quarter of 2020 and are expected to continue to impact demand in the second half of 2020. Commercial and Industrial customer demand has experienced a notable decrease, while residential demand has slightly increased. Generation and the Utility Registrants estimate a net decrease in Net income due to reduction in load of $50 to $100 million and $10 to $25 million, respectively, in the second half of 2020. Generation and the Utility Registrants load forecasts are highly dependent on many factors including, but not limited to, the duration of remaining restrictions and the speed and strength of the economic recovery. A 1% change in load would result in the following change in Net income in the second half of 2020:

 Generation’s Net IncomeUtility Registrants’ Net Income
Commercial & Industrial Customers$8
$4
Residential Customers4
4
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. These measures were in place through July 1, 2020 for DPL Delaware and July 15, 2020 for ACE and are currently expected to continue through August 31, 2020 for ComEd, September 1, 2020 for BGE, Pepco Maryland and DPL Maryland, October 9, 2020 for Pepco District of Columbia and until further notice for PECO. As a result of such measures, the Registrants expect an increase in Customer allowance for credit losses for the year ending December 31, 2020. Generation estimates a decrease in Net income due to an increase in credit loss expense of $15 to $50 million in the second half of 2020. The Utility Registrants do not expect a material decrease in Net income for the year ending December 31, 2020. Typically, they recover credit loss expense through rate required programs or distribution base rate cases. For those jurisdictions without an existing rate required program to recover credit loss expense, the Utility Registrants are pursuing strategies with their respective commissions to recover incremental costs being incurred as a result of COVID-19. During April, May, and July of 2020, the MDPSC, the DCPSC, the DPSC, and the NJBPU issued orders authorizing the creation of regulatory assets to track incremental COVID-19 related costs. Also, in May of 2020, the PAPUC issued a Secretarial Letter authorizing the creation of regulatory assets to track incremental credit loss expense related to COVID-19. Such orders and the Secretarial Letter will allow for assessment of recovery of those costs in future distribution base rate cases. ComEd and ACE have existing mechanisms for recovery of credit loss expense. The other Utility Registrants are assessing the regulatory facts and circumstances and expect to record regulatory assets in the second half of 2020 for the incremental credit loss expense related to COVID-19, including the expense recorded in the second quarter of 2020. However, the timing and amount of the recovery offset of the increase in credit loss expense could extend beyond 2020, which could have a negative impact on Net income for the year ending December 31, 2020.

The 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. Such costs are excluded from Adjusted (non-GAAP) Operating Earnings.

To offset part of the unfavorable impacts from reduction in load, increase in credit loss expense and direct costs related to COVID-19, the Registrants identified and are pursuing approximately $250 million in cost savings across Generation and the Utility Registrants.

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, to date in 2020, the Registrants have issued long-term debt of $5.1 billion, of which $4.0 billion was issued in the period of April to July of 2020. The Registrants accelerated the timing of a number of planned debt issuances resulting in the $4.0 billion issued in the period of April to July of 2020 and the Registrants have now completed their planned long-term debt issuances for the 2020 year. See Liquidity and Capital Resources, Note 12 - Debt and Credit Agreements, and Note 5 - 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 to date in 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 our workforce, our customers and our suppliers and we will take additional precautions that we determine are 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.
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 three and six months ended June 30, 20202021 compared to the same period in 2019.2020. For additional information regarding the financial results for the three and six months ended June 30, 20202021 and 20192020 see the discussions of Results of Operations by Registrant.
Three Months Ended June 30, Favorable (unfavorable) variance Six Months Ended June 30, Favorable (unfavorable) varianceThree Months Ended June 30,Favorable (unfavorable) varianceSix Months Ended June 30,Favorable (unfavorable) variance
2020 2019 2020 2019 2021202020212020
Exelon521
 484
 $37
 $1,103
 $1,391
 $(288)Exelon$401 $521 $(120)$112 $1,103 $(991)
Generation476
 108
 368
 521
 472
 49
Generation(61)476 (537)(854)521 (1,375)
ComEd(61) 186
 (247) 107
 344
 (237)ComEd192 (61)253 390 107 283 
PECO39
 102
 (63) 178
 270
 (92)PECO104 39 65 271 178 93 
BGE39
 45
 (6) 219
 206
 13
BGE45 39 6 254 219 35 
PHI94
 106
 (12) 202
 223
 (21)PHI141 94 47 269 202 67 
Pepco57
 64
 (7) 109
 119
 (10)Pepco75 57 18 134 109 25 
DPL19
 30
 (11) 64
 83
 (19)DPL30 19 11 86 64 22 
ACE18
 14
 4
 31
 24
 7
ACE37 18 19 51 31 20 
Other(a)
(66) (63) (3) (124) (124) —
Other(a)
(20)(66)46 (218)(124)(94)
__________
(a)Primarily includes eliminating and consolidating adjustments, Exelon’s corporate operations, shared service entities and other financing and investing activities.
(a)Primarily includes eliminating and consolidating adjustments, Exelon’s corporate operations, shared service entities and other financing and investing activities.
Three Months Ended June 30, 20202021 Compared to Three Months Ended June 30, 2019. Net income attributable to common shareholders increased by $37 million and diluted earnings per average common share increased to $0.53 in 2020 from $0.50 in 2019 primarily due to:
Higher net unrealized and realized gains on NDT funds;
Higher mark-to-market gains;
•
Lower operating and maintenance expense primarily due to lower contracting costs at Generation;and
Favorable weather conditions at PECO and DPL Delaware.
The increases were partially offset by:
Payments that ComEd will make under the Deferred Prosecution Agreement.  See Note 14 - 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;
Higher storm costs related to the June 2020 storms at PECO;
•
Higher credit loss expense that includes the impacts of COVID-19 at Generation,PECO, Pepco and DPL;
COVID-19 direct costs; and
Lower electric distribution earnings at ComEd primarily due to distribution formula rate timing.

Six Months Ended June 30, 2020 Compared to Six Months Ended June 30, 2019.2020. Net income attributable to common shareholders decreaseddecreased by $288$120 million and diluted earnings per average common share decreased to $1.13$0.41 in 20202021 from $1.43$0.53 in 20192020 primarily due to:
Payments that ComEd will make under
146



•Accelerated depreciation and amortization associated with Generation's decisions in the Deferred Prosecution Agreement.  See Note 14 - Commitmentsthird quarter of 2020 to early retire Byron and ContingenciesDresden nuclear facilities in 2021 and Mystic Units 8 and 9 in 2024;
•Impairments of the Combined Notes to Consolidated Financial Statements for additional information;New England asset group and the Albany Green Energy biomass facility at Generation; and
Higher•Lower net unrealized and realized lossesgains on NDT funds;
Lower capacity revenue;
Reduction in load due to COVID-19 at Generation;
Higher nuclear outage days;
Higher storm costs related to the June 2020 storms at PECO;
Higher credit loss expense that includes the impacts of COVID-19 at Generation, PECO, Pepco, and DPL;
COVID-19 direct costs;
Unfavorable weather conditions at PECO and ACE; and
Lower allowed electric distribution ROE due to a decrease in treasury rates.funds.
The decreases were partially offset by:
•Higher mark-to-market gains;
•Higher net unrealized and realized gains on equity investments;
•Lower nuclear outage days;
•Higher New York ZEC revenues due to higher generation and an increase in ZEC prices;
•Lower operating and maintenance expense at ComEd due to the payments that ComEd made in 2020 under the Deferred Prosecution Agreement;
•Higher electric distribution earnings from higher rate base and higher allowed ROE due to an increase in treasury rates at ComEd;
•The favorable impacts of the multi-year plan at BGE and regulatory rate increases at DPL and ACE;
•Favorable volume at PECO and ACE; and
•Lower storm costs at PECO due to the absence of the June 2020 storms.
Six Months Ended June 30, 2021 Compared to Six Months Ended June 30, 2020. Net income attributable to common shareholders decreased by $991 million and diluted earnings per average common share decreased to $0.11 in 2021 from $1.13 in 2020 primarily due to:
•Impacts of the February 2021 extreme cold weather event;
•Accelerated depreciation and amortization associated with Generation's decisions in the third quarter of 2020 to previous cost management programsearly retire Byron and lower contracting costs at Generation;Dresden nuclear facilities in 2021 and Mystic Units 8 and 9 in 2024;
The approval•Impairments of the New Jersey ZEC program inEngland asset group and the second quarter of 2019;
An income tax settlementAlbany Green Energy biomass facility at Generation; and
Regulatory•The absence of a prior year one-time tax settlement.
The decreases were partially offset by:
•Higher mark-to-market gains;
•Higher net unrealized and realized gains on NDT funds;
147



•Higher net unrealized and realized gains on equity investments;
•Lower nuclear outage days;
•Higher New York ZEC revenues due to higher generation and an increase in ZEC prices;
•Lower operating and maintenance expense at ComEd due to the payments that ComEd made in 2020 under the Deferred Prosecution Agreement;
•Higher electric distribution earnings from higher rate base and higher allowed ROE due to an increase in treasury rates at ComEd;
•The favorable impacts of the multi-year plan at BGE and regulatory rate increases at BGEDPL and ACE.ACE;
•Favorable weather conditions at PECO, DPL's Delaware service territory, and ACE;
•Favorable volume at PECO and ACE; and
•Lower storm costs at PECO due to the absence of the June 2020 storms.
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.

The following tables provide a reconciliation between net income attributable to common shareholders as determined in accordance with GAAP and adjusted (non-GAAP) operating earnings for the three and six months ended June 30, 20202021 compared to the same period in 2019.2020.
148



 Three Months Ended June 30,
 2020 2019
(All amounts in millions after tax)  
Earnings per
Diluted Share
   
Earnings per
Diluted Share
Net Income Attributable to Common Shareholders$521
 $0.53
 $484
 $0.50
Mark-to-Market Impact of Economic Hedging Activities (net of taxes of $18 and $22, respectively)(51) (0.05) 68
 0.07
Unrealized (Gains) Losses Related to NDT Fund Investments (net of taxes of $275 and $28, respectively)(a)
(305) (0.31) 52
 0.05
Asset Impairments (net of taxes of $7 and $1, respectively)(b)
19
 0.02
 1
 —
Plant Retirements and Divestitures (net of taxes of $2 and $37, respectively)(c)
7
 0.01
 (24) (0.02)
Cost Management Program (net of taxes of $3 and $1, respectively)(d)
6
 0.01
 6
 0.01
Litigation Settlement Gain (net of taxes of $7)—
 —
 (19) (0.02)
Change in Environmental Liabilities (net of taxes of $0)1
 —
 —
 —
COVID-19 Direct Costs (net of taxes of $10)(e)
27
 0.03
 —
 —
Deferred Prosecution Agreement Payments (net of taxes of $0)(f)
200
 0.20
 —
 —
Income Tax-Related Adjustments (entire amount represents tax expense)5
 0.01
 —
 —
Noncontrolling Interests (net of taxes of $20 and $3, respectively)(g)
104
 0.11
 15
 0.02
Adjusted (non-GAAP) Operating Earnings$536
 $0.55
 $583
 $0.60
Three Months Ended June 30,
20212020
(In millions, except per share data)Earnings per
Diluted Share		Earnings per
Diluted Share
Net Income Attributable to Common Shareholders$401 $0.41 $521 $0.53 
Mark-to-Market Impact of Economic Hedging Activities (net of taxes of $79 and $18, respectively)(231)(0.24)(51)(0.05)
Unrealized Gains Related to NDT Fund Investments (net of taxes of $134 and $275, respectively)(a)
(130)(0.13)(305)(0.31)
Asset Impairments (net of taxes of $124 and $7, respectively)(b)
368 0.38 19 0.02 
Plant Retirements and Divestitures (net of taxes of $116 and $2, respectively)(c)
344 0.35 7 0.01 
Cost Management Program (net of taxes of $1 and $3, respectively)(d)
2 — 6 0.01 
Change in Environmental Liabilities (net of taxes of $0)— — 1 — 
COVID-19 Direct Costs (net of taxes of $3 and $10, respectively)(e)
9 0.01 27 0.03 
Deferred Prosecution Agreement Payments (net of taxes of $0)(f)
— — 200 0.20 
Acquisition Related Costs (net of taxes of $1)(g)
2 — — — 
ERP System Implementation Costs (net of taxes $1)(h)
2 — — — 
Planned Separation Costs (net of taxes of $7)(i)
13 0.01 — — 
Costs Related to Suspension of Contractual Offset (net of taxes of $12)(j)
41 0.04 — — 
Income Tax-Related Adjustments (entire amount represents tax expense)(2)— 5 0.01 
Noncontrolling Interests (net of taxes of $8 and $20, respectively)(k)
50 0.05 104 0.11 
Adjusted (non-GAAP) Operating Earnings$869 $0.89 $536 $0.55 


149



 Six Months Ended June 30,
 2020 2019
(All amounts in millions after tax)  
Earnings per
Diluted Share
   
Earnings per
Diluted Share
Net Income Attributable to Common Shareholders$1,103
 $1.13
 $1,391
 $1.43
Mark-to-Market Impact of Economic Hedging Activities (net of taxes of $50 and $34, respectively)(146) (0.15) 98
 0.10
Unrealized (Gains) Losses Related to NDT Fund Investments (net of taxes of $130 and $133, respectively)(a)
180
 0.18
 (142) (0.15)
Asset Impairments (net of taxes of $7 and $2, respectively)(b)
21
 0.02
 6
 0.01
Plant Retirements and Divestitures (net of taxes of $6 and $32, respectively)(c)
20
 0.02
 (4) —
Cost Management Program (net of taxes of $6 and $7, respectively)(d)
17
 0.02
 16
 0.02
Litigation Settlement Gain (net of taxes of $7)—
 —
 (19) (0.02)
Change in Environmental Liabilities (net of taxes of $0)1
 —
 —
 —
COVID-19 Direct Costs (net of taxes of $10)(e)
27
 0.03
 —
 —
Deferred Prosecution Agreement Payments (net of taxes of $0)(f)
200
 0.20
 —
 —
Income Tax-Related Adjustments (entire amount represents tax expense)4
 —
 —
 —
Noncontrolling Interests (net of taxes of $10 and $15, respectively)(g)
(40) (0.04) 82
 0.08
Adjusted (non-GAAP) Operating Earnings$1,387
 $1.42
 $1,429
 $1.47
Six Months Ended June 30,
20212020
(In millions, except per share data)Earnings per
Diluted Share		Earnings per
Diluted Share
Net Income Attributable to Common Shareholders$112 $0.11 $1,103 $1.13 
Mark-to-Market Impact of Economic Hedging Activities (net of taxes of $125 and $50, respectively)(366)(0.37)(146)(0.15)
Unrealized (Gains) Losses Related to NDT Fund Investments (net of taxes of $94 and $130, respectively)(a)
(87)(0.09)180 0.18 
Asset Impairments (net of taxes of $124 and $7, respectively)(b)
368 0.38 21 0.02 
Plant Retirements and Divestitures (net of taxes of $219 and $6, respectively)(c)
654 0.67 20 0.02 
Cost Management Program (net of taxes of $1 and $6, respectively)(d)
4 — 17 0.02 
Change in Environmental Liabilities (net of taxes of $1 and $0, respectively)2 — 1 — 
COVID-19 Direct Costs (net of taxes of $7 and $10, respectively)(e)
18 0.02 27 0.03 
Deferred Prosecution Agreement Payments (net of taxes of $0)(f)
— — 200 0.20 
Acquisition Related Costs (net of tax of $3)(g)
7 0.01 — — 
ERP System Implementation Costs (net of taxes of $1)(h)
7 0.01 — — 
Planned Separation Costs (net of taxes of $7)(i)
21 0.02 — — 
Costs Related to Suspension of Contractual Offset (net of taxes of $12)(j)
41 0.04 — — 
Income Tax-Related Adjustments (entire amount represents tax expense)(4)— 4 — 
Noncontrolling Interests (net of taxes of $3 and $10, respectively)(k)
33 0.03 (40)(0.04)
Adjusted (non-GAAP) Operating Earnings$809 $0.83 $1,387 $1.42 
__________
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 fund investments, the marginal statutory income tax rates for 20202021 and 20192020 ranged from 26.0%25.0% 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 fund investments were 47.4%50.6% and 35.1%47.4% for the three months ended June 30, 20202021 and 2019,2020, respectively. The effective tax rates for the unrealized gains and losses related to NDT fund investments were 41.9%51.7% and 48.4%41.9% for the six months ended June 30, 20202021 and 2019,2020, 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)
(a)Reflects the impact of net unrealized gains on Generation’s NDT fund investments for Non-Regulatory Agreement Units.
(b)In 2021, reflects an impairment in the New England asset group and an impairment recorded as a result of the agreement to sell the Albany Green Energy biomass facility. In 2020, reflects an impairment at ComEd related to the acquisition of transmission assets and the impairment of certain wind assets at Generation.
(c)In 2021, primarily reflects accelerated depreciation and amortization associated with Generation's decision 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 a gain on sale of Generation's solar business. In 2020, primarily reflects accelerated depreciation and amortization expenses associated with the early retirement of certain fossil sites.
(d)Primarily represents reorganization costs related to cost management programs.
(e)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.
(f)Reflects the payments made by ComEd related to the acquisition of transmission assets and the impairment of certain wind assets at Generation.
(c)
In 2019, primarily reflects net realized gains related to Oyster Creek's NDT fund investments in conjunction with the Holtec sale on July 1, 2019and a gain on the sale of certain wind assets, partially offset by accelerated depreciation and amortization expenses associated with the early retirement of the TMI nuclear facility. In 2020, primarily reflects accelerated depreciation and amortization expenses associated with the early retirement of certain fossil sites.
(d)
Primarily represents reorganization costs related to cost management programs.
(e)
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.
(f)Reflects the payments that ComEd will make under the Deferred Prosecution Agreement. See Note 14 - Commitments and Contingencies of the Combined Notes to Consolidated Financial Statements for additional information.
(g)
Represents elimination from Generation’s results of the noncontrolling interests related to certain exclusion items, primarily related to unrealized gains and losses on NDT fund investments for CENG units.

Significant 2020 Transactions and Developments
Deferred Prosecution Agreement
On July 17, 2020, ComEd entered into a Deferred Prosecution Agreement, (DPA)which ComEd entered in July 2020 with the U.S. Attorney’s Office for the Northern District of Illinois (USAO)Illinois.
150



(g)Reflects costs related to resolve the USAO’s investigation into ComEd’s lobbying activitiesacquisition of EDF's interest in CENG.
(h)Reflects costs related to a multi-year Enterprise Resource Program (ERP) system implementation.
(i)Represents costs related to the planned separation primarily comprised of system-related costs, third-party costs paid to advisors, consultants, lawyers, and other experts assisting in the Stateplanned separation, and employee-related severance costs.
(j)Decommissioning-related activities for the former ComEd and PECO units (Regulatory Agreement Units), net of Illinois. Underapplicable taxes, including realized and unrealized gains and losses on the DPA,NDT funds, depreciation of the USAOARC, and accretion of the decommissioning obligation, are generally offset within Exelon’s and Generation’s consolidated statements of operations. These costs reflect the impact of suspension of contractual offset for the Byron units in the second quarter of 2021.
(k)Represents elimination from Generation’s results of the noncontrolling interests related to certain exclusion items, primarily related to unrealized gains and losses on NDT fund investments for CENG units.
Significant 2021 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.
On February 25, 2021, Exelon and Generation filed applications with the FERC, NYPSC, and NRC seeking approvals for the separation of Generation. On March 25, 2021, Exelon filed a single charge alleging that ComEd improperly gave and offeredrequest for a private letter ruling with the IRS to give jobs, vendor subcontracts, and payments associated with those jobs and subcontracts forconfirm the benefittax-free treatment of the Speakerplanned separation. Exelon and Generation expect a decision from the IRS in the third quarter of 2021, the Illinois HouseFERC in the second half of Representatives2021, the NRC in the fourth quarter of 2021, and have requested a decision from the Speaker’s associates, withNYPSC before the intent to influenceend of 2021. Exelon and Generation cannot predict if the Speaker’s action regarding legislation affecting ComEd’s interests. The DPA provides that the USAOapplications will defer any prosecution of such charge and any other criminal or civil case against ComEd inbe approved as filed.
In connection with the matters identified thereinplanned separation, Exelon incurred transaction costs of approximately $19 million and $28 million on a pre-tax basis for the three and six months ended June 30, 2021, respectively, which are excluded from Adjusted (non-GAAP) Operating Earnings. The transaction costs are primarily comprised of system-related costs, third-party costs paid to advisors, consultants, lawyers, and other experts assisting in the planned separation, and employee-related severance costs.
There can be no assurance that any separation transaction will ultimately occur or, if one does occur, of its terms or timing. See Note 20 — Planned Separation of the Combined Notes to Consolidated Financial Statements for additional information.
Impacts of the February 2021 Extreme Cold Weather Event 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 outages as a result of extreme cold weather conditions. In addition, those weather conditions drove increased demand for service, dramatically increased wholesale power prices, and also increased gas prices in certain regions.
The estimated impact to Exelon’s and Generation’s Net income for the six months ended June 30, 2021 arising from these market and weather conditions was a reduction of approximately $880 million. The estimated impact to Exelon's and Generation's Net income for the three months ended June 30, 2021 was not material. The six months ended estimated impact includes certain charges associated with the natural gas business that may be reduced through waivers and/or recoveries from customers. Therefore, such charges are not included in the estimated full year earnings impact. Exelon and Generation estimate a reduction in Net income of approximately $670 million to $820 million for the full year 2021. 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 or federal solutions to address the financial challenges caused by the event, and related litigation and contract disputes. See Note 3 — Regulatory Matters and Note 15 — Commitments and Contingencies of the Combined Notes to Consolidated Financial Statements for additional information.
Exelon expects to offset between $410 million and $490 million of this impact for the full year 2021 primarily at Generation through a combination of enhanced revenue opportunities, deferral of selected non-essential maintenance, and primarily one-time cost savings.
151



Agreement for the Sale of a Generation Biomass Facility
On April 28, 2021, Generation and ReGenerate entered into a purchase agreement, under which ReGenerate agreed to purchase Generation's interest in the Albany Green Energy biomass facility. As a result, in the second quarter of 2021, Exelon and Generation recorded a pre-tax impairment charge of $140 million which is excluded from Exelon’s and Generation’s Adjusted (non-GAAP) Operating Earnings. The sale was completed on June 30, 2021 for a three-year period subjectnet purchase price of $36 million. See Note 2 — Mergers, Acquisitions, and Dispositions of the Combined Notes to certain obligationsConsolidated Financial Statements for additional information.
Early Retirement of ComEd, including paymentGeneration 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, there are 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.
Also, as a result, in the third quarter of 2020, Exelon and Generation recognized a $500 million pre-tax impairment for the New England asset group. In the second quarter of 2021, an incremental decline in value resulted in an additional pre-tax impairment charge of $350 million for the New England asset group. See Note 9 — Asset Impairments of the Combined Notes to Consolidated Financial Statements for additional information.
Further, in the second quarter of 2021, Exelon and Generation recorded a pre-tax charge of $53 million for decommissioning-related activities that were not offset for the Byron units due to the United States Treasuryinability to recognize a regulatory asset at ComEd. In the event Byron retires in September 2021 as previously announced, the full year impact is estimated to be in the range of $200$450 million with $100to $600 million, payable within thirty daysdepending on future market returns. See Note 7 — Early Plant Retirements and Note 8 — Nuclear Decommissioning of the filingCombined Notes to Consolidated Financial Statements for additional information.
All of the DPAcharges above are excluded from Exelon's and Generation’s Adjusted (non-GAAP) Operating Earnings.
The following table summarizes the incremental expense recorded in the three and six months ended June 30, 2021 and the estimated amounts of incremental expense expected to be incurred for the full year 2021 and through the retirement dates.
Actual
Projected(a)
Income statement expense (pre-tax)Three Months Ended June 30, 2021Six Months Ended June 30, 20212021202220232024
Depreciation and amortization
     Accelerated depreciation(b)
$632 $1,271 $2,770 $10 $20 $10 
     Accelerated nuclear fuel amortization52 106 180 — — — 
Operating and maintenance
     Other charges2 4 20 10 10 30 
     Contractual offset(c)
(166)(391)(930)— — — 
Total$520 $990 $2,040 $20 $30 $40 

152



__________
(a)Actual results may differ based on incremental future capital additions, actual units of production for nuclear fuel amortization, future revised ARO assumptions, etc. and exclude any changes in earnings in the NDT funds.
(b)Reflects incremental accelerated depreciation of plant assets, including any ARC.
(c)Reflects contractual offset for ARO accretion, ARC depreciation, and net impacts associated with the United States District Courtremeasurement of the ARO for Byron and Dresden and exclude any changes in earnings in the NDT funds. Decommissioning-related activities were not offset for the Northern DistrictByron units starting in the second quarter of Illinois2021 due to the inability to recognize a regulatory asset at ComEd. 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 8 – Nuclear Decommissioning of the Combined Notes to Consolidated Financial Statements for 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.information.

Utility Rates and Base Rate 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 2020.2021. See Note 23 — 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 16, 2020Electric$(11)$(14)8.38 %December 9, 2020January 1, 2021
PECO - PennsylvaniaSeptember 30, 2020Natural Gas69 29 10.24 %June 22, 2021July 1, 2021
BGE - MarylandMay 15, 2020 (amended September 11, 2020)Electric203 140 9.50 %December 16, 2020January 1, 2021
Natural Gas108 74 9.65 %
Pepco - District of ColumbiaMay 30, 2019 (amended June 1, 2020)Electric136 109 9.275 %June 8, 2021July 1, 2021
Pepco - MarylandOctober 26, 2020 (amended March 31, 2021)Electric104 52 9.55 %June 28, 2021June 28, 2021
ACE - New JerseyDecember 9, 2020 (amended February 26, 2021)Electric67 41 9.60 %July 14, 2021January 1, 2022
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Registrant/JurisdictionFiling DateRequested Revenue Requirement (Decrease) IncreaseApproved Revenue Requirement (Decrease) IncreaseApproved ROEApproval DateRate Effective Date
ComEd - Illinois (Electric)April 8, 2019$(6)$(17)8.91%December 4, 2019January 1, 2020
DPL - Maryland (Electric)December 5, 2019 (amended April 23, 2020)17
12
9.60%July 14, 2020July 16, 2020

Pending Distribution Base Rate Case Proceedings
Registrant/JurisdictionFiling DateRequested Revenue Requirement (Decrease) IncreaseRequested ROEExpected Approval Timing
ComEd - Illinois (Electric)April 16, 2020$(11)8.38%Fourth quarter of 2020
BGE - Maryland (Electric and Natural Gas)May 15, 2020235
10.1%Fourth quarter of 2020
Pepco - District of Columbia (Electric)May 30, 2019 (amended June 1, 2020)136
9.7%Fourth quarter of 2020
DPL - Delaware (Natural Gas)February 21, 2020 (amended March 17, 2020)9
10.3%First quarter of 2021
DPL - Delaware (Electric)March 6, 2020 (amended April 16, 2020)24
10.3%Second quarter of 2021
Registrant/JurisdictionFiling DateServiceRequested Revenue Requirement IncreaseRequested ROEExpected Approval Timing
ComEd - IllinoisApril 16, 2021Electric$51 7.36 %Fourth quarter of 2021
PECO - PennsylvaniaMarch 30, 2021Electric246 10.95 %Fourth quarter of 2021
DPL - DelawareMarch 6, 2020 (amended February 2, 2021)Electric23 10.3 %Third quarter of 2021
Transmission Formula Rates
Transmission Formula Rate (Exelon, ComEd, PECO, BGE, PHI, Pepco, DPL and ACE). ComEd’s, PECO's, BGE’s, Pepco's, DPL's and ACE's transmission rates are each established based on a FERC-approved formula. ComEd, BGE, Pepco, DPL and ACE are required to file an annual update to the FERC-approved formula on or before May 15 and PECO is required to file on or before May 31, with the resulting rates effective on June 1 of the same year. The annual update for ComEd, BGE, DPL and ACE is based on prior year actual costs and current year projected capital additions (initial year revenue requirement). The annual update for PECO is based on prior year actual costs and current year projected capital additions, accumulated depreciation, and accumulated deferred income taxes. The annual update for Pepco is based on prior year actual costs and current year projected capital additions, accumulated depreciation, depreciation and amortization expense and accumulated deferred income taxes. The update for ComEd, BGE, DPL and ACE also reconciles any differences between the revenue requirement in effect beginning June 1 of the prior year and actual costs incurred for that year (annual reconciliation). The update for PECO and Pepco also reconciles any differences between the actual costs and actual revenues for the calendar year (annual reconciliation).
For 2020, the following total increases/(decreases) were included in ComEd’s, PECO's, BGE’s, Pepco's, DPL's and ACE'sthe Utility Registrants' 2021 electric transmission formula rate filings:
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%
PECO5
(28)(23)7.47%10.35%
BGE16
(3)4
7.26%10.50%
Pepco2
(46)(44)7.81%10.50%
DPL(4)(40)(44)7.20%10.50%
ACE5
(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.updates. See Note 53 — Accounts ReceivableRegulatory Matters of the Combined Notes to Consolidated Financial Statements for additional information.
RegistrantInitial Revenue Requirement Increase (Decrease)Annual Reconciliation IncreaseTotal Revenue Requirement IncreaseAllowed Return on Rate BaseAllowed ROE
ComEd$33 $12 $45 8.20 %11.50 %
PECO(2)26 24 7.37 %10.35 %
BGE38 27 65 7.35 %10.50 %
Pepco(9)21 12 7.68 %10.50 %
DPL19 33 52 7.20 %10.50 %
ACE27 24 51 7.45 %10.50 %
Other Key Business Drivers and Management Strategies
The following discussion of other key business driver and management strategies includes current developments of previously disclosed matters and new issues arising during the period that may impact future financial statements. This section should be read in conjunction with ITEM 1. Business and ITEM 7. Management's Discussion and Analysis of Financial Condition and Results of Operations — Other Key Business Drivers and Management Strategies in the Registrants' combined 20192020 Form 10-K and Note 1415 — Commitments and Contingencies to the Consolidated Financial Statements in this report for additional information on various environmental matters.
Power Markets
Section 232 Uranium PetitionComplaint at FERC Seeking to Alter Capacity Market Default Offer Caps
On January 16, 2018, two Canadian-owned uranium mining companies with operationsFebruary 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. Several consumer advocates filed a complaint seeking similar relief several months after the IMM’s complaint. On March 18, 2021, FERC granted the complaints, finding the current estimate of performance assessment intervals to be excessive compared to the reasonably expected number of performance assessment intervals which results in an unjust and unreasonable default offer cap. FERC did not establish the number of performance assessment intervals that should be used to calculate the default offer cap and instead requested briefs on the matter, including alternative approaches to mitigation in the U.S. jointlycapacity market. Exelon submitted a petitionan initial and reply briefs on May 3, 2021 and June 9, 2021, respectively, and an answer 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 publicbriefs filed by other parties on April 23, 2020. The Working Group report states that nuclear powerJune 24, 2021. It is intrinsically tiedtoo early 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”) 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 Russian Suspension Agreement 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 the U.S. government has expressed interest in continuing the limitations on Russian imports by renegotiating the Russian Suspension Agreement.
The Working Group report should be viewed as policy recommendations that may be implemented by executive agencies, congress and or regulatory bodies. Negotiations between the DOC and the Russians on an extension of the Russian Suspension Agreement are in progress at this time, and may result in a reduction in the amount of uranium that can be imported from Russia, which may have the effect of reducing the diversity of supply available to Exelon for uranium, enrichment and conversion services purchases. Exelon and Generation cannot currently predict the final outcome of the policy changes recommended by the Working Group.this proceeding or its potential financial impact, if any, on Exelon or Generation.
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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 June 30, 2020,2021, the percentage of expected generation hedged for the Mid-Atlantic, Midwest, New York, and ERCOT reportable segments is 98%-101% and 76%-79% for 2020 and 2021, respectively.2021. Generation has been and will continue to be proactive in using hedging strategies to mitigate commodity price risk.
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

2020 2021 through 20242025 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 results of operations, cash flows andconsolidated financial positions.statements.
See Note 1112 — Derivative Financial Instruments of the Combined Notes to Consolidated Financial Statements and ItemITEM 3. Quantitative and Qualitative Disclosures about Market RiskQUANTITATIVE 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.
Environmental Regulation
Exelon is well positioned to support increasingly ambitious climate policy and to partner with our customers and communities to reduce GHG emissions.
In August 2021, the Utility Registrants announced a “path to clean” goal to collectively reduce their operations-driven emissions 50% by 2030 against a 2015 baseline, and to reach net zero operations-driven emissions by 2050. This goal builds upon Exelon’s long-standing commitment to reducing our GHG emissions. The Utility Registrants “path to clean” will include efficiency and clean electricity for operations, vehicle fleet electrification, equipment and processes to reduce sulfur hexafluoride (SF6) leakage, modern natural gas infrastructure to minimize methane leaks and increase safety and reliability, and investment and collaboration to develop new technologies.
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.
The United States has set an economy-wide target of reducing its net GHG emissions by 50-52% below 2005 levels by 2030.
Other Legislative and Regulatory Developments
Air QualityFERC Supplemental Notice of Proposed Rulemaking
On April 15, 2021, the FERC issued a Supplemental Notice of Proposed Rulemaking (NOPR) proposing to modify the current regulation permitting a continuous 50-basis-point ROE incentive adder for a transmission utility that joins and remains a member of a RTO. Under the NOPR, the ROE incentive adder would only be available for a period of up to three years after a transmission utility newly joins a RTO and all existing ROE incentive adders would end for transmission utilities that have been members for three or more years. The Utility
155
Mercury and Air Toxics Standards Rule (MATS).
On December 16, 2011,

Registrants’ existing transmission rates include the EPA signedROE incentive adder. Exelon submitted comments to FERC on this matter on June 25, 2021. Exelon cannot predict the outcome, but a final rule known as MATS,proposed could have an adverse impact to reduce emissionsExelon’s and the Utility Registrants’ financial statements. See Note 3 — Regulatory Matters of hazardous air pollutants from power plants. MATS requires coal-fired power plantsthe Combined Notes to achieve high removalConsolidated Financial Statements for additional information regarding the Utility Registrants’ transmission formula rates and regulatory proceedings at the FERC.
City of mercury, acid gasesChicago Franchise Agreement
ComEd has had a Franchise Agreement with the City of Chicago (the City) since 1992. The Franchise Agreement grants rights to use the public right of way to install, maintain, and operate the wires, poles, and other metals,infrastructure required to deliver electricity to residents and businesses across the City. The Franchise Agreement became terminable on one year notice as of December 31, 2020. It now continues in effect indefinitely unless and until either party issues a notice of termination, effective one year later, or it is replaced by mutual agreement with a new franchise agreement between ComEd and the City. If either party terminates and no new agreement is reached between the parties, the parties could continue with ComEd providing electric services within the City with no franchise agreement in place. The City also has an option to make capital investmentsterminate and purchase the ComEd system (“municipalize”), which also requires one year notice. Neither party has issued a notice of termination at this time, the City has not exercised its municipalization option, and no new agreement has been reached. Accordingly, the 1992 Franchise Agreement remains in pollution control equipment and incur higher operating expenses.effect at this time. In April 2014,2021, the U.S. CourtCity invited interested parties to respond to a Request for Information (RFI) regarding the franchise for electricity delivery. Under this process, the City could choose to terminate the ComEd Franchise Agreement on one year notice and grant a franchise to another party instead. Final responses to the RFI were due on July 30, 2021, however, on July 29, 2021, the City chose to extend the final submission deadline to September 30, 2021. While Exelon and ComEd cannot predict the ultimate outcome of Appealsthe RFI and the Franchise Agreement, fundamental changes in the agreement or other adverse actions affecting ComEd’s business in the City would require changes in their business planning models and operations and could have a material adverse impact on Exelon’s and ComEd’s consolidated financial statements. If the City were to disconnect from the ComEd system, ComEd would seek full compensation for the D.C. Circuit issued a decision upholding MATS inbusiness and its entirety. On appeal,associated property taken by the U.S. Supreme Court decided in June 2015 that the EPA unreasonably refused to consider costs in determining whether it is appropriate and necessary to regulate power plant emissions of hazardous air pollutants, but did not vacate MATS. In 2016, the EPA issued a supplemental finding responding to the U.S. Supreme Court’s decision; the EPA concluded that, after considering costs, it remained appropriate and necessary to regulate hazardous air pollutants from power plants. On May 22, 2020, however, 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. D.C. Circuit court seeking vacatur of MATS based on EPA’s May 22, 2020 ruling. On June 22, 2020, Exelon and two other entities filed a motion to intervene in that lawsuit to defend MATS, and on July 21, 2020, they separately filed a lawsuit in the D.C. Circuit court challenging the EPA’s May 22, 2020 rescission of the appropriate and necessary finding underpinning MATS.
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,City, as well as for all damages resulting to ComEd and its system. ComEd would also seek appropriate compensation for stranded costs with the development of new or expanded zero-emissions generation. In July 2019, the EPA published its final the 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 has been consolidated with separate challenges to the Affordable Clean Energy rule filed by various states, non-governmental organizations, and business coalitions.FERC.
Employees
In June 2020,the second quarter of 2021, Generation ComEd, and DPLPECO ratified or extended CBAs as follows:
•Generation ratified its CBA with SPFPA Local 238,UGSOA, which covers 12273 security officers at Quad Cities.Three Mile Island. The CBA expireswill expire in 2023.
ComEd extended its CBA•PECO ratified two CBAs with IBEW Local 15 to 2022,614 which covers 801,140 operations employees in the System Services Group.  
DPL ratified its CBAs with IBEW Locals 1238 and 1307, which together cover 857 employees.185 customer service employees, respectively. Both CBAs expire in 2024.2026.


Critical Accounting Policies and Estimates
Management of each of the Registrants makes a number of significant estimates, assumptions, and judgments in the preparation of its financial statements. At June 30, 2020,2021, the Registrants’ critical accounting policies and estimates had not changed significantly from December 31, 2019.2020. See ITEM 7. MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS — Critical Accounting Policies and Estimates in the Registrants' 20192020 Form 10-K for further information.

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Generation
Results of Operations by Registrant

151

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.
Three Months Ended
June 30,		 
Favorable
(Unfavorable)
Variance
 Six Months Ended
June 30,		 

(Unfavorable)
Favorable
Variance
Three Months Ended
June 30,		Favorable
(Unfavorable)
Variance		Six Months Ended
June 30,

Favorable
(Unfavorable)
Variance
2020 2019 2020 2019 2021202020212020
Operating revenues$3,880
 $4,210
 $(330) $8,613
 $9,506
 $(893)Operating revenues$4,153 $3,880 $273 $9,712 $8,613 $1,099 
Purchased power and fuel expense1,942
 2,292
 350
 4,646
 5,497
 851
Purchased power and fuel expense1,947 1,942 (5)6,557 4,646 (1,911)
Revenues net of purchased power and fuel expense1,938
 1,918
 20
 3,967
 4,009
 (42)Revenues net of purchased power and fuel expense2,206 1,938 268 3,155 3,967 (812)
Other operating expenses           Other operating expenses
Operating and maintenance1,189
 1,266
 77
 2,451
 2,484
 33
Operating and maintenance1,474 1,189 (285)2,476 2,451 (25)
Depreciation and amortization300
 409
 109
 604
 814
 210
Depreciation and amortization930 300 (630)1,869 604 (1,265)
Taxes other than income taxes116
 129
 13
 246
 264
 18
Taxes other than income taxes118 116 (2)239 246 7 
Total other operating expenses1,605
 1,804
 199
 3,301
 3,562
 261
Total other operating expenses2,522 1,605 (917)4,584 3,301 (1,283)
Gain on sales of assets and businesses12
 33
 (21) 12
 33
 (21)Gain on sales of assets and businesses8 12 (4)79 12 67 
Operating income345

147
 198
 678

480
 198
Operating (loss) incomeOperating (loss) income(308)345 (653)(1,350)678 (2,028)
Other income and (deductions)           Other income and (deductions)
Interest expense, net(87) (116) 29
 (197) (227) 30
Interest expense, net(76)(87)11 (148)(197)49 
Other, net602
 171
 431
 (168) 601
 (769)Other, net508 602 (94)675 (168)843 
Total other income and (deductions)515
 55
 460
 (365) 374
 (739)Total other income and (deductions)432 515 (83)527 (365)892 
Income before income taxes860
 202
 658
 313
 854
 (541)
Income (loss) before income taxesIncome (loss) before income taxes124 860 (736)(823)313 (1,136)
Income taxes329
 78
 (251) (59) 301
 360
Income taxes110 329 219 (70)(59)11 
Equity in losses of unconsolidated affiliates(2) (6) 4
 (4) (13) 9
Equity in losses of unconsolidated affiliates(1)(2)1 (3)(4)1 
Net income529

118

411

368

540

(172)
Net income (loss)Net income (loss)13 529 (516)(756)368 (1,124)
Net income (loss) attributable to noncontrolling interests53
 10
 43
 (153) 68
 (221)Net income (loss) attributable to noncontrolling interests74 53 21 98 (153)251 
Net income attributable to membership interest$476
 $108
 $368
 $521
 $472
 $49
Net (loss) income attributable to membership interestNet (loss) income attributable to membership interest$(61)$476 $(537)$(854)$521 $(1,375)
Three Months Ended June 30, 20202021 Compared to Three Months Ended June 30, 2019.2020. Net income attributable to membership interest decreased by $537 million primarily due to:
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Generation
•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;
•Impairments of the New England asset group and the Albany Green Energy biomass facility at
    Generation; and
•Lower net unrealized and realized gains on NDT funds.
The decreases were partially offset by:
•Higher mark-to-market gains;
•Higher net unrealized and realized gains on equity investments;
•Lower nuclear outage days; and
•Higher New York ZEC revenues due to higher generation and an increase in ZEC prices.
Six Months Ended June 30, 2021 Compared to Six Months Ended June 30, 2020. Net income attributable to membership interestinterest increased $368decreased by $1,375 million by primarilyprimarily due to:
•Impacts of the February 2021 extreme cold weather event;
•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;
•Impairments of the New England asset group and the Albany Green Energy biomass facility at
    Generation; and
•The absence of a prior year one-time tax settlement.
The decreases were partially offset by:
•Higher mark-to-market gains;
•Higher net unrealized and realized gains on NDT funds;
Higher mark-to-market gains; and
Lower operating and maintenance expense primarily due to lower contracting costs.
The increases were partially offset by:
Lower capacity revenue;

152

Reduction in load due to COVID-19;
•
COVID-19 direct costs; and
Higher credit loss expense that includes the impacts of COVID-19.
Six Months Ended June 30, 2020 Compared to Six Months Ended June 30, 2019.•Net income attributable to membership interest increased $49 million by primarily due to:
Higher mark-to-market gains;
Lower operating and maintenance expense primarily due to previous cost management programs and lower contracting costs;
The approval of the New Jersey ZEC program in the second quarter of 2019; and
•
An income tax settlement.
The increases were partially offset by:
Higher net unrealized and realized lossesgains on NDT funds;equity investments;
•Lower capacity revenue;nuclear outage days; and
Reduction in load•Higher New York ZEC revenues due to COVID-19;
•
Higher nuclear outage days;higher generation and an increase in ZEC prices.
•
COVID-19 direct costs; and
Higher credit loss expense that includes the impacts of COVID-19.
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 45 - Segment 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;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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Generation
and ancillary services. Fuel expense includes the fuel costs for owned generation and fuel costs associated with tolling agreements.

153

For the three and six months ended June 30, 20202021 compared to 2019,2020, RNF by region were as follows. See Note 45 - 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.
Three Months Ended
June 30,		Variance% ChangeSix Months Ended
June 30,		Variance% Change
2021202020212020
Mid-Atlantic(a)
$572 $525 $47 9.0 %$1,141 $1,092 $49 4.5 %
Midwest(b)
658 703 (45)(6.4)%1,360 1,427 (67)(4.7)%
New York292 246 46 18.7 %536 440 96 21.8 %
ERCOT83 97 (14)(14.4)%(1,102)177 (1,279)(722.6)%
Other Power Regions136 157 (21)(13.4)%353 312 41 13.1 %
Total electric revenues net of purchased power and fuel expense1,741 1,728 13 0.8 %2,288 3,448 (1,160)(33.6)%
Mark-to-market gains314 85 229 269.4 %489 218 271 124.3 %
Other151 125 26 20.8 %378 301 77 25.6 %
Total revenue net of purchased power and fuel expense$2,206 $1,938 $268 13.8 %$3,155 $3,967 $(812)(20.5)%
 Three Months Ended
June 30,		 Variance % Change Six Months Ended
June 30,		 Variance % Change
 2020 2019  2020 2019 
Mid-Atlantic(a)
$525
 $652
 $(127) (19.5)% $1,092
 $1,334
 $(242) (18.1)%
Midwest(b)
703
 730
 (27) (3.7)% 1,427
 1,500
 (73) (4.9)%
New York246
 253
 (7) (2.8)% 440
 519
 (79) (15.2)%
ERCOT97
 79
 18
 22.8 % 177
 154
 23
 14.9 %
Other Power Regions157
 134
 23
 17.2 % 312
 292
 20
 6.8 %
Total electric revenues net of purchased power and fuel expense1,728
 1,848
 (120) (6.5)% 3,448
 3,799
 (351) (9.2)%
Mark-to-market gains (losses)85
 (74) 159
 214.9 % 218
 (102) 320
 313.7 %
Other125
 144
 (19) (13.2)% 301
 312
 (11) (3.5)%
Total revenue net of purchased power and fuel expense$1,938
 $1,918
 $20
 1.0 % $3,967
 $4,009
 $(42) (1.0)%
__________
_________
(a)Includes results of transactions with PECO, BGE, Pepco, DPL and ACE.
(b)Includes results of transactions with ComEd.

(a)Includes results of transactions with PECO, BGE, Pepco, DPL, and ACE.

(b)Includes results of transactions with ComEd.



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159




Generation

Generation’s supply sources by region are summarized below:
Three Months Ended
June 30,		Variance% ChangeSix Months Ended
June 30,		Variance% Change
Supply Source (GWhs)2021202020212020
Nuclear Generation(a)
Mid-Atlantic13,197 13,167 30 0.2 %26,451 25,951 500 1.9 %
Midwest23,299 23,860 (561)(2.4)%46,454 47,458 (1,004)(2.1)%
New York7,079 6,389 690 10.8 %14,135 12,562 1,573 12.5 %
Total Nuclear Generation43,575 43,416 159 0.4 %87,040 85,971 1,069 1.2 %
Fossil and Renewables
Mid-Atlantic522 707 (185)(26.2)%1,185 1,560 (375)(24.0)%
Midwest262 268 (6)(2.2)%585 656 (71)(10.8)%
New York— 1 (1)(100.0)%1 2 (1)(50.0)%
ERCOT2,797 3,251 (454)(14.0)%5,581 6,263 (682)(10.9)%
Other Power Regions2,239 2,603 (364)(14.0)%5,205 6,110 (905)(14.8)%
Total Fossil and Renewables5,820 6,830 (1,010)(14.8)%12,557 14,591 (2,034)(13.9)%
Purchased Power
Mid-Atlantic3,089 3,730 (641)(17.2)%7,571 9,672 (2,101)(21.7)%
Midwest131 236 (105)(44.5)%310 524 (214)(40.8)%
ERCOT1,259 1,255 4 0.3 %2,031 2,246 (215)(9.6)%
Other Power Regions12,356 11,303 1,053 9.3 %25,189 23,469 1,720 7.3 %
Total Purchased Power16,835 16,524 311 1.9 %35,101 35,911 (810)(2.3)%
Total Supply/Sales by Region
Mid-Atlantic(b)
16,808 17,604 (796)(4.5)%35,207 37,183 (1,976)(5.3)%
Midwest(b)
23,692 24,364 (672)(2.8)%47,349 48,638 (1,289)(2.7)%
New York7,079 6,390 689 10.8 %14,136 12,564 1,572 12.5 %
ERCOT4,056 4,506 (450)(10.0)%7,612 8,509 (897)(10.5)%
Other Power Regions14,595 13,906 689 5.0 %30,394 29,579 815 2.8 %
Total Supply/Sales by Region66,230 66,770 (540)(0.8)%134,698 136,473 (1,775)(1.3)%
 Three Months Ended
June 30,		 Variance % Change Six Months Ended
June 30,		 Variance % Change
Supply Source (GWhs)2020 2019  2020 2019 
Nuclear Generation(a)
               
Mid-Atlantic13,167
 14,075
 (908) (6.5)% 25,951
 29,155
 (3,204) (11.0)%
Midwest23,860
 23,996
 (136) (0.6)% 47,458
 47,729
 (271) (0.6)%
New York6,389
 6,677
 (288) (4.3)% 12,562
 13,579
 (1,017) (7.5)%
Total Nuclear Generation43,416
 44,748
 (1,332) (3.0)% 85,971

90,463
 (4,492) (5.0)%
Fossil and Renewables            
 
Mid-Atlantic707
 915
 (208) (22.7)% 1,560
 1,865
 (305) (16.4)%
Midwest268
 328
 (60) (18.3)% 656
 719
 (63) (8.8)%
New York1
 1
 —
 — % 2
 2
 —
 — %
ERCOT3,251
 3,066
 185
 6.0 % 6,263
 6,144
 119
 1.9 %
Other Power Regions2,603
 2,514
 89
 3.5 % 6,110
 5,654
 456
 8.1 %
Total Fossil and Renewables6,830
 6,824
 6
 0.1 % 14,591

14,384
 207
 1.4 %
Purchased Power            
 
Mid-Atlantic3,730
 2,557
 1,173
 45.9 % 9,672
 5,123
 4,549
 88.8 %
Midwest236
 250
 (14) (5.6)% 524
 538
 (14) (2.6)%
ERCOT1,255
 1,213
 42
 3.5 % 2,246
 2,255
 (9) (0.4)%
Other Power Regions11,303
 11,116
 187
 1.7 % 23,469
 23,684
 (215) (0.9)%
Total Purchased Power16,524
 15,136
 1,388
 9.2 % 35,911

31,600
 4,311
 13.6 %
Total Supply/Sales by Region(c)
            
 
Mid-Atlantic(b)
17,604
 17,547
 57
 0.3 % 37,183
 36,143
 1,040
 2.9 %
Midwest(b)
24,364
 24,574
 (210) (0.9)% 48,638
 48,986
 (348) (0.7)%
New York6,390
 6,678
 (288) (4.3)% 12,564
 13,581
 (1,017) (7.5)%
ERCOT4,506
 4,279
 227
 5.3 % 8,509
 8,399
 110
 1.3 %
Other Power Regions13,906
 13,630
 276
 2.0 % 29,579
 29,338
 241
 0.8 %
Total Supply/Sales by Region66,770
 66,708
 62
 0.1 % 136,473

136,447
 26
 — %
__________
_________(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).
(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.
(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.

155
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Generation

For the three and six months ended June 30, 20202021 compared to 2019,2020, changes in RNF by region were as follows:
Increase/(Decrease)Three Months Ended
June 30, 2021		Increase/(Decrease)Six Months Ended
June 30, 2021
Mid-Atlantic$47 • favorable settlement of an outstanding regulatory matter
• increased capacity revenue, offset by
• decreased load served
$49 • favorable settlement of an outstanding regulatory matter
• increased capacity revenue
• decreased nuclear outage days
• increased ZEC revenues due to decreased nuclear outage days, offset by
• decreased load served
Midwest(45)• decreased total ISO sales due to decreased generation
• decreased capacity revenue, partially offset by
• increased load served		(67)• decreased load served
• decreased total ISO sales due to decreased generation
New York46 • increased ZEC revenues due to decreased nuclear outage days and higher ZEC prices
• decreased nuclear outage days
• increased capacity revenue
• increased load served
96 • increased ZEC revenues due to decreased nuclear outage days and higher ZEC prices
• decreased nuclear outage days
• increased capacity revenue
• increased load served
ERCOT(14)• higher energy procurement costs due to increased outage days(1,279)• higher energy procurement costs due to the February 2021 extreme cold weather event, as well as the impact of ERCOT market participant defaults
• higher procurement costs due to increased outage days
Other Power Regions(21)• decreased capacity revenue, partially offset by
• increased load served
• higher portfolio optimization		41 • increased load served
• higher portfolio optimization, partially offset by
• decreased capacity revenue
Mark-to-market(a)
229 • gains on economic hedging activities of $314 million in 2021 compared to gains of $85 million in 2020271 • gains on economic hedging activities of $489 million in 2021 compared to gains of $218 million in 2020
Other26 • higher natural gas RNF due to higher natural gas prices and favorable LDC penalty waivers and revenue true ups related to the February 2021 extreme cold weather event
• increased revenue related to the energy efficiency business, partially offset by
• increase in accelerated nuclear fuel amortization associated with announced early plant retirements		77 • higher natural gas RNF due to higher portfolio optimization and higher natural gas prices, partially offset by penalties associated with operational flow orders and curtailments as a result of the February 2021 extreme cold weather event
• increased revenue related to the energy efficiency business, partially offset by
• increase in accelerated nuclear fuel amortization associated with announced early plant retirements
Total$268 $(812)
 Increase/ (Decrease)Three Months Ended
June 30, 2020		Increase/ (Decrease)Six Months Ended June 30, 2020
Mid-Atlantic$(127)
• decreased capacity revenue
• decreased revenue due to permanent cease of generation operations at Three Mile Island in the third quarter of 2019
• decreased load due to COVID-19
• lower realized energy prices, partially offset by
• increased ZEC revenues due to decreased nuclear outage days at Salem
$(242)
• decreased capacity revenue
• decreased revenue due to permanent cease of generation operations at Three Mile Island in the third quarter of 2019
• decreased load due to COVID-19
• lower realized energy prices, partially offset by
• increased ZEC revenues due to the approval of the NJ ZEC program in the second quarter of 2019


Midwest(27)
• decreased capacity revenue
• decreased load due to COVID-19
• lower realized energy prices


(73)
• decreased capacity revenue
• decreased load due to COVID-19
• lower realized energy prices
New York(7)
• decreased load due to COVID-19
• lower realized energy prices, partially offset by
• increased capacity revenues
(79)
• decreased load due to COVID-19
• lower realized energy prices
• increased nuclear outage days



ERCOT18
• higher portfolio optimization, partially offset by
• decreased load due to COVID-19

23
• higher portfolio optimization partially offset by
• decreased load due to COVID-19
Other Power Regions23
• higher portfolio optimization, partially offset by
• decreased capacity revenue
• decreased load due to COVID-19

20
• higher portfolio optimization, partially offset by
• decreased capacity revenue
• decreased load due to COVID-19

Mark-to-market(a)
159
• gains on economic hedging activities of $85 million in 2020 compared to losses of $74 million in 2019320
• gains on economic hedging activities of $218 million in 2020 compared to losses of $102 million in 2019
Other(19)• decreased revenue related to the energy efficiency business(11)
• decreased revenue related to the energy efficiency business

Total$20
 $(42) 
__________
_________
(a)See Note 11(a)See Note 12 — Derivative Financial Instruments for additional information on mark-to-market gains (losses).

156

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
161




Generation
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.
Three Months Ended
June 30,		 Six Months Ended
June 30,		Three Months Ended
June 30,		Six Months Ended
June 30,
2020 2019 2020 20192021202020212020
Nuclear fleet capacity factor95.4% 95.1% 94.7% 96.1%Nuclear fleet capacity factor93.7 %95.4 %94.5 %94.7 %
Refueling outage days92
 56
 186
 130
Refueling outage days66 92 150 186 
Non-refueling outage days—
 28
 11
 28
Non-refueling outage days7 — 10 11 
The changes in Operating and maintenance expense consisted of the following:
 Three Months Ended
June 30, 2020		 Six Months Ended June 30, 2020
 Increase (Decrease) Increase (Decrease)
Litigation Settlements$26
 $26
COVID-19 Direct Costs23
 23
Nuclear refueling outage costs, including the co-owned Salem plants12
 54
Credit loss expense(a)
12
 17
Asset Impairments9
 5
Pension and non-pension postretirement benefits expense(4) (9)
Accretion expense(5) (15)
Other(9) (4)
Travel and Entertainment(11) (12)
Plant retirements and divestitures(13) 69
Corporate allocations(16) (27)
Labor, other benefits, contracting and materials(b)
(101) (160)
Increase in operating and maintenance expense$(77) $(33)
Three Months Ended
June 30, 2021		Six Months Ended June 30, 2021
 Increase (Decrease)Increase (Decrease)
Asset impairments$481 $479 
Labor, other benefits, contracting, and materials24 (4)
Credit loss expense(4)43 
Corporate allocations(6)(11)
Nuclear refueling outage costs, including the co-owned Salem plants(37)(88)
Plant retirements and divestitures(a)
(171)(391)
Other(2)(3)
Total increase$285 $25 
___________________ 
(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 and lower labor costs resulting from previous cost management programs.
(a)Primarily reflects contractual offset of accelerated depreciation and amortization associated with Generation's decision to early retire the Byron and Dresden nuclear facilities. See Note 8 — Nuclear Decommissioning of the Combined Notes to Consolidated Financial Statements for additional information.
Depreciation and amortization expense for the three and six months ended June 30, 20202021 compared to the same period in 2019 decreased2020 increased primarily due to the permanent ceaseaccelerated depreciation and amortization associated with Generation's decision to early retire the Byron and Dresden nuclear facilities. A portion of generation operations at Three Mile Island in the third quarter of 2019.
Taxes other than income taxes for the threethis accelerated depreciation and six months ended June 30, 2020 compared to the same period in 2019 decreased primarily due to decreased salesamortization is offset within Operating and power usage.maintenance expense.

Gain on sales of assets and businessesbusinesses for the three and six months ended June 30, 20202021 compared to the same period in 2019 decreased2020 increased primarily due to Generation'sa gain on sale of certain wind assets in the second quarter of 2019.Generation's solar business.
InterestInterest Expense for the three and six months ended June 30, 20202021 compared to the same periodperiod in 20192020 decreased primarilyprimarily due to mark-to-market gains related to the maturityEGR IV interest swaps entered into in December 2020 and decreases in interest rates. See Note 17 — Debt and Credit Agreements of long-term debt in the first and second quarter of 2020.Exelon 2020 Form 10-K for additional information on the interest swaps.

157

Other, net for the three months ended June 30, 20202021 compared to the same same period in 2019 increased2020 decreased and for the six months ended June 30, 20202021 compared to the same period in 2019 decreased2020 increased due to activity associated with NDT funds as described in the table below:
 Three Months Ended
June 30,		 Six Months Ended
June 30,
 2020 2019 2020 2019
Net unrealized (losses) gains on NDT funds(a)
$452

$(98) $(253) $182
Net realized gains on sale of NDT funds(a)
3
 193
 58
 222
Interest and dividend income on NDT funds(a)
19
 36
 46
 61
Contractual elimination of income tax expense(b)
134
 34
 (43) 120
Other(6) 6
 24
 16
Total other, net$602
 $171
 $(168) $601
162
_________



Generation
Three Months Ended
June 30,		Six Months Ended
June 30,
2021202020212020
Net unrealized gains (losses) on NDT funds(a)
$195 

$452 $128 $(253)
Net realized gains on sale of NDT funds(a)
63 3 248 58 
Interest and dividend income on NDT funds(a)
28 19 46 46 
Contractual elimination of income tax expense(b)
97 134 139 (43)
Net unrealized gains from equity investments(c)
119 — 96 — 
Other6 (6)18 24 
Total other, net$508 $602 $675 $(168)
__________ 
(a)Unrealized gains (losses), 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.
(a)Unrealized gains (losses), 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)Net unrealized gains from equity investments that became publicly traded entities in the fourth quarter of 2020 and the first half of 2021.

Effective income tax rates were 38.3%88.7% and 38.6%38.3% for the three months ended June 30, 2021 and 2020, respectively, and 2019, respectively. Generation's effective income tax rates were8.5% and (18.8)% and 35.2% for the six months ended June 30, 2021 and 2020, and 2019, respectively. The change primarily reflects one-time tax settlements. See Note 1210 — Income Taxes of the Combined Notes to Consolidated Financial Statements for additional information
Net income attributable to noncontrolling interests for the three and six months ended June 30, 20202021 compared to the same period in 20192020 increased primarily due to higher net gains on NDT fund investments for CENG and for the six months ended June 30, 2020 compared to the same period in 2019 decreased primarily due to unrealized losses on NDT fund investments for CENG.

163

158



Results of Operations — ComEd
Three Months Ended
June 30,		 
Favorable
(Unfavorable)
Variance
 Six Months Ended
June 30,		 
Favorable
(Unfavorable)
Variance
Three Months Ended
June 30,		Favorable
(Unfavorable)
Variance		Six Months Ended
June 30,		Favorable
(Unfavorable)
Variance
2020 2019 2020 2019 2021202020212020
Operating revenues$1,417
 $1,351
 $66
 $2,856
 $2,759
 $97
Operating revenues$1,517 $1,417 $100 $3,052 $2,856 $196 
Operating expenses           Operating expenses
Purchased power expense464
 407
 (57) 951
 892
 (59)Purchased power expense500 464 (36)1,025 951 (74)
Operating and maintenance536
 305
 (231) 853
 626
 (227)Operating and maintenance323 536 213 639 853 214 
Depreciation and amortization274
 257
 (17) 547
 508
 (39)Depreciation and amortization296 274 (22)589 547 (42)
Taxes other than income taxes71
 71
 —
 146
 148
 2
Taxes other than income taxes77 71 (6)153 146 (7)
Total operating expenses1,345
 1,040
 (305) 2,497
 2,174
 (323)Total operating expenses1,196 1,345 149 2,406 2,497 91 
Gain on sales of assets—
 —
 —
 —
 3
 (3)
Operating income72
 311
 (239) 359
 588
 (229)Operating income321 72 249 646 359 287 
Other income and (deductions)           Other income and (deductions)
Interest expense, net(98) (89) (9) (192) (178) (14)Interest expense, net(98)(98)— (193)(192)(1)
Other, net11
 10
 1
 22
 19
 3
Other, net15 11 4 22 22 — 
Total other income and (deductions)(87) (79) (8) (170) (159) (11)Total other income and (deductions)(83)(87)4 (171)(170)(1)
(Loss) income before income taxes(15) 232
 (247) 189
 429
 (240)
Income (loss) before income taxesIncome (loss) before income taxes238 (15)253 475 189 286 
Income taxes46
 46
 —
 82
 85
 3
Income taxes46 46 — 85 82 (3)
Net (loss) income$(61) $186
 $(247) $107
 $344
 $(237)
Net income (loss)Net income (loss)$192 $(61)$253 $390 $107 $283 
Three Months Ended June 30, 20202021 Compared to Three Months Ended June 30, 2019. 2020. Net income decreased $247increased $253 million as compared to the same period in 2019,2020, primarily due to payments that ComEd will makemade in 2020 under the Deferred Prosecution Agreement, an impairment charge resulting from acquisition of transmission assets, andAgreement. The remaining increase is due to electric distribution formula rate timing.earnings (reflecting the impacts of higher rate base and higher allowed electric distribution ROE due to an increase in treasury rates). See Note 14 —15 - Commitments and Contingencies of the Combined Notes to the Consolidated Financial Statements for additional information related to the Deferred Prosecution Agreement.
Six Months Ended June 30, 20202021 Compared to Six Months Ended June 30, 2019. 2020. Net income decreased $237increased $283 million as compared to the same period in 2019,2020, primarily due to payments that ComEd will makemade in 2020 under the Deferred Prosecution Agreement, an impairment charge resulting from acquisition of transmission assets, and lower allowed electric distribution ROEAgreement. The remaining increase is due to a decrease in treasury rates, partially offset by higher electric distribution formula rate earnings (reflecting the impacts of higher rate base)base and higher allowed electric distribution ROE due to an increase in treasury rates). See Note 14 —15 - Commitments and Contingencies of the Combined Notes to the Consolidated Financial Statements for additional information related to the Deferred Prosecution Agreement.
The changes in Operating revenues consisted of the following:
 Three Months Ended
June 30, 2020		 Six Months Ended
June 30, 2020
 Increase (Decrease) Increase (Decrease)
Electric distribution$—
 $21
Transmission(4) (12)
Energy efficiency6
 19
 2
 28
Regulatory required programs64
 69
Total increase$66
 $97

159

Three Months Ended
June 30, 2021		Six Months Ended
June 30, 2021
IncreaseIncrease
Distribution$52 $73 
Transmission1 4 
Energy efficiency12 24 
Other— 12 
65 113 
Regulatory required programs35 83 
Total increase$100 $196 
Revenue Decoupling. The demand for electricity is affected by weather conditions and customer usage. Operating revenues are not impacted by abnormal weather, usage per customer or number of customers as a result of a change to the electric distribution formula rate pursuant torevenue decoupling mechanisms as allowed by FEJA.
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
164




ComEd
in the underlying costs, (e.g., severe weather and storm restoration), investments being recovered, and allowed ROE. Electric distribution revenue increased for the three months ended June 30, 2020 compared to the same period in 2019 remained relatively consistent. Electric distribution revenue increased during theand six months ended June 30, 20202021 as compared to the same period in 2019, primarily2020, due to the impact of higher rate base and higher fully recoverable costs, offset by lower allowed ROE due to a decreasean increase in treasury rates. See Note 2 — Regulatory Mattersrates and the impact of the Combined Notes to Consolidated Financial Statements for additional information.a higher rate base.
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. Transmission revenue decreased for the three and six months ended June 30, 2020 as compared to the same period in 2019, primarily due to the impact of decreased peak load partially offset by higher fully recoverable costs. See Note 2 — Regulatory Matters of the Combined Notes to Consolidated Financial Statements for additional information.
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. UnderUnder FEJA, energy efficiency revenue varies from year to year based upon fluctuationsfluctuations in the underlying costs, investments being recovered, and allowed ROE. Energy efficiency revenue increased during the three and six months ended June 30, 20202021 as compared to the same period in 2019,2020, primarily due to the increased regulatory asset amortization. See Depreciationamortization, which is fully recoverable.
Other Revenue primarily includes assistance provided to other utilities through mutual assistance programs. Other revenue remained the same for the three months ended June 30, 2021 and amortization expense discussions below and Note 2 — Regulatory Matters ofincreased for the Combined Notessix months ended June 30, 2021 as compared to Consolidated Financial Statements for additional information.the same period in 2020, which 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 and fuel 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 but impactas 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 either acts as the billing agent or the competitive supplier separately bills its own customers, and therefore ComEd does not record Operating revenues or Purchased power expense related to suppliedthe electricity. Drivers of Operating revenues relatedFor 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 participationtherefore records equal and offsetting amounts in customer choice programs are fully offset by their impact onOperating revenues and Purchased power expense related to the electricity, ZECs, and fuel expense. ComEd recovers electricity, ZEC and REC procurement costs from customers without mark-up.RECs.
See Note 45 — Segment Information of the Combined Notes to Consolidated Financial Statements for the presentation of ComEd's revenue disaggregation.
The increase of $57$36 million and $59of $74 million for the three and six months ended June 30, 20202021 compared to the same period in 2019,2020, respectively, in Purchased power expense is offset in Operating revenues as part of regulatory required programs.

165

160


ComEd

The changes in Operating and maintenance expense consisted of the following:
Three Months Ended
June 30, 2020		 Six Months Ended
June 30, 2020		Three Months Ended
June 30, 2021		Six Months Ended
June 30, 2021
Increase (Decrease) (Decrease) Increase(Decrease) Increase(Decrease) Increase
Deferred Prosecution Agreement payments(a)
$200
 $200
Deferred Prosecution Agreement payments(a)
$(200)$(200)
Storm-related costs9
 2
Storm-related costs(5)(14)
BSC costs6
 16
Pension and non-pension postretirement benefits expense2
 4
Pension and non-pension postretirement benefits expense1 2 
Labor, other benefits, contracting and materials1
 (9)Labor, other benefits, contracting and materials2 10 
BSC costsBSC costs5 5 
Other(b)
10
 13
Other(b)
(17)(23)
228
 226
(214)(220)
Regulatory required programs(c)
3
 1
Regulatory required programs(c)
1 6 
Total increase$231
 $227
Total decreaseTotal decrease$(213)$(214)
__________
(a)
See Note 14
(a)See Note 15 - Commitments and Contingencies of the Combined Notes to the Consolidated Financial Statements for additional information.
(b)Primarily reflects the absence of an impairment charge related to acquisition of transmission assets in 2020.
(c)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.— Commitments and Contingencies of the Combined Notes to Consolidated Financial Statements for additional information.
(b)Primarily reflects impairment charge related to acquisition of transmission assets.
(c)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. During the three and six months ended June 30, 2020, ComEd recorded a net increase in credit losses account due to the timing of regulatory cost recovery. An equal and offsetting amount has been recognized in Operating revenues for the period presented.

The changes in Depreciation and amortization expense consisted of the following:
Three Months Ended
June 30, 2021		Six Months Ended
June 30, 2021
IncreaseIncrease
Depreciation and amortization(a)
$10 $22 
Regulatory asset amortization(b)
12 20 
Total increase$22 $42 
 Three Months Ended
June 30, 2020		 Six Months Ended
June 30, 2020
 Increase Increase
Depreciation and amortization(a)
$14
 $28
Regulatory asset amortization(b)
3
 11
Total increase$17
 $39
__________
_________(a)Reflects ongoing capital expenditures.
(a)Reflects ongoing capital expenditures.
(b)Includes amortization of ComEd's energy efficiency formula rate regulatory asset.
(b)Includes amortization of ComEd's energy efficiency formula rate regulatory asset and amortization related to the August 2020 storm regulatory asset.
Effective income tax raterates werewere 19.3% and (306.7)% and 19.8% for the three months ended June 30, 20202021 and 2019,2020, respectively, and 43.4%17.9% and 19.8%43.4% for the six months ended June 30, 2021 and 2020, and 2019.respectively. See Note 910 — Income Taxes of the Combined Notes to Consolidated Financial Statements for additional information regarding the components of the effective income tax rates.

166

161



Results of Operations — PECO
Three Months Ended
June 30,		 
Favorable
(Unfavorable)
Variance
 Six Months Ended
June 30,		 Favorable
(Unfavorable)
Variance		Three Months Ended
June 30,		Favorable
(Unfavorable)
Variance		Six Months Ended
June 30,		Favorable
(Unfavorable)
Variance
2020 2019 2020 2019 2021202020212020
Operating revenues$681
 $655
 $26
 $1,493
 $1,554
 $(61)Operating revenues$693 $681 $12 $1,582 $1,493 $89 
Operating expenses           Operating expenses
Purchased power and fuel expense

216
 191
 (25) 499
 520
 21
Purchased power and fuel expense207 216 9 523 499 (24)
Operating and maintenance275
 199
 (76) 492
 424
 (68)Operating and maintenance209 275 66 443 492 49 
Depreciation and amortization88
 83
 (5) 173
 164
 (9)Depreciation and amortization87 88 1 173 173 — 
Taxes other than income taxes39
 37
 (2) 78
 79
 1
Taxes other than income taxes49 39 (10)92 78 (14)
Total operating expenses618
 510
 (108) 1,242
 1,187
 (55)Total operating expenses552 618 66 1,231 1,242 11 
Operating income63
 145
 (82) 251
 367
 (116)Operating income141 63 78 351 251 100 
Other income and (deductions)           Other income and (deductions)
Interest expense, net(36) (33) (3) (71) (67) (4)Interest expense, net(42)(36)(6)(80)(71)(9)
Other, net5
 3
 2
 7
 7
 —
Other, net7 5 2 12 7 5 
Total other income and (deductions)(31) (30) (1) (64) (60) (4)Total other income and (deductions)(35)(31)(4)(68)(64)(4)
Income before income taxes32
 115
 (83) 187
 307
 (120)Income before income taxes106 32 74 283 187 96 
Income taxes(7) 13
 20
 9
 37
 28
Income taxes2 (7)(9)12 9 (3)
Net income$39
 $102
 $(63) $178
 $270
 $(92)Net income$104 $39 $65 $271 $178 $93 
Three Months Ended June 30, 20202021 Compared to Three Months Ended June 30, 2019. 2020. Net income decreasedincreased by $63$65 million primarily reflects the absence of costs in 2021 due to higher storm costs due tothe June 2020 storms and an increase in credit loss expense including the impacts of COVID-19, partially offset by favorable weather conditions.both gas and electric volume.
Six Months Ended June 30, 20202021 Compared to Six Months Ended June 30, 2019.2020. Net income decreasedincreased by $92$93 million primarily reflects the absence of costs in 2021 due to unfavorable weather conditions, higher storm costs due tothe June 2020 storms, favorable weather, and an increase in credit loss expense including the impacts of COVID-19.primarily electric volume.
The changes in Operating revenues consisted of the following:
Three Months Ended
June 30, 2020		 Six Months Ended
June 30, 2020		Three Months Ended
June 30, 2021		Six Months Ended
June 30, 2021
Increase (Decrease) Increase (Decrease)Increase (Decrease)Increase (Decrease)
Electric Gas Total Electric Gas TotalElectricGasTotalElectricGasTotal
Weather$3
 $8
 $11
 $(23) $(13) $(36)Weather$3 $(5)$(2)$24 $12 $36 
Volume3
 (3) —
 (4) (6) (10)Volume6 5 11 17 6 23 
Pricing(2) 1
 (1) 6
 5
 11
Pricing4 (4)— (3)(4)(7)
Transmission—
 —
 —
 2
 —
 2
Transmission2 — 2 3 — 3 
Other(4) —
 (4) (4) (1) (5)Other— — — (1)— (1)
—
 6
 6
 (23) (15) (38)15 (4)11 40 14 54 
Regulatory required programs20
 —
 20
 27
 (50) (23)Regulatory required programs10 (9)1 41 (6)35 
Total increase (decrease)$20
 $6
 $26
 $4
 $(65) $(61)
Total increaseTotal increase$25 $(13)$12 $81 $8 $89 
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. During the three months ended June 30, 20202021 compared to the same period in 2019,2020, Operating revenues related to weather remained relatively consistent. During the six months ended June 30, 2021 compared to the same period in 2020, revenues related to weather increased by the impact of favorable weather conditions in PECO's service territory. During the six months ended

162

June 30, 2020 compared to the same period in 2019, Operating revenues related to weather decreased by 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-daysdegree-
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PECO
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 three and six months ended June 30, 20202021 compared to the same period in 20192020 and normal weather consisted of the following:
Heating and Cooling Degree-Days  Normal % ChangeHeating and Cooling Degree-DaysNormal% Change
Three Months Ended June 30,2020 2019From 2019 2020 vs. NormalThree Months Ended
June 30,		20212020From 20202021 vs. Normal
Heating Degree-Days568
 270 432 110.4 % 31.5 %Heating Degree-Days404568423(28.9)%(4.5)%
Cooling Degree-Days376
 425 386 (11.5)% (2.6)%Cooling Degree-Days41837638811.2 %7.7 %
     Normal% Change
Six Months Ended June 30,     Six Months Ended June 30,20212020From 20202021 vs. Normal
Heating Degree-Days2,557
 2,702 2,850 (5.4)% (10.3)%Heating Degree-Days2,706 2,5572,8405.8 %(4.7)%
Cooling Degree-Days376
 427 387 (11.9)% (2.8)%Cooling Degree-Days423 37638912.5 %8.7 %
Volume. Electric volume, exclusive of the effects of weather, for the three and six months ended June 30, 20202021, compared to the same period in 2019,2020, increased on a net basis due to an increase in overall usage for residential customers partially offset by a decrease for commercial and industrial customers due to COVID-19.  Residential volumes were further increased by customer growth.  Electric volume, exclusive of the effects of weather, for the six months ended June 30, 2020 compared to the same period in 2019, decreased on a net basis due to a decrease in usage for commercial and industrial customers partially offset by an increase in usage for residential customers due to COVID-19. Volumes further decreased as a result of the impact of energy efficiency initiatives across all customer classes partially offset by increases due to customer growth. Natural gas volume for the three and six months ended June 30, 2020,2021 compared to the same period in 2019, decreased on a net basis2020, increased due to a decrease in usage for the commercial and industrial natural gas classes partially offset by increased usage for the residential natural gas class due to COVID-19.retail load growth.
Electric Retail Deliveries to Customers (in GWhs)Three Months Ended
June 30,		% Change
Weather -
Normal
% Change(b)
Six Months Ended June 30,% Change
Weather -
Normal
% Change(b)
2021202020212020
Residential3,1163,143(0.9)%(1.9)%6,8836,3977.6 %2.5 %
Small commercial & industrial1,7581,57111.9 %10.8 %3,6393,4764.7 %1.9 %
Large commercial & industrial3,4753,1819.2 %8.3 %6,7476,6022.2 %1.4 %
Public authorities & electric railroads1211128.0 %8.2 %2702632.7 %2.7 %
Total electric retail deliveries(a)
8,4708,0075.8 %4.8 %17,53916,7384.8 %1.9 %
As of June 30,
Electric Retail Deliveries to Customers (in GWhs)Three Months Ended
June 30,		 % Change 
Weather -
Normal
% Change(b)
 Six Months Ended June 30, % Change 
Weather -
Normal
% Change(b)
2020 2019 2020 2019 
Number of Electric CustomersNumber of Electric Customers20212020
Residential3,143 2,821 11.4 % 8.4 % 6,397 6,462 (1.0)% 3.3 %Residential1,513,4561,501,259
Small commercial & industrial1,571 1,823 (13.8)% (12.9)% 3,476 3,889 (10.6)% (7.7)%Small commercial & industrial154,842154,016
Large commercial & industrial3,181 3,769 (15.6)% (14.7)% 6,602 7,340 (10.1)% (9.2)%Large commercial & industrial3,1083,096
Public authorities & electric railroads112 182 (38.5)% (38.5)% 263 377 (30.2)% (30.4)%Public authorities & electric railroads10,28510,119
Total electric retail deliveries(a)
8,007 8,595 (6.8)% (7.1)% 16,738 18,068 (7.4)% (4.8)%
TotalTotal1,681,6911,668,490
__________
(a)Reflects delivery volumes 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.
Natural Gas Deliveries to Customers (in mmcf)Three Months Ended
June 30,		% Change
Weather -
Normal
% Change(b)
Six Months Ended
June 30,		% Change
Weather -
Normal
% Change(b)
2021202020212020
Residential5,0276,464(22.2)%(9.7)%25,70123,7468.2 %0.2 %
Small commercial & industrial3,1212,05451.9 %76.9 %13,29110,86322.4 %10.7 %
Large commercial & industrial23(33.3)%27.1 %912(25.0)%11.1 %
Transportation5,4685,1486.2 %8.6 %13,11812,2836.8 %3.6 %
Total natural gas retail deliveries(a)
13,61813,669(0.4)%9.9 %52,11946,90411.1 %3.6 %
168
 As of June 30,
Number of Electric Customers2020 2019
Residential1,501,259 1,486,973
Small commercial & industrial154,016 153,387
Large commercial & industrial3,096 3,105
Public authorities & electric railroads10,119 9,733
Total1,668,490 1,653,198


163

PECO

 As of June 30,
Number of Natural Gas Customers20212020
Residential494,895489,201
Small commercial & industrial44,45044,189
Large commercial & industrial66
Transportation677719
Total540,028534,115
_________
(a)Reflects delivery volumes 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.
__________
Natural Gas Deliveries to Customers (in mmcf)Three Months Ended
June 30,		 % Change 
Weather -
Normal
% Change(b)
 Six Months Ended
June 30,		 % Change 
Weather -
Normal
% Change(b)
2020 2019  2020 2019 
Residential6,464 3,351 92.9 % 9.3 % 23,746 24,569 (3.3)% 1.2 %
Small commercial & industrial2,054 4,040 (49.2)% (46.0)% 10,863 14,684 (26.0)% (10.8)%
Large commercial & industrial3 17 (82.4)% (30.0)% 12 36 (66.7)% (18.0)%
Transportation5,148 5,719 (10.0)% (16.0)% 12,283 13,692 (10.3)% (8.0)%
Total natural gas retail deliveries(a)
13,669 13,127 4.1 % (13.7)% 46,904 52,981 (11.5)% (4.3)%
(a)Reflects delivery volumes from customers purchasing natural gas directly from PECO and customers purchasing natural gas from a competitive natural gas supplier as all customers are assessed distribution charges.
(b)Reflects the change in delivery volumes assuming normalized weather based on the historical 30-year average.
 As of June 30,
Number of Natural Gas Customers2020 2019
Residential489,201 483,657
Small commercial & industrial44,189 43,953
Large commercial & industrial6 2
Transportation719 737
Total534,115 528,349
_________
(a)Reflects delivery volumes from customers purchasing natural gas directly from PECO and customers purchasing natural gas from a competitive natural gas supplier as all customers are assessed distribution charges.
(b)Reflects the change in delivery volumes assuming normalized weather based on the historical 30-year average.
Pricing for the three months ended June 30, 20202021 compared to the same period in 20192020 remained relatively consistent. Pricing for the six months ended June 30, 20202021 compared to the same period in 2019 increased2020 decreased primarily due to higherlower overall effective electric rates due to decreasedincreased usage across all major customer classes. Additionally, the increase represents revenue from higher natural gas distribution rates.
Transmission Revenue. Under a FERC approved formula, transmission revenue varies from year to year based upon fluctuations in the underlying costs and capital investments being recovered. Transmission revenue for the three and six months ended June 30, 2020 compared to the same period in 2019 remained relatively consistent.
Regulatory Required Programs represents revenues collected under approved riders to recover costs incurred for regulatory programs such as energy efficiency, PGC, and the GSA. The riders are designed to provide full and current cost recovery as well as a return. The costs of these programs are included in Purchased power and fuel expense, Operating and maintenance expense, Depreciation and amortization expense, and Income taxes. Customers have the choice to purchase electricity and natural gas from competitive electric generation and natural gas suppliers. Customer choice programs do not impact the volume of deliveries but impactas PECO 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 or natural gas from competitive suppliers, PECO either acts as the billing agent or the competitive supplier separately bills its own customers and therefore PECO does not record Operating revenues related to supplied electricity and natural gas. Drivers of Operating revenues related to commodity and REC procurement costs and participation in customer choice programs are fully offset by their impact onor Purchased power and fuel expense.expense related to the electricity and/or natural gas. For customers that choose to purchase electric generation or natural gas from PECO, recoversPECO is permitted to recover the electricity, natural gas, and REC procurement costs from customers without mark-up.mark-up and therefore records equal and offsetting amounts in Operating revenues and Purchased power and fuel expense related to the electricity, natural gas, and RECs.
Other revenue which primarily includes revenue related to late payment charges. Other revenues decreased for the three and six months ended June 30, 2020,2021 compared to the same period in 2019, as PECO temporarily suspended customer disconnections for non-payment and temporarily ceased new late fees for all customers and restored service to customers upon request who were disconnected in the last twelve months.2020, remained relatively consistent.
See Note 4—5 — Segment Information of the Combined Notes to Consolidated Financial Statements for the presentation of PECO's revenue disaggregation.

164

The$9 million and the increase of $25 million and decrease of $21$24 million for the three and six months ended June 30, 20202021 compared to the same period in 2019,2020, respectively, in Purchased power and fuel expense is fullypartially offset in Operating revenues as part of regulatory required programs.
169




PECO
The changes in Operating and maintenance expense consisted of the following:
Three Months Ended
June 30, 2021		Six Months Ended
June 30, 2021
Increase (Decrease)Increase (Decrease)
Storm-related costs(a)
Storm-related costs(a)
$(65)$(59)
Credit loss expenseCredit loss expense(19)(12)
Regulatory Required ProgramsRegulatory Required Programs1 (1)
BSC costsBSC costs5 7 
Labor, other benefits, contracting and materialsLabor, other benefits, contracting and materials13 22 
OtherOther(1)(6)
Three Months Ended
June 30, 2020		 Six Months Ended
June 30, 2020
Increase (Decrease) (Decrease) Increase
Storm-related costs(a)
$61
 $53
Credit loss expense(b)
18
 19
Labor, other benefits, contracting and materials1
 (5)
Pension and non-pension postretirement benefits expense(1) (1)
Other(3) 2
Total increase$76
 $68
Total increase$(66)$(49)
__________
(a) Reflects increased stormPrimarily reflects the absence of costs in 2021 due to the June 2020 storms.
(b) Increased credit loss expense including impacts from COVID-19.

The changes in Depreciation and amortization expense consisted of the following:
Three Months Ended June 30, 2020 Six Months Ended
June 30, 2020		Three Months Ended June 30, 2021Six Months Ended
June 30, 2021
Increase Increase (Decrease)Increase (Decrease)Increase (Decrease)
Depreciation and amortization(a)
$5
 $10
Depreciation and amortization(a)
$(2)$(6)
Regulatory asset amortization—
 (1)Regulatory asset amortization3 6 
Total increase$5
 $9
Total increase$1 $— 
__________
(a)Depreciation and amortization increased primarily due to ongoing capital expenditures.
(a)Depreciation and amortization increased primarily due to ongoing capital expenditures.
Interest expense, net increased $6 million and $9 million for the three and six months ended June 30, 2021 compared to the same period in 2020, respectively, primarily due to the issuance of debt in March 2021 and June 2020.
Effective Income Tax Ratesincome tax rates were 1.9% and (21.9)% and 11.3% for the three months ended June 30, 20202021 and 2019,2020 respectively, and 4.8%4.2% and 12.1%4.8% for the six months ended June 30, 2021 and 2020, and 2019.respectively. See Note 910 — Income Taxes of the Combined Notes to Consolidated Financial Statements for additional information regarding the components of the effective income tax rates.

170

165



Results of Operations — BGE
Three Months Ended
June 30,		 
(Unfavorable)
Favorable
Variance
 Six Months Ended
June 30,		 
(Unfavorable)
Favorable
Variance
Three Months Ended
June 30,		Favorable
(Unfavorable)
Variance		Six Months Ended
June 30,		Favorable
(Unfavorable)
Variance
2020 2019 2020 2019 2021202020212020
Operating revenues$616
 $649
 $(33) $1,554
 $1,625
 $(71)Operating revenues$682 $616 $66 $1,656 $1,554 $102 
Operating expenses

 

 

      Operating expenses
Purchased power and fuel expense194
 208
 14
 483
 570
 87
Purchased power and fuel expense219 194 (25)550 483 (67)
Operating and maintenance187
 182
 (5) 376
 372
 (4)Operating and maintenance193 187 (6)390 376 (14)
Depreciation and amortization129
 117
 (12) 272
 252
 (20)Depreciation and amortization141 129 (12)293 272 (21)
Taxes other than income taxes63
 62
 (1) 132
 131
 (1)Taxes other than income taxes67 63 (4)139 132 (7)
Total operating expenses573
 569
 (4) 1,263
 1,325
 62
Total operating expenses620 573 (47)1,372 1,263 (109)
Operating income43
 80
 (37) 291
 300
 (9)Operating income62 43 19 284 291 (7)
Other income and (deductions)           Other income and (deductions)
Interest expense, net(32) (29) (3) (64) (58) (6)Interest expense, net(34)(32)(2)(67)(64)(3)
Other, net6
 5
 1
 10
 11
 (1)Other, net9 6 3 16 10 6 
Total other income and (deductions)(26) (24) (2) (54) (47) (7)Total other income and (deductions)(25)(26)1 (51)(54)3 
Income before income taxes17
 56
 (39) 237
 253
 (16)Income before income taxes37 17 20 233 237 (4)
Income taxes(22) 11
 33
 18
 47
 29
Income taxes(8)(22)(14)(21)18 39 
Net income$39
 $45
 $(6) $219
 $206
 $13
Net income$45 $39 $6 $254 $219 $35 
Three Months Ended June 30, 20202021 Compared to Three Months Ended June 30, 2019. Net income2020. remained relatively consistent.Net Income increased $6 million primarily due to the favorable impacts of the multi-year plan. See Note 3 — Regulatory Matters of the Combined Notes to Consolidated Financial Statements for additional information on the three-year electric and natural gas distribution multi-year plan.
Six Months Ended June 30, 20202021 Compared to Six Months Ended June 30, 2019.2020. Net incomeincome increased by $13$35 million primarily due to higherfavorable impacts of the multi-year plan. See Note 3 — Regulatory Matters of the Combined Notes to Consolidated Financial Statements for additional information on the three-year electric and natural gas and electric distribution rates that became effective December 2019.multi-year plan.
The changes in Operating revenues consisted of the following:
Three Months Ended
June 30, 2020		 Six Months Ended
June 30, 2020		Three Months Ended
June 30, 2021		Six Months Ended
June 30, 2021
Increase (Decrease) Increase (Decrease)Increase (Decrease)Increase (Decrease)
Electric Gas Total Electric Gas TotalElectricGasTotalElectricGasTotal
Distribution$1
 $6
 $7
 $10
 $35
 $45
Distribution$5 $3 $8 $6 $1 $7 
Transmission(17) —
 (17) (11) —
 (11)Transmission26 — 26 30 — 30 
Other(5) (3) (8) (2) (4) (6)Other5 2 7 (2)1 (1)
(21) 3
 (18) (3) 31
 28
36 5 41 34 2 36 
Regulatory required programs(14) (1) (15) (77) (22) (99)Regulatory required programs17 8 25 40 26 66 
Total (decrease) increase$(35) $2
 $(33) $(80) $9
 $(71)
Total increaseTotal increase$53 $13 $66 $74 $28 $102 
Revenue Decoupling. The demand for electricity and natural gas is affected by weather and customer usage. However, Operating revenues are not impacted by abnormal weather or usage per customer as a result of a bill stabilization adjustment (BSA) that provides for a fixed distribution charge per customer by customer class. While Operating revenues are not impacted by abnormal weather or usage per customer, they are impacted by changes in the number of customers.

171

166


BGE


 As of June 30,
Number of Electric Customers20212020
Residential1,192,135 1,185,718 
Small commercial & industrial114,682 114,118 
Large commercial & industrial12,528 12,416 
Public authorities & electric railroads267 264 
Total1,319,612 1,312,516 
 As of June 30,
Number of Electric Customers2020 2019
Residential1,185,718
 1,171,815
Small commercial & industrial114,118
 113,982
Large commercial & industrial12,416
 12,275
Public authorities & electric railroads264
 264
Total1,312,516
 1,298,336
As of June 30,As of June 30,
Number of Natural Gas Customers2020 2019Number of Natural Gas Customers20212020
Residential643,745
 634,939
Residential647,534 643,745 
Small commercial & industrial38,255
 38,164
Small commercial & industrial38,223 38,255 
Large commercial & industrial6,079
 5,991
Large commercial & industrial6,132 6,079 
Total688,079
 679,094
Total691,889 688,079 
Distribution Revenueincreased for the three and six months ended June 30, 2020, 2021,compared to the same period in 2019, primarily 2020, due to the impact of higher natural gas and electric distribution rates that became effective in December 2019. See Note 2 — Regulatory Matters of the Combined Notes to Consolidated Financial Statements for additional information.customer growth.
Transmission Revenue. Under a FERC approvedFERC-approved formula, transmission revenue varies from year to year based upon fluctuations in the underlying costs and 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.recovered. Transmission revenue decreasedincreased for the three and six months ended June 30, 2020,2021, compared to the same period in 2019,2020, primarily due to the reduction in revenue in 2020 due to the settlement agreement of ongoing transmission-relatedtransmission related income tax regulatory liabilities. See Note 2 — Regulatory Matters of the Combined Notes to Consolidated Financial Statements for additional information.
Other revenueRevenue includes revenue related to late payment charges, mutual assistance, administrative charges, off-system sales, and late payment charges.service application fees. Other revenues decreasedincreased for the three and six months ended June 30, 2020,2021, compared to the same period in 2019,2020, as BGE had temporarily suspended customer disconnections for non-payment and temporarily ceased new late fees for all customers and restored servicein 2020 which has resumed in 2021. Other revenues remained relatively consistent for the six months ended June 30, 2021 compared to customers upon request who were disconnectedthe same period in the last twelve months.2020.
Regulatory Required Programs represent revenues collected under approved riders to recover costs incurred for regulatory programs such as conservation, demand response, STRIDE, and the POLR mechanism.mechanism. The riders are designed to provide full and current cost recovery, as well as a return in certain instances. The costs of these programs are included in Purchased power and fuel expense, Operating and maintenance expense, Depreciation and amortization expense, and Taxes other than income taxes. Customers have the choice to purchase electricity and natural gas from competitive electric generation and natural gas suppliers. Customer choice programs do not impact the volume of deliveries but impactas BGE 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 or natural gas from competitive suppliers, BGE either acts as the billing agent or the competitive supplier separately bills its own customers, and therefore BGE does not record Operating revenues or Purchased power and fuel expense related to suppliedthe electricity and/or natural gas. For customers that choose to purchase electric generation or natural gas from BGE, BGE is permitted to recover the electricity and natural gas. Drivers ofgas procurement costs from customers and therefore records the amounts related to the electricity and/or natural gas in Operating revenues related to commodity procurement costs and participation in customer choice programs are fully offset by their impact on Purchased power and fuel expense. BGE recovers electricity and natural gas and procurement costs from customers with a slight mark-up.
See Note 45 — Segment Information of the Combined Notes to the Consolidated Financial Statements for the presentation of BGE's revenue disaggregation.
The decreaseThe increase of $14$25 million and decrease of $87$67 million for the three and six months ended June 30, 20202021 compared to the same period in 2019, respectively,2020, in Purchased power and fuel expense is fully offset in Operating revenues as part of regulatory required programs.


167
172




BGE


The changes in Operating and maintenance expense consisted of the following:
Three Months Ended
June 30, 2021		Six Months Ended
June 30, 2021
Three Months Ended
June 30, 2020		 Six Months Ended
June 30, 2020		 Increase (Decrease) Increase (Decrease)
Labor, other benefits, contracting, and materialsLabor, other benefits, contracting, and materials$3 $3 
Storm-related costsStorm-related costs1 7 
Increase (Decrease) Increase (Decrease)
BSC costsBSC costs4 6 
Credit loss expense$7
 $6
Credit loss expense(4)(6)
BSC costs

1
 4
Labor, other benefits, contracting and materials1
 3
Storm-related costs

—
 (5)
Pension and non-pension postretirement benefits expense(1) (1)
Other(2) (2)Other1 2 
6
 5
5 12 
Regulatory required programs(1) (1)Regulatory required programs1 2 
Total increase$5
 $4
Total increase$6 $14 
The changes in Depreciation and amortization expense consisted of the following:
Three Months Ended
June 30, 2021		Six Months Ended
June 30, 2021
IncreaseIncrease
Depreciation and amortization(a)
$10 $19 
Regulatory asset amortization2 2 
Total increase$12 $21 
 Three Months Ended
June 30, 2020		 Six Months Ended
June 30, 2020
 Increase Increase (Decrease)
Depreciation and amortization(a)
$9
 $21
Regulatory required programs3
 (1)
Total increase$12
 $20
__________
_________(a)Depreciation and amortization increased primarily due to ongoing capital expenditures.
(a)Depreciation and amortization increased primarily due to ongoing capital expenditures.
Effective income tax rates were (129.4)(21.6)% and 19.6%(129.4)% for the three months ended June 30, 20202021 and 2019,2020, respectively, and (9.0)% and 7.6% and 18.6% forfor the six months ended June 30, 2021 and 2020, and 2019.respectively. The change is primarily relateddue to the multi-year plan which resulted in the acceleration of certain income tax benefits and the April 24, 2020 settlement agreement of ongoing transmission-relatedtransmission related income tax regulatory liabilities. See Note 23 — Regulatory Matters of the Combined Notes to Consolidated Financial Statements for additional information on the three-year electric and natural gas distribution multi-year plan, Note 3 — Regulatory Matters of the 2020 Exelon Form 10-K for additional information on the April 24, 2020 settlement agreement, and Note 910 — Income Taxes of the Combined Notes to Consolidated Financial Statements for additional information regarding the components of the effective income tax rates.

173

168



Results of Operations — PHI
PHI’s Results of Operations include the results of its three reportable segments, Pepco, DPL, and ACE. PHI also has a business services subsidiary, PHISCO, which provides a variety of support services and the costs are directly charged or allocated to the applicable subsidiaries. Additionally, the results of PHI’s corporate operations include interest costs from various financing activities. All material intercompany accounts and transactions have been eliminated in consolidation. The following table sets forth PHI's GAAP consolidated Net Income by Registrant for the three and six months ended June 30, 2021 compared to the same period in 2020. See the Results of Operations for Pepco, DPL, and ACE for additional information.
Three Months Ended
June 30,		 (Unfavorable)Favorable Variance Six Months Ended
June 30,		 (Unfavorable)Favorable VarianceThree Months Ended
June 30,		Favorable (Unfavorable) VarianceSix Months Ended
June 30,		Favorable (Unfavorable) Variance
2020 2019 2020 2019 2021202020212020
PHI$94
 $106
 $(12) $202
 $223
 $(21)PHI$141 $94 $47 $269 $202 $67 
Pepco57
 64
 (7) 109
 119
 (10)Pepco75 57 18 134 109 25 
DPL19
 30
 (11) 64
 83
 (19)DPL30 19 11 86 64 22 
ACE18
 14
 4
 31
 24
 7
ACE37 18 19 51 31 20 
Other(a)
—
 (2) 2
 (2) (3) 1
Other(a)
(1)— (1)(2)(2)— 
_________
(a)Primarily includes eliminating and consolidating adjustments, PHI's corporate operations, shared service entities and other financing and investing activities.
(a)Primarily includes eliminating and consolidating adjustments, PHI's corporate operations, shared service entities, and other financing and investing activities.
Three Months Ended June 30, 20202021 Compared to Three Months Ended June 30, 2019.2020. Net Income decreasedincreased by $12$47 million primarily due to higher electric distribution rates at DPL, higher transmission revenues due to an increase in capital investments and higher distribution revenues due to an increase in volume in ACE's service territory, customer growth at Pepco, and a decrease in credit loss expense including the impacts of COVID-19at Pepco and an increase in various expenses, partially offset by higher electric distribution rates primarily at ACE.DPL.
Six Months Ended June 30, 20202021 Compared to Six Months Ended June 30, 2019.2020. Net Income decreasedincreased by $21$67 million primarily due higher electric distribution rates at DPL, favorable weather conditions in DPL's Delaware and ACE's service territories, higher transmission revenues due to an increase in credit loss expense including the impacts of COVID-19, unfavorable weather conditionscapital investments and higher distribution revenues due to an increase in volume in ACE's service territory, customer growth at Pepco, and an increasea decrease in various expenses, partially offset by higher electric distribution rates primarilycredit loss expense at ACE.Pepco and DPL.


169
174





Results of Operations — Pepco
Three Months Ended June 30, (Unfavorable) Favorable Variance Six Months Ended June 30, (Unfavorable) Favorable VarianceThree Months Ended June 30, Favorable (Unfavorable) VarianceSix Months Ended June 30,Favorable (Unfavorable) Variance
2020 2019 2020 2019 2021202020212020
Operating revenues$494
 $531
 $(37) $1,039
 $1,106
 $(67)Operating revenues$523 $494 $29 $1,076 $1,039 $37 
Operating expenses           Operating expenses
Purchased power expense138
 144
 6
 303
 331
 28
Purchased power expense133 138 5 298 303 5 
Operating and maintenance119
 111
 (8) 231
 230
 (1)Operating and maintenance113 119 6 221 231 10 
Depreciation and amortization92
 93
 1
 186
 186
 —
Depreciation and amortization96 92 (4)199 186 (13)
Taxes other than income taxes87
 90
 3
 179
 182
 3
Taxes other than income taxes87 87 — 177 179 2 
Total operating expenses436
 438
 2
 899
 929
 30
Total operating expenses429 436 7 895 899 4 
Operating income58
 93
 (35) 140
 177
 (37)Operating income94 58 36 181 140 41 
Other income and (deductions)    
      Other income and (deductions)
Interest expense, net(34) (34) —
 (68) (68) —
Interest expense, net(35)(34)(1)(69)(68)(1)
Other, net9
 7
 2
 18
 14
 4
Other, net13 9 4 25 18 7 
Total other income and (deductions)(25) (27) 2
 (50) (54) 4
Total other income and (deductions)(22)(25)3 (44)(50)6 
Income before income taxes33
 66
 (33) 90
 123
 (33)Income before income taxes72 33 39 137 90 47 
Income taxes(24) 2
 26
 (19) 4
 23
Income taxes(3)(24)(21)3 (19)(22)
Net income$57
 $64
 $(7) $109
 $119
 $(10)Net income$75 $57 $18 $134 $109 $25 
Three Months Ended June 30, 20202021 Compared to Three Months Ended June 30, 2019.2020. Net income decreased by $7increased $18 million primarily due to an increasecustomer growth, a decrease in credit loss expense, including the impacts of COVID-19.and decreases in various operating expenses.
Six Months Ended June 30, 20202021 Compared to Six Months Ended June 30, 2019.2020. Net income decreased by $10increased $25 million primarily due to an increasecustomer growth, a decrease in credit loss expense, including the impacts of COVID-19.and decreases in various operating expenses.
The changes in Operating revenues consisted of the following:
Three Months Ended
June 30, 2021		Six Months Ended June 30, 2021
Three Months Ended
June 30, 2020		 Six Months Ended June 30, 2020Increase (Decrease)Increase (Decrease)
Increase (Decrease) Increase (Decrease)
Volume$2
 $4
Distribution2
 3
Distribution$1 $4 
Transmission(26) (28)Transmission25 22 
Other(1) (2)Other(2)— 
(23) (23)24 26 
Regulatory required programs(14) (44)Regulatory required programs5 11 
Total decrease$(37) $(67)
Total increaseTotal increase$29 $37 
Revenue Decoupling. The demand for electricity is affected by weather and customer usage. However, Operating revenues from electric distribution in both Maryland and the District of Columbia are not impacted by abnormal weather or usage per customer as a result of a bill stabilization adjustment (BSA) that provides for a fixed distribution charge per customer by customer class. While Operating revenues are not impacted by abnormal weather or usage per customer, they are impacted by changes in the number of customers.

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Pepco


As of June 30,
Number of Electric Customers20212020
Residential837,744 825,000 
Small commercial & industrial53,669 53,809 
Large commercial & industrial22,579 22,467 
Public authorities & electric railroads178 168 
Total914,170 901,444 
Volume,Distribution Revenue exclusive of the effects of weather, remained relatively consistent for the three and six months ended June 30, 20202021 compared to the same period in 2019.
 As of June 30,
Number of Electric Customers2020 2019
Residential825,000
 811,985
Small commercial & industrial53,809
 54,194
Large commercial & industrial22,467
 22,155
Public authorities & electric railroads168
 155
Total901,444
 888,489
2020. Distribution Revenue revenue increased for the three and six months ended June 30, 20202021 compared to the same period in 2019,2020 due to higher electric distribution rates in Maryland that became effective in August 2019.customer growth.
Transmission Revenues.Revenues Under a FERC-approved formula, transmission revenue varies from year to year based upon fluctuations in the underlying costs and 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.recovered. Transmission revenues decreasedrevenue increased for the three and six months ended June 30, 20202021, compared to the same period in 2019,2020, primarily due to the reduction in revenue in 2020 due to the settlement agreement of ongoing transmission-relatedtransmission related income tax regulatory liabilities. See Note 2 — Regulatory Matters of the Combined Notes to Consolidated Financial Statements for additional information.
Other revenueincludes rental revenue, revenue related to late payment charges, mutual assistance revenues, and recoveries of other taxes. Other revenue decreased for the three and six months ended June 30, 2020, compared to the same period in 2019, as Pepco temporarily suspended customer disconnections for non-payment and temporarily ceased new late fees for all customers and restored services to customers upon request who were disconnected in the last twelve months.
Regulatory Required Programs represent revenues collected under approved riders to recover costs incurred for regulatory programs such as energy efficiency programs, DC PLUG, and SOS procurement and administrative costs. The riders are designed to provide full and current cost recovery as well as a return in certain instances. The costs of these programs are included in Purchased power expense, Operating and maintenance expense, Depreciation and amortization expense, and Taxes other than income taxes. Customers have the choice to purchase electricity from competitive electric generation suppliers. Customer choice programs do not impact the volume of deliveries, but impactas Pepco 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, Pepco either acts as the billing agent or the competitive supplier separately bills its own customers, and therefore Pepco does not record Operating revenues or Purchased power expense related to suppliedthe electricity. Drivers of Operating revenues relatedFor customers that choose to commoditypurchase electric generation from Pepco, Pepco is permitted to recover the electricity and REC procurement costs from customers and participationtherefore records the amounts related to the electricity and RECs in customer choice programs are fully offset by their impact onOperating revenues and Purchased power expense. Pepco recovers electricity and REC procurement costs from customers with a slight mark-up.
SeeSee Note 45 - Segment Information of the Combined Notes to Consolidated Financial Statements for the presentation of Pepco's revenue disaggregation.
The decrease of $6$5 million and $28 million for both the three and six months ended June 30, 20202021 compared to the same period 2019,in 2020, respectively, in Purchased power expense is fully 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:
Three Months Ended
June 30, 2021		Six Months Ended June 30, 2021
(Decrease) Increase(Decrease) Increase
Credit loss expense$(7)$(5)
Labor, other benefits, contracting and materials(5)(12)
Pension and non-pension postretirement benefits expense(1)(2)
BSC and PHISCO costs(1)— 
Other7 8 
(7)(11)
Regulatory required programs1 1 
Total decrease$(6)$(10)
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 Three Months Ended
June 30, 2020		 Six Months Ended June 30, 2020
 Increase (Decrease) Increase (Decrease)
Labor, other benefits, contracting and materials

$5
 $12
Credit loss expense8
 7
Storm-related costs1
 (1)
Pension and non-pension postretirement benefits expense(1) (3)
BSC and PHISCO costs—
 (3)
Expiration of lease arrangement(4) (8)
Other(3) (4)
 6
 —
Regulatory required programs2
 1
Total increase$8
 $1

Pepco

The changes in Depreciation and amortization expense consisted of the following:
Three Months Ended
June 30, 2020		 Six Months Ended June 30, 2020Three Months Ended
June 30, 2021		Six Months Ended June 30, 2021
Increase (Decrease) Increase (Decrease)Increase (Decrease)Increase (Decrease)
Depreciation and amortization(a)
$4
 $9
Depreciation and amortization(a)
$4 $8 
Regulatory asset amortizationRegulatory asset amortization(6)(5)
Regulatory required programs(5) (9)Regulatory required programs6 10 
Total decrease$(1) $—
Total increaseTotal increase$4 $13 
_________
(a)Depreciation and amortization increased primarily due to ongoing capital expenditures.

(a)Depreciation and amortization increased primarily due to ongoing capital expenditures.
Effective income tax rates were (72.7)(4.2)% and 3.0%(72.7)% for the three months ended June 30, 20202021 and 2019,2020, respectively, and 2.2% and (21.1)% and 3.3% for the six months ended June 30, 20202021 and 2019,2020, respectively. The change is primarily relateddue to the April 24, 2020 settlement agreement of ongoing transmission-relatedtransmission related income tax regulatory liabilities. See Note 23 — Regulatory Matters of the 2020 Exelon Form 10-K for additional information on the April 24, 2020 settlement agreement, and Note 910 — Income Taxes of the Combined Notes to Consolidated Financial Statements for additional information regarding the components of the change in effective income tax rates.

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Results of Operations — DPL
Three Months Ended June 30, (Unfavorable)Favorable Variance Six Months Ended June 30, (Unfavorable)Favorable VarianceThree Months Ended June 30,Favorable (Unfavorable) VarianceSix Months Ended June 30,Favorable (Unfavorable) Variance
2020 2019 2020 2019 2021202020212020
Operating revenues$267
 $287
 $(20) $617
 $667
 $(50)Operating revenues$298 $267 $31 $680 $617 $63 
Operating expenses

 

 

 

 

 

Operating expenses
Purchased power and fuel expense

107
 107
 —
 249
 271
 22
Purchased power and fuel expense108 107 (1)263 249 (14)
Operating and maintenance92
 77
 (15) 172
 160
 (12)Operating and maintenance80 92 12 164 172 8 
Depreciation and amortization47
 45
 (2) 94
 91
 (3)Depreciation and amortization51 47 (4)104 94 (10)
Taxes other than income taxes17
 14
 (3) 32
 28
 (4)Taxes other than income taxes16 17 1 33 32 (1)
Total operating expenses263
 243
 (20) 547
 550
 3
Total operating expenses255 263 8 564 547 (17)
Operating income4
 44
 (40) 70
 117
 (47)Operating income43 4 39 116 70 46 
Other income and (deductions)

 

 

 

 

 

Other income and (deductions)
Interest expense, net(15) (15) —
 (31) (30) (1)Interest expense, net(16)(15)(1)(30)(31)1 
Other, net2
 5
 (3) 5
 7
 (2)Other, net4 2 2 6 5 1 
Total other income and (deductions)(13) (10) (3) (26) (23) (3)Total other income and (deductions)(12)(13)1 (24)(26)2 
(Loss) income before income taxes(9)
34
 (43) 44

94
 (50)
Income (loss) before income taxesIncome (loss) before income taxes31 (9)40 92 44 48 
Income taxes(28) 4
 32
 (20) 11
 31
Income taxes1 (28)(29)6 (20)(26)
Net income$19
 $30
 $(11) $64
 $83
 $(19)Net income$30 $19 $11 $86 $64 $22 
Three Months Ended June 30, 20202021 Compared to Three Months Ended June 30, 20192020. Net income decreased byincreased $11 million primarily due to an increasehigher electric distribution rates and a decrease in credit loss expense including the impacts of COVID-19 and an increase in various expenses, partially offset by favorable weather conditions in DPL's Delaware service territory.expense.
Six Months Ended June 30, 20202021 Compared to Six Months Ended June 30, 20192020. Net income decreased by $19increased $22 million primarily due to an increasehigher electric distribution rates, favorable weather conditions at DPL's Delaware electric and natural gas service territories, and a decrease in credit loss expense including the impacts of COVID-19 and an increase in various expenses.expense.
The changes in Operating revenues consisted of the following:
Three Months Ended
June 30, 2020		 Six Months Ended
June 30, 2020		Three Months Ended
June 30, 2021		Six Months Ended
June 30, 2021
Increase (Decrease) Increase (Decrease)(Decrease) IncreaseIncrease (Decrease)
Electric Gas Total Electric Gas TotalElectricGasTotalElectricGasTotal
Weather$1
 $6
 $7
 $(5) $—
 $(5)Weather$— $(3)$(3)$4 $2 $6 
Volume—
 (3) (3) 1
 (3) (2)Volume2 (2)— 2 (2)— 
Distribution—
 —
 —
 2
 3
 5
Distribution4 1 5 9 1 10 
Transmission(25) —
 (25) (22) —
 (22)Transmission28 — 28 28 — 28 
Other(1) —
 (1) (2) (1) (3)Other— — — 1 — 1 
(25) 3
 (22) (26) (1) (27)34 (4)30 44 1 45 
Regulatory required programs(1) 3
 2
 (22) (1) (23)Regulatory required programs4 (3)1 18 — 18 
Total (decrease) increase$(26) $6
 $(20) $(48) $(2) $(50)
Total increase (decrease)Total increase (decrease)$38 $(7)$31 $62 $1 $63 
Revenue Decoupling. The demand for electricity is affected by weather and customer usage. However, Operating revenues from electric distribution in Maryland are not impacted by abnormal weather or usage per customer as a result of a bill stabilization adjustment (BSA) that provides for a fixed distribution charge per customer by customer class. While Operating revenues from electric distribution customers in Maryland are not impacted by abnormal weather or usage per customer, they are impacted by changes in the number of customers.

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Weather.The demand for electricity and natural gas in Delaware 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
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demand. During the three months ended June 30, 20202021 compared to the same period in 2019,2020, Operating revenues related to weather decreased due to the impact of unfavorable weather conditions in DPL's Delaware natural gas service territory. During the six months ended June 30, 2021 compared to the same period in 2020, Operating revenues related to weather increased due to the impact of favorable weather conditions in DPL's Delaware electric and natural gas service territory. During the six months ended June 30, 2020 compared to the same period in 2019, Operating revenues related to weather decreased due to the impact of unfavorable weather conditions in DPL's Delaware service territory.territories.
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 20-year period in DPL's Delaware electric service territory and a 30-year period in DPL's Delaware natural gas service territory. The changes in heating and cooling degree days in DPL’s Delaware service territory for the three and six months ended June 30, 20202021 compared to same period in 20192020 and normal weather consisted of the following:
Delaware Electric Service Territory% Change
Three Months Ended June 30,20212020Normal2021 vs. 20202021 vs. Normal
Heating Degree-Days480 606 471 (20.8)%1.9 %
Cooling Degree-Days361 299 334 20.7 %8.1 %
% Change
Six Months Ended June 30,20212020Normal2021 vs. 20202021 vs. Normal
Heating Degree-Days2,838 2,609 2,964 8.8 %(4.3)%
Cooling Degree-Days364 299 334 21.7 %9.0 %
Delaware Electric Service Territory    % Change
Three Months Ended June 30,2020 2019 Normal 2020 vs. 2019 2020 vs. Normal
Heating Degree-Days606
 300
 467
 102.0 % 29.8 %
Cooling Degree-Days299
 386
 334
 (22.5)% (10.5)%
          
     % Change
Six Months Ended June 30,2020 2019 Normal 2020 vs. 2019 2020 vs. Normal
Heating Degree-Days2,609
 2,822
 2,980
 (7.5)% (12.4)%
Cooling Degree-Days299
 386
 335
 (22.5)% (10.7)%
Delaware Natural Gas Service Territory    % ChangeDelaware Natural Gas Service Territory% Change
Three Months Ended June 30,2020 2019 Normal 2020 vs. 2019 2020 vs. NormalThree Months Ended June 30,20212020Normal2021 vs. 20202021 vs. Normal
Heating Degree-Days606
 300
 486
 102.0 % 24.7 %Heating Degree-Days480 606 490 (20.8)%(2.0)%
         
    % Change% Change
Six Months Ended June 30,2020 2019 Normal 2020 vs. 2019 2020 vs. NormalSix Months Ended June 30,20212020Normal2021 vs. 20202021 vs. Normal
Heating Degree-Days2,609
 2,822
 2,984
 (7.5)% (12.6)%Heating Degree-Days2,838 2,609 2,987 8.8 %(5.0)%
Volume, exclusive of the effects of weather, remained relatively consistent for the three and six months ended June 30, 20202021 compared to the same period in 2019.2020.
Electric Retail Deliveries to Delaware Customers (in GWhs)Three Months Ended
June 30,		% Change
Weather - Normal
% Change(b)
Six Months Ended
June 30,		% Change
Weather - Normal
% Change(b)
2021202020212020
Residential703 703 — %0.6 %1,557 1,446 7.7 %2.8 %
Small commercial & industrial357 274 30.3 %30.5 %699 570 22.6 %19.8 %
Large commercial & industrial810 810 — %(0.3)%1,499 1,633 (8.2)%(8.9)%
Public authorities & electric railroads10 9 11.1 %6.8 %19 17 11.8 %7.2 %
Total electric retail deliveries(a)
1,880 1,796 4.7 %4.8 %3,774 3,666 2.9 %0.4 %
As of June 30,
Number of Total Electric Customers (Maryland and Delaware)20212020
Residential475,061 470,788 
Small commercial & industrial62,880 61,958 
Large commercial & industrial1,213 1,402 
Public authorities & electric railroads607 612 
Total539,761 534,760 
_________
(a)Reflects delivery volumes from customers purchasing electricity directly from DPL and customers purchasing electricity from a competitive electric generation supplier as all customers are assessed distribution charges.
179
Electric Retail Deliveries to Delaware Customers (in GWhs)Three Months Ended
June 30,		 % Change 
Weather - Normal
% Change(b)
 Six Months Ended
June 30,		 % Change 
Weather - Normal
% Change(b)
2020 2019   2020 2019  
Residential703
 652
 7.8 % 4.6 % 1,446
 1,503
 (3.8)% 1.4 %
Small commercial & industrial274
 306
 (10.5)% (10.9)% 570
 626
 (8.9)% (6.4)%
Large commercial & industrial810
 866
 (6.5)% (6.1)% 1,633
 1,676
 (2.6)% (1.7)%
Public authorities & electric railroads9
 9
 — % 4.0 % 17
 17
 — % 3.0 %
Total electric retail deliveries(a)
1,796
 1,833
 (2.0)% (3.0)% 3,666
 3,822
 (4.1)% (1.2)%


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(b)Reflects the change in delivery volumes assuming normalized weather based on the historical 20-year average.
Natural Gas Retail Deliveries to Delaware Customers (in mmcf)Three Months Ended
June 30,		% Change
Weather - Normal
% Change(b)
Six Months Ended
June 30,		% Change
Weather - Normal
% Change(b)
2021202020212020
Residential713 1,168 (39.0)%(23.5)%5,107 4,815 6.1 %(2.0)%
Small commercial & industrial430 557 (22.8)%(6.2)%2,295 2,228 3.0 %(4.3)%
Large commercial & industrial393 411 (4.4)%(4.3)%853 863 (1.2)%(1.5)%
Transportation1,470 1,472 (0.1)%3.4 %3,694 3,580 3.2 %0.7 %
Total natural gas deliveries(a)
3,006 3,608 (16.7)%(6.8)%11,949 11,486 4.0 %(1.6)%
 As of June 30,
Number of Total Electric Customers (Maryland and Delaware)2020 2019
Residential470,788
 465,423
Small commercial & industrial61,958
 61,552
Large commercial & industrial1,402
 1,398
Public authorities & electric railroads612
 619
Total534,760
 528,992
_________
(a)Reflects delivery volumes from customers purchasing electricity directly from DPL 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 20-year average.
Natural Gas Retail Deliveries to Delaware Customers (in mmcf)Three Months Ended
June 30,		 % Change 
Weather - Normal
% Change(b)
 Six Months Ended
June 30,		 % Change 
Weather - Normal
% Change(b)
2020 2019   2020 2019  
Residential1,168
 741
 57.6 % (11.8)% 4,815
 5,348
 (10.0)% (2.8)%
Small commercial & industrial557
 566
 (1.6)% (35.0)% 2,228
 2,586
 (13.8)% (7.4)%
Large commercial & industrial411
 442
 (7.0)% (7.0)% 863
 965
 (10.6)% (10.6)%
Transportation1,472
 1,475
 (0.2)% (8.0)% 3,580
 3,693
 (3.1)% (0.9)%
Total natural gas deliveries(a)
3,608
 3,224
 11.9 % (14.1)% 11,486
 12,592
 (8.8)% (3.8)%
As of June 30,As of June 30,
Number of Delaware Natural Gas Customers2020 2019Number of Delaware Natural Gas Customers20212020
Residential126,245
 124,325
Residential127,503 126,245 
Small commercial & industrial9,914
 9,907
Small commercial & industrial9,953 9,914 
Large commercial & industrial17
 18
Large commercial & industrial18 17 
Transportation159
 158
Transportation158 159 
Total136,335
 134,408
Total137,632 136,335 
__________
(a)Reflects delivery volumes from customers purchasing natural gas directly from DPL and customers purchasing natural gas from a competitive natural gas 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.
(a)Reflects delivery volumes from customers purchasing natural gas directly from DPL and customers purchasing natural gas from a competitive natural gas 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.
Distribution Revenue increased for the three and six months ended June 30, 20202021 compared to the same period in 20192020 primarily due to higher electric distribution rates in Maryland that became effective in July 2020 and higher electric and natural gas distribution rates due to the Gas Distribution System Improvement Charge (DSIC) fully implementedin Delaware that became effective in the first quartersecond half of 2020.
Transmission Revenues. Under a FERC approvedFERC-approved formula, transmission revenue varies from year to year based upon fluctuations in the underlying costs and capital investments being recovered and the highest daily peak load, which is updated annually in January based on the prior calendar years. Generally, increases/decreases in the highest daily peak load will result in higher/lower transmission revenue.recovered. Transmission revenue decreasedincreased for the three and six months ended June 30, 20202021, compared to the same period in 20192020, primarily due to the reduction in revenue in 2020 due to the settlement agreement of ongoing transmission-relatedtransmission related income tax regulatory liabilities. See Note 2 — Regulatory Matters of the Combined Notes to Consolidated Financial Statements for additional information.
Other revenue includes rental revenue, revenue related to late payment charges, mutual assistance revenues, and recoveries of other taxes. Other revenue decreased for the three and six months ended June 30, 2020 compared to the same period in 2019, as DPL temporarily suspended customer disconnections for non-payment and temporarily ceased new late fees for all customers and restored service to customers upon request who were disconnected in the last twelve months.

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Regulatory Required Programs represent revenues collected under approved riders to recover costs incurred for regulatory programs such as energy efficiency programs, DE Renewable Portfolio Standards, SOS procurement and administrative costs, and GCR costs. The riders are designed to provide full and current cost recovery as well as a return in certain instances. The costs of these programs are included in Purchased power and fuel expense, Operating and maintenance expense, Depreciation and amortization expense, and Taxes other than income taxes. Customers have the choice to purchase electricity from competitive electric generation suppliers. Customer choice programs do not impact the volume of deliveries but impactas DPL 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, DPL either acts as the billing agent or the competitive supplier separately bills its own customers, and therefore DPL does not record Operating revenues or Purchased power and fuel expense related to suppliedthe electricity. Drivers of Operating revenues relatedFor customers that choose to commodity and REC procurement costs and participation in customer choice programs are fully offset by their impact on Purchased power expense.purchase electric generation from DPL, recoversDPL is permitted to recover the electricity and REC procurement costs from customers with a slight mark-up and therefore records the amounts related to the electricity and RECs in Operating revenues and Purchased power and fuel expense. DPL recovers natural gas costs from customers without mark-up.mark-up and records the amount in Operating revenues and Purchased power and fuel expense.
See Note 45 - Segment Information forof the Combined Notes to Consolidated Financial Statements for the presentation of DPL's revenue disaggregation.
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The decreaseincrease of $22$1 million and $14 million for the three and six months ended June 30, 20202021, compared to the same period in 20192020, respectively, in Purchased power and fuel expense is fully offset in Operating revenues as part of regulatory required programs.
The changes in Operating and maintenance expense consisted of the following:
Three Months Ended
June 30, 2021		Six Months Ended
June 30, 2021
Three Months Ended
June 30, 2020		 Six Months Ended
June 30, 2020		(Decrease) Increase(Decrease) Increase
Increase (Decrease) Increase (Decrease)
Credit loss expenseCredit loss expense$(6)$(5)
Labor, other benefits, contracting and materials$8
 $8
Labor, other benefits, contracting and materials(5)(3)
Credit loss expense7
 5
Storm-related costs2
 2
Storm-related costs(3)(4)
Pension and non-pension postretirement benefits expense(1) (2)Pension and non-pension postretirement benefits expense(1)(1)
BSC and PHISCO costs—
 (2)BSC and PHISCO costs1 3 
Other(5) (2)Other3 3 
11
 9
(11)(7)
Regulatory required programs4
 3
Regulatory required programs(1)(1)
Total increase$15
 $12
Total decreaseTotal decrease$(12)$(8)
The changes in Depreciation and amortization expense consisted of the following:
Three Months Ended
June 30, 2020		 Six Months Ended
June 30, 2020		Three Months Ended
June 30, 2021		Six Months Ended
June 30, 2021
Increase (Decrease) Increase (Decrease)IncreaseIncrease
Depreciation and amortization(a)
$3
 $5
Depreciation and amortization(a)
$3 $7 
Regulatory required programs(1) (2)Regulatory required programs1 3 
Total increase$2
 $3
Total increase$4 $10 
_________
(a)Depreciation and amortization increased primarily due to ongoing capital expenditures.
(a)Depreciation and amortization increased primarily due to ongoing capital expenditures.

Effective income tax rates were 311.1%3.2% and 11.8%311.1% for the three months ended June 30, 20202021 and 2019,2020, respectively, and 6.5% and (45.5)% and 11.7% for the six months ended June 30, 20202021 and 2019,2020, respectively. The change is primarily relateddue to the April 24, 2020 settlement agreement of ongoing transmission-relatedtransmission related income tax regulatory liabilities. See Note 23 — Regulatory Matters of the 2020 Exelon Form 10-K for additional information on the April 24, 2020 settlement agreement, and Note 910 — Income Taxes of the Combined Notes to Consolidated Financial Statements for additional information regarding the components of the change in effective income tax rates.

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Results of Operations — ACE
Three Months Ended June 30, (Unfavorable) Favorable Variance Six Months Ended June 30, (Unfavorable) Favorable VarianceThree Months Ended June 30,Favorable (Unfavorable) VarianceSix Months Ended June 30,Favorable (Unfavorable) Variance
2020 2019 2020 2019 2021202020212020
Operating revenues$256
 $274
 $(18) $532
 $547
 $(15)Operating revenues$319 $256 $63 $629 $532 $97 
Operating expenses    
      Operating expenses
Purchased power expense130
 131
 1
 259
 270
 11
Purchased power expense154 130 (24)311 259 (52)
Operating and maintenance82
 74
 (8) 160
 155
 (5)Operating and maintenance73 82 9 150 160 10 
Depreciation and amortization44
 40
 (4) 86
 71
 (15)Depreciation and amortization40 44 4 87 86 (1)
Taxes other than income taxes2
 1
 (1) 4
 2
 (2)Taxes other than income taxes2 2 — 4 4 — 
Total operating expenses258
 246
 (12) 509
 498
 (11)Total operating expenses269 258 (11)552 509 (43)
Gain on sale of assets—
 —
 —
 2
 —
 2
Gain on sale of assets— — — — 2 (2)
Operating (loss) income(2) 28
 (30) 25
 49
 (24)
Operating income (loss)Operating income (loss)50 (2)52 77 25 52 
Other income and (deductions)    
      Other income and (deductions)
Interest expense, net(15) (15) —
 (29) (28) (1)Interest expense, net(14)(15)1 (29)(29)— 
Other, net2
 1
 1
 3
 4
 (1)Other, net— 2 (2)2 3 (1)
Total other income and (deductions)(13)
(14) 1
 (26) (24) (2)Total other income and (deductions)(14)(13)(1)(27)(26)(1)
Income before income taxes(15)
14
 (29) (1) 25
 (26)
Income (loss) before income taxesIncome (loss) before income taxes36 (15)51 50 (1)51 
Income taxes(33) —
 33
 (32) 1
 33
Income taxes(1)(33)(32)(1)(32)(31)
Net income$18
 $14
 $4
 $31
 $24
 $7
Net income$37 $18 $19 $51 $31 $20 
Three Months Ended June 30, 20202021 Compared to Three Months Ended June 30, 2019.2020. Net income increased by $4$19 million primarily due to higher electrictransmission revenues due to an increase in capital investments and higher distribution rates that became effectiverevenues due to an increase in April 2020 partially offset by lower commercial and industrial usage.volume in ACE's service territory.

Six Months Ended June 30, 20202021 Compared to Six Months Ended June 30, 2019.2020. Net income increased by $7$20 million primarily due to higher electric distribution rates that became effective in April 2019 and April 2020, partially offset by unfavorablefavorable weather conditions, higher transmission revenues due to an increase in ACE’scapital investments and higher distribution revenues due to an increase in volume in ACE's service territory, lower commercial and industrial usage and increased depreciation and amortization expense.territory.
The changes in Operating revenues consisted of the following:
Three Months Ended
June 30, 2020		 Six Months Ended June 30, 2020Three Months Ended
June 30, 2021		Six Months Ended June 30, 2021
(Decrease) Increase (Decrease) Increase(Decrease) Increase Increase (Decrease)
Weather$(1) $(5)Weather$(1)$4 
Volume(4) (6)Volume14 15 
Distribution5
 20
Distribution— (1)
Transmission(24) (18)Transmission36 36 
Other(1) (2)Other(1)— 
(25) (11)48 54 
Regulatory required programs7
 (4)Regulatory required programs15 43 
Total decrease$(18) $(15)
Total increaseTotal increase$63 $97 
Weather. The demand for electricity is affected by weather conditions. With respect to the electric business, very warm weather in summer months and very cold weather in winter months are referred to as “favorable weather conditions” because these weather conditions result in increased deliveries of electricity. Conversely, mild weather reduces demand. There was a decreaseDuring the three months ended June 30, 2021 compared to the same period in 2020, Operating revenues related to weather forremained relatively consistent. During the six months ended June 30, 20202021 compared to the same period in 20192020, Operating revenues related to weather increased due to the impact of unfavorablefavorable weather conditions in ACE's service territory.

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177


ACE


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 20-year period in ACE’s service territory. The changes in heating and cooling degree days in ACE’s service territory for the three and six months ended June 30, 20202021 compared to same period in 20192020 and normal weather consisted of the following:
Heating and Cooling Degree-Days  Normal % ChangeHeating and Cooling Degree-DaysNormal% Change
Three Months Ended June 30,2020 2019 2020 vs. 2019 2020 vs. NormalThree Months Ended June 30,202120202021 vs. 20202021 vs. Normal
Heating Degree-Days613
 380
 541
 61.3 % 13.3 %Heating Degree-Days525 613 540 (14.4)%(2.8)%
Cooling Degree-Days312
 351
 304
 (11.1)% 2.6 %Cooling Degree-Days321 312 305 2.9 %5.2 %
         
  Normal % ChangeNormal% Change
Six Months Ended June 30,2020 2019 2020 vs. 2019 2020 vs. NormalSix Months Ended June 30,202120202021 vs. 20202021 vs. Normal
Heating Degree-Days2,561
 2,886
 3,034
 (11.3)% (15.6)%Heating Degree-Days2,873 2,561 3,008 12.2 %(4.5)%
Cooling Degree-Days312
 351
 305
 (11.1)% 2.3 %Cooling Degree-Days325 312 305 4.2 %6.6 %
Volume, exclusive of the effects of weather, decreased for the three and six months ended June 30, 2020 compared to the same period in 2019, primarily due to lower commercial and industrial usage.
Electric Retail Deliveries to Customers (in GWhs)Three Months Ended
June 30,		 % Change 
Weather - Normal % Change(b)
 Six Months Ended June 30, 2020 % Change 
Weather - Normal % Change(b)
2020 2019   2020 2019  
Residential850
 804
 5.7 % 6.5 % 1,660
 1,713
 (3.1)% 1.3 %
Small commercial & industrial276
 314
 (12.1)% (12.8)% 570
 624
 (8.7)% (6.4)%
Large commercial & industrial702
 872
 (19.5)% (19.3)% 1,437
 1,662
 (13.5)% (12.7)%
Public authorities & electric railroads11
 11
 — % 2.8 % 24
 24
 — % (0.9)%
Total electric retail deliveries(a)
1,839
 2,001
 (8.1)% (7.9)% 3,691
 4,023
 (8.3)% (5.7)%
 As of June 30,
Number of Electric Customers2020 2019
Residential496,668
 492,940
Small commercial & industrial61,468
 61,416
Large commercial & industrial3,327
 3,464
Public authorities & electric railroads687
 672
Total562,150
 558,492
_________
(a)Reflects delivery volumes from customers purchasing electricity directly from ACE 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 20-year average.
Distribution Revenue increased for the three and six months ended June 30, 20202021 compared to the same period in 20192020, primarily due to highercustomer growth and usage.
Electric Retail Deliveries to Customers (in GWhs)Three Months Ended
June 30,		% Change
Weather - Normal % Change(b)
Six Months Ended
June 30,		% Change
Weather - Normal % Change(b)
2021202020212020
Residential975 850 14.7 %16.2 %1,903 1,660 14.6 %11.3 %
Small commercial & industrial333 276 20.7 %22.3 %638 570 11.9 %9.9 %
Large commercial & industrial761 702 8.4 %8.8 %1,477 1,437 2.8 %2.4 %
Public authorities & electric railroads11 11 — %2.0 %24 24 — %1.4 %
Total electric retail deliveries(a)
2,080 1,839 13.1 %14.2 %4,042 3,691 9.5 %7.6 %

As of June 30,
Number of Electric Customers20212020
Residential499,436 496,668 
Small commercial & industrial61,836 61,468 
Large commercial & industrial3,243 3,327 
Public authorities & electric railroads707 687 
Total565,222 562,150 
_________
(a)Reflects delivery volumes from customers purchasing electricity directly from ACE and customers purchasing electricity from a competitive electric generation supplier as all customers are assessed distribution rates that became effectivecharges.
(b)Reflects the change in April 2019delivery volumes assuming normalized weather based on the historical 20-year average.
Distribution Revenue remained relatively consistent for the three and Aprilsix months ended June 30, 2021 compared to the same period in 2020.
Transmission Revenues.Under a FERC-approved formula, transmission revenue varies from year to year based upon fluctuations in the underlying costs and 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.recovered. Transmission revenue decreasedincreased for the three and six months ended June 30, 20202021, compared to the same period in 2019,2020, primarily due to the reduction in revenue in 2020 due to the settlement agreement for

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ongoing transmission-relatedtransmission related income tax regulatory liabilities. See Note 2 — Regulatory Mattersliabilities and increases in capital investment.
Other Revenue includes rental revenue, service connection fees, and mutual assistance revenues.
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ACE

Regulatory Required Programs represent revenues collected under approved riders to recover costs incurred for regulatory programs such as energy efficiency programs, Societal Benefits Charge, Transition Bonds, and BGS procurement and administrative costs. The riders are designed to provide full and current cost recovery as well as a return in certain instances. The costs of these programs are included in Purchased power and fuel expense, Operating and maintenance expense, Depreciation and amortization expense, and Taxes other than income taxes. Customers have the choice to purchase electricity from competitive electric generation suppliers. Customer choice programs do not impact the volume of deliveries, but impactas ACE 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, ACE either acts as the billing agent or the competitive supplier separately bills its own customers, and therefore ACE does not record Operating revenues or Purchased power expense related to suppliedthe electricity. Drivers ofFor customers that choose to purchase electric generation from ACE, ACE 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 commodity, RECthe electricity, ZECs, and ZEC procurement costs and participation in customer choice programs are fully offset by their impact on Purchased power expense. ACE recovers electricity, REC and ZEC procurement costs from customers without mark-up.RECs.
See Note 45 - Segment Information of the Combined Notes to Consolidated Financial Statements for the presentation of ACE's revenue disaggregation.
The decreaseincrease of $1$24 million and $11$52 million for the three and six months ended June 30, 20202021 compared to the same period in 2019 ,2020, respectively, in Purchased power expense is fully offset in Operating revenues as part of regulatory required programs.
The changes in Operating and maintenance expense consisted of the following:
Three Months Ended
June 30, 2020		 Six Months Ended June 30, 2020Three Months Ended
June 30, 2021		Six Months Ended June 30, 2021
Increase (Decrease) Increase (Decrease)(Decrease) Increase(Decrease) Increase
Labor, other benefits, contracting and materials$6
 $9
Labor, other benefits, contracting and materials$(4)$(3)
Storm-related costs(1) (1)Storm-related costs(3)(3)
Pension and non-pension postretirement benefits expensePension and non-pension postretirement benefits expense— (1)
BSC and PHISCO costs—
 (1)BSC and PHISCO costs— 1 
Credit loss expense(a)
7
 6
Other(3) (8)Other— 2 
9
 5
(7)(4)
Regulatory required programs(1) —
Total increase$8
 $5
Regulatory required programs(a)
Regulatory required programs(a)
(2)(6)
Total decreaseTotal decrease$(9)$(10)
_________
(a)ACE 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. An equal and offsetting amount has been recognized in Operating revenues.
(a)ACE 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 the Societal Benefits Charge.
The changes in Depreciation and amortization expense consisted of the following:
Three Months Ended
June 30, 2020		 Six Months Ended June 30, 2020Three Months Ended
June 30, 2021		Six Months Ended June 30, 2021
Increase (Decrease) Increase (Decrease)Increase (Decrease)Increase (Decrease)
Depreciation and amortization(a)
$3
 $12
Depreciation and amortization(a)
$4 $7 
Regulatory asset amortization(2) (1)Regulatory asset amortization(1)(1)
Regulatory required programs3
 4
Regulatory required programs(7)(5)
Total increase$4
 $15
Total (decrease) increaseTotal (decrease) increase$(4)$1 
_________
(a)
(a)Depreciation and amortization increased primarily due to ongoing capital expenditures.

Gain on sale of assets for the six months ended June 30, 2020 compared to the same period in 2019 increased due to the sale of land in February 2020.ongoing capital expenditures.

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Effective income tax rates were 220.0%(2.8)% and 0.0%220.0% for the three months ended June 30, 2021 and 2020, respectively, and 2019, respectively, 3,200.0%(2.0)% and 4.0%3200.0% for the six months ended June 30, 20202021 and 2019,2020, respectively. The change is primarily relateddue to the April 24, 2020 settlement agreement of ongoing transmission-relatedtransmission related income tax regulatory liabilities. See Note 23 — Regulatory Matters of the 2020 Exelon Form 10-K for additional information on the April 24, 2020 settlement agreement, and Note 910 — Income Taxes of the Combined Notes to Consolidated Financial Statements for additional information regarding the components of the change in effective income tax rates.

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Liquidity and Capital Resources
All results included throughout the liquidity and capital resources section are presented on a GAAP basis.
The Registrants’ operating and capital expenditures requirements are provided by internally generated cash flows from operations, the sale of certain receivables, as well as funds from external sources in the capital markets and through bank borrowings. The Registrants’ businesses are capital intensive and require considerable capital resources. Each of the Registrants annually evaluates its financing plan, dividend practices, and credit line sizing, focusing on maintaining its investment grade ratings while meeting its cash needs to fund capital requirements, retire debt, pay dividends, fund pension and OPEB obligations, and invest in new and existing ventures. A broad spectrum of financing alternatives beyond the core financing options can be used to meet its needs and fund growth including monetizing assets in the portfolio via project financing, asset sales, and the use of other financing structures (e.g., joint ventures, minority partners, etc.). Each Registrant’s access to external financing on reasonable terms depends on its credit ratings and current overall capital market business conditions, including that of the utility industry in general. If these conditions deteriorate to the extent that the Registrants no longer have access to the capital markets at reasonable terms, the Registrants have access to credit facilities with aggregate bank commitments of $10.7$10.5 billion. As a result of disruptions in the commercial paper markets due to COVID-19 in March of 2020, Generation borrowed $1.5 billion on its revolving credit facility to refinance commercial paper. Generation repaid the $1.5 billion borrowed on the revolving credit facility on April 3, 2020 using funds from short-term loans issued in March 2020, cash proceeds from the sale of certain customer accounts receivable, and borrowings from the Exelon intercompany money pool. See Note 5 - Accounts Receivable of the Combined Notes to Consolidated Financial Statements for additional information on the sale of customer accounts receivable. Exelon Corporate, Generation, and the Utility Registrants continued to issue commercial paper during the second quarter of 2020. See Executive Overview for additional information on COVID-19. The Registrants continue to utilize their credit facilities to support their commercial paper programs, provide for other short-term borrowings and to issue letters of credit. See the “Credit Matters” section below for additional information. The Registrants expect cash flows to be sufficient to meet operating expenses, financing costs, and capital expenditure requirements.
The Registrants primarily use their capital resources, including cash, to fund capital requirements, including construction expenditures, retire debt, pay dividends, fund pension and other postretirement benefitOPEB obligations, and invest in new and existing ventures. The Registrants spend a significant amount of cash on capital improvements and construction projects that have a long-term return on investment. Additionally, the Utility Registrants operate in rate-regulated environments in which the amount of new investment recovery may be delayed or limited and where such recovery takes place over an extended period of time. See Note 1213 — Debt and Credit Agreements of the Combined Notes to Consolidated Financial Statements for additional information on the Registrants’ debt and credit agreements.
Despite disruptions in the financial markets due to COVID-19, the Registrants have been able to fund their liquidity needs to date. As of December 31, 2019, Exelon had approximately $4.0 billion of long-term debt that matures in 2020, excluding project financings and floating rate long-term debt. Of this, as of June 30, 2020, Exelon has redeemed or refinanced approximately $3.4 billion that is maturing in 2020. The remaining amount of $0.6 billion on Exelon’s and Generation’s Consolidated Balance Sheet matures in the fourth quarter of 2020. To date in 2020, the Registrants have been able to execute their expected debt issuances and have issued long-term debt of $5.1 billion, of which $4.0 billion was issued in the period of April to July of 2020. The Registrants accelerated the timing of a number of planned debt issuances resulting in the $4.0 billion issued in the period of April to July of 2020 and the Registrants have now completed their planned long-term debt issuances for the 2020 year.
NRC Minimum Funding Requirements (Exelon and Generation)
NRC regulations require that licensees of nuclear generating facilities demonstrate reasonable assurance that sufficient funds will be available in certain minimum amounts to decommission the facility. These NRC minimum funding levels are typically based upon the assumption that decommissioning activities will commence after the end of the current licensed life of each unit. If a unit fails the NRC minimum funding test, then the plant’s owners or parent companies would be required to take steps, such as providing financial guarantees through letters of credit or parent company guarantees or making additional cash contributions to the NDT fund to ensure sufficient funds are available. See Note 78 — Nuclear Decommissioning of the Combined Notes to Consolidated Financial Statements for additional information.

If a nuclear plant were to early retire there is a risk that it will no longer meet the NRC minimum funding requirements due to the earlier commencement of decommissioning activities and a shorter time period over which the NDT fund investmentsfunds could appreciate in value. A shortfall could require that Generation address the shortfall by among other things, obtaining a parental guaranteeproviding additional financial assurances such as surety bonds, letters of credit, or parent company guarantees for Generation’s share of the funding assurance. However, the amount of any guarantees or other assurance will ultimately depend on the decommissioning approach, the associated level of costs, and the NDT fund investment performance going forward. No later than two years after shutting down a plant, Generation must submit a PSDAR to the NRC that includes the planned option for decommissioning the site. Upon early retirement, Dresden will have adequate funding assurance, however, due to the earlier commencement of decommissioning activities and a shorter time period over which the NDT fund investments could appreciate in value, Byron may no longer meet the NRC minimum funding requirements and, as a result, additional financial assurance may be required. Based on the decommissioning approach selected by Generation in the July 28, 2021 PSDAR filing for the Byron units, financial assurance for radiological decommissioning at Byron of up to $60 million could be required.
Upon issuance of any required financial guarantees,assurance, each site would be able to utilize the respective NDT funds for radiological decommissioning costs, which represent the majority of the total expected decommissioning costs. However, under the regulations, the NRC must approve an exemption in order for the plant’s owner(s)Generation to utilize the NDT fundfunds to pay for non-radiological decommissioning costs (i.e., spent fuel management and site restoration costs)
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costs, if applicable). If a unit does not receive this exemption, thethose costs would be borne by the owner(s)Generation without reimbursement from or access to the NDT funds. The ultimate costs forBased on current projections of the decommissioning approaches selected and expected exemptions from the NRC, it is expected that Dresden would not require supplemental cash from Generation, but some portion of the Byron spent fuel management costs would need to be funded through supplemental cash from Generation. While the ultimate amounts may vary greatly and could be reducedoffset by alternate decommissioning scenarios and/or reimbursement of certain spent fuel management costs under the DOE reimbursement agreements.settlement agreement, decommissioning for Byron may require supplemental cash from Generation of up to $135 million, net of taxes, over a period of 10 years after permanent shutdown.
As of June 30, 2020, Exelon would2021, Generation is not be required to post a parental guaranteeprovide any additional financial assurances for TMI Unit 1 under the SAFSTOR scenario which is the planned decommissioning option as described in the TMI Unit 1 PSDAR filed by Generation with the NRC on April 5, 2019. On October 16, 2019, the NRC granted Generation's exemption request to use the TMI Unit 1 NDT funds for spent fuel management costs. An additional exemption request would be required to allow the TMI Unit 1 NDT funds to be spent onused for site restoration costs which are not expectedwas submitted to be incurred in the near term.NRC on May 20, 2021 and is pending NRC review.
Project Financing (Exelon and Generation)
Project financing is used to help mitigate risk of specific generating assets. Project financing is based upon a nonrecourse financial structure, in which project debt is paid back from the cash generated by the specific asset or portfolio of assets. Borrowings under these agreements are secured by the assets and equity of each respective project. The lenders do not have recourse against Exelon or Generation in the event of a default. If a specific project financing entity does not maintain compliance with its specific debt financing covenants, there could be a requirement to accelerate repayment of the associated debt or other project-related borrowings earlier than the stated maturity dates. In these instances, if such repayment was not satisfied, or restructured, the lenders or security holders would generally have rights to foreclose against the project-specific assets and related collateral. The potential requirement to satisfy its associated debt or other borrowings earlier than otherwise anticipated could lead to impairments due to a higher likelihood of disposing of the respective project-specific assets significantly before the end of their useful lives. Additionally, project finance has credit facilities. SeeRefer to Note 1217 — Debt and Credit Agreements of the Exelon 2020 Form 10-K and Note 13 — Debt and Credit Agreements of the Combined Notes to Consolidated Financial Statements for additional information on credit facilities and nonrecourse debt. Refer to Note 16 — Debt and Credit Agreements of the Exelon 2019 Form 10-K for additional information on credit facilities.
Cash Flows from Operating Activities (All Registrants)
General
Generation’s cash flows from operating activities primarily result from the sale of electric energy and energy-related products and services to customers. Generation’s future cash flows from operating activities may be affected by future demand for and market prices of energy and its ability to continue to produce and supply power at competitive costs as well as to obtain collections from customers and the sale of certain receivables.
The Utility Registrants' cash flows from operating activities primarily result from the transmission and distribution of electricity and, in the case of PECO, BGE, and DPL, gas distribution services. The Utility Registrants' distribution services are provided to an established and diverse base of retail customers. The Utility Registrants' future cash flows may be affected by the economy, weather conditions, future legislative initiatives, future regulatory proceedings with respect to their rates or operations, and their ability to achieve operating cost reductions.
See Note 3 — Regulatory Matters and Note 1819 — Commitments and Contingencies of the Combined Notes to Consolidated Financial Statements of the Exelon 20192020 Form 10-K for additional information ofon regulatory and legal proceedings and proposed legislation.

186



The following table provides a summary of the change in cash flows from operating activities for the six months ended June 30, 20202021 and 20192020 by Registrant:
(Decrease) increase in cash flows from operating activitiesExelon Generation ComEd PECO BGE PHI Pepco DPL ACE(Decrease) increase in cash flows from operating activitiesExelonGenerationComEdPECOBGE PHIPepcoDPLACE
Net income$(510) $(172) $(237) $(92) $13
 $(21) $(10) $(19) $7
Net income$(739)$(1,124)$283 $93 $35 $67 $25 $22 $20 
Adjustments to reconcile net income to cash:                 Adjustments to reconcile net income to cash:
Non-cash operating activities305
 44
 315
 17
 4
 (7) (29) 18
 10
Non-cash operating activities(326)164 (219)(15)(12)(54)(9)(19)(19)
Pension and non-pension postretirement benefit contributions(203) (85) (76) 9
 (26) (20) —
 1
 (2)Pension and non-pension postretirement benefit contributions(1)31 (29)3 (3)(9)(1)— (1)
Income taxes(265) (295) (133) 26
 55
 (18) 5
 (23) (4)Income taxes304 (27)56 9 (53)29 (2)26 — 
Changes in working capital and other noncurrent assets and liabilities(46) (149) (24) 115
 1
 (6) 12
 5
 (14)Changes in working capital and other noncurrent assets and liabilities(1,501)(1,399)(36)(109)(85)(3)(33)11 12 
Option premiums paid, net(150) (150) —
 —
 —
 —
 —
 —
 —
Collateral posted, net651
 660
 (14) —
 5
 —
 —
 —
 —
Option premiums received (paid), netOption premiums received (paid), net104 104 — — — — — — — 
Collateral received, netCollateral received, net617 613 5 — 2 — — — — 
(Decrease) increase in cash flows from operating activities$(218) $(147) $(169) $75
 $52
 $(72) $(22) $(18) $(3)(Decrease) increase in cash flows from operating activities$(1,542)$(1,638)$60 $(19)$(116)$30 $(20)$40 $12 
Changes in the Registrants' cash flows from operations were generally consistent with changes in each Registrant’s respective results of operations, as adjusted by changes in working capital in the normal course of business, except as discussed below. In addition, significant operating cash flow impacts for the Registrants for the six months ended June 30, 20202021 and 20192020 were as follows:
•
See Note 17 — Supplemental Financial Information of the Combined Notes to Consolidated Financial Statements and the Registrants’ Consolidated Statement of Cash Flows for additional information on non-cash operating activity
•See Note 18 — Supplemental Financial Information of the Combined Notes to Consolidated Financial Statements and the Registrants’ Consolidated Statements of Cash Flows for additional information on non-cash operating activities.
•See Note 10 — Income Taxes of the Combined Notes to Consolidated Financial Statements and the Registrants' Consolidated Statements of Cash Flows for additional information on income taxes.
•Changes in working capital and other noncurrent assets and liabilities are primarily due to impacts resulting from the sale of customer accounts receivable at Exelon and Generation. See Note 6 – Accounts Receivable for additional information.
•Depending upon whether Generation is in a net mark-to-market liability or asset position, collateral may be required to be posted with or collected from its counterparties. In addition, the collateral posting and collection requirements differ depending on whether the transactions are on an exchange or in the over-the-counter markets.
187



•
See Note 9 — Income Taxes of the Combined Notes to Consolidated Financial Statements and the Registrants' Consolidated Statement of Cash Flows for additional information on income taxes.
•
Depending upon whether Generation is in a net mark-to-market liability or asset position, collateral may be required to be posted with or collected from its counterparties. In addition, the collateral posting and collection requirements differ depending on whether the transactions are on an exchange or in the OTC markets.
•
During 2020, Exelon and Generation derecognized approximately $1.2 billion of accounts receivable. See Note 5 — Accounts Receivable for additional information on the sales of customer accounts receivable.
Cash Flows from Investing Activities (All Registrants)
The following table provides a summary of the change in cash flows from investing activities for the six months ended June 30, 20202021 and 20192020 by Registrant:
Increase (decrease) in cash flows from investing activitiesExelon Generation ComEd PECO BGE PHI Pepco DPL ACEIncrease (decrease) in cash flows from investing activitiesExelonGenerationComEdPECOBGE PHIPepcoDPLACE
Capital expenditures$(201) $(40) $(68) $(65) $(6) $12
 $(26) $(24) $49
Capital expenditures$(267)$211 $(133)$(65)$(72)$(203)$(115)$(27)$(61)
Proceeds from NDT fund sales, net(125) (125) —
 —
 —
 —
 —
 —
 —
Proceeds from NDT fund sales, net(48)(48)— — — — — — — 
Proceeds from sales of assets and businesses(14) (14) —
 —
 —
 —
 —
 —
 —
Proceeds from sales of assets and businesses724 724 — — — — — — — 
Changes in intercompany money pool—
 179
 —
 68
 —
 —
 38
 (55) —
Changes in intercompany money pool— — — (68)— — — 46 — 
Collection of DPP1,102
 1,102
 —
 —
 —
 —
 —
 —
 —
Collection of DPP1,107 1,107 — — — — — — — 
Other investing activities(22) (2) (21) (1) (8) —
 (4) (4) 5
Other investing activities13 (14)16 1 14 (4)1 4 (5)
Increase (decrease) in cash flows from investing activities$740
 $1,100
 $(89) $2
 $(14) $12
 $8
 $(83) $54
Increase (decrease) in cash flows from investing activities$1,529 $1,980 $(117)$(132)$(58)$(207)$(114)$23 $(66)
Significant investing cash flow impacts for the Registrants for six months ended June 30, 20202021 and 20192020 were as follows:
•
Variances in capital expenditures are primarily due to the timing of cash expenditures for capital projects. Refer below
•Variances in capital expenditures are primarily due to the timing of cash expenditures for capital projects. Refer to Liquidity and Capital Resources of the Exelon 2020 Form 10-K for additional information on projected capital expenditure spending.
•See Note 2 – Mergers, Acquisitions, and Dispositions of the Combined Notes to Consolidated Financial Statements for additional information related to the sale of a significant portion of Generation's solar business.
•Changes in intercompany money pool are driven by short-term borrowing needs. Refer to more information regarding the intercompany money pool below.
•See Note 6 – Accounts Receivable of the Combined Notes to Consolidated Financial Statements for additional information on the Collection of DPP.
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•
Changes in intercompany money pool are driven by short-term borrowing needs. Refer to more information regarding the intercompany money pool below.
Capital Expenditure Spending
As of June 30, 2020,2021, there have been no material changes to the most recent estimates ofRegistrants' projected capital expenditures for plant additionsas disclosed in Liquidity and improvements forCapital Resources of the Exelon 2020 are as follows:
(in millions)TransmissionDistributionGasTotal
ExelonN/A
N/A
N/A
$8,075
GenerationN/A
N/A
N/A
1,500
ComEd450
1,900
N/A
2,350
PECO125
725
300
1,150
BGE300
550
450
1,300
PHI450
1,125
100
1,675
Pepco150
700
N/A
850
DPL125
225
100
450
ACE175
200
N/A
375
Projected capital expenditures and other investments are subject to periodic review and revision to reflect changes in economic conditions and other factors.Form 10-K.
Cash Flows from Financing Activities (All Registrants)
The following table provides a summary of the change in cash flows from financing activities for the six months ended June 30, 20202021 and 20192020 by Registrant:
Increase (decrease) in cash flows from financing activitiesExelon Generation ComEd PECO BGE PHI Pepco DPL ACE
(Decrease) increase in cash flows from financing activities(Decrease) increase in cash flows from financing activitiesExelonGenerationComEdPECOBGE PHIPepcoDPLACE
Changes in short-term borrowings, net$(596) $280
 $(433) $—
 $(270) $(37) $(28) $(56) $47
Changes in short-term borrowings, net$85 $(620)$(160)$— $76 $153 $187 $(90)$56 
Long-term debt, net2,356
 (443) 900
 350
 400
 53
 6
 99
 (52)Long-term debt, net(807)628 (300)25 200 38 1 26 12 
Changes in intercompany money pool—
 100
 —
 (52) —
 7
 50
 (38) 5
Changes in intercompany money pool— (285)— (40)— (22)(41)— (5)
Dividends paid on common stock(42) —
 5
 10
 (11) —
 (29) 4
 (11)Dividends paid on common stock(1)— (4)1 (23)— (22)3 (194)
Distributions to member—
 (488) —
 —
 —
 (52) —
 —
 —
Distributions to member— 21 — — — (146)— — — 
Contributions from parent/member—
 —
 125
 86
 26
 76
 8
 106
 (39)Contributions from parent/member— — 146 164 (26)201 1 14 187 
Other financing activities(79) (9) (4) (2) (8) (4) (3) (1) —
Other financing activities21 1 3 (1)2 — 4 (2)(3)
Increase (decrease) in cash flows from financing activities$1,639
 $(560) $593
 $392
 $137
 $43
 $4
 $114
 $(50)
(Decrease) increase in cash flows from financing activities(Decrease) increase in cash flows from financing activities$(702)$(255)$(315)$149 $229 $224 $130 $(49)$53 
Significant financing cash flow impacts for the Registrants for the six months ended June 30, 20202021 and 20192020 were as follows:
•
•Changes in short-term borrowings, net, is driven by repayments on and issuances of notes due in less than 365 days. Refer to 13 — Debt and Credit Agreements of the Combined Notes to Consolidated Financial Statements for additional information on short-term borrowings.
•Long-term debt, net, varies due to debt issuances and redemptions each year. Refer to 13 — Debt and Credit Agreements of the Combined Notes to Consolidated Financial Statements for additional information on debt issuances. Refer to debt redemptions tables below for additional information.
•Changes in intercompany money pool are driven by short-term borrowing needs. Refer to more information regarding the intercompany money pool below.
•Exelon’s ability to pay dividends on its common stock depends on the receipt of dividends paid by its operating subsidiaries. The payments of dividends to Exelon by its subsidiaries in turn depend on their results of operations and cash flows and other items affecting retained earnings. See Note 19 — Commitments and Contingencies of the Combined Notes to Consolidated Financial Statements of the Exelon 2020 Form 10-K for additional information on dividend restrictions. See below for quarterly dividends declared.
•, is driven by repayments on and issuances of notes due in less than 365 days. Refer to 12 — Debt and Credit Agreements of the Consolidated Financial Statements for additional information on short-term borrowings.
•
Long-term debt, net, varies due to debt issuances and redemptions each year. Refer to 12 — Debt and Credit Agreements of the Consolidated Financial Statements for additional information on debt issuances. Refer to debt redemptions tables below for more information.

•
Changes in intercompany money pool are driven by short-term borrowing needs. Refer to more information regarding the intercompany money pool below.
•
Exelon’s ability to pay dividends on its common stock depends on the receipt of dividends paid by its operating subsidiaries. The payments of dividends to Exelon by its subsidiaries in turn depend on their results of operations and cash flows and other items affecting retained earnings. See Note 14 — Commitments and Contingencies of the Combined Notes to Consolidated Financial Statements of the Exelon 2019 Form 10-K for additional information on dividend restrictions. See below for quarterly dividends declared.
For the six months ended June 30, 2020,2021, other financing activities primarily consists of debt issuance costs. See Note 1213 — Debt and Credit Agreements of the Combined Notes to Consolidated Financial Statements for additional information of the Registrants���Registrants’ debt issuances.
Debt
See Note 1213 — Debt and Credit Agreements of the Combined Notes to Consolidated Financial Statements for additional information on the Registrants’ debt issuances.
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During the six months ended June 30, 2020,2021, the following long-term debt was retired and/or redeemed:
CompanyCompanyTypeInterest RateMaturityAmount
ExelonExelonSenior Notes2.45 %April 15, 2021$300 
ExelonExelonLong-Term Software License Agreement3.95 %May 1, 202424 
ExelonExelonLong-Term Software License Agreements3.62 %December 1, 20251 
Company(a)
 Type Interest Rate Maturity Amount
Exelon Notes 2.85% June 15, 2020 $900
Exelon Long-Term Software License Agreement 3.95% May 1, 2024 24
Generation Senior Notes 2.95% January 15, 2020 1,000
Generation
Continental Wind Nonrecourse Debt(a)
6.00 %February 28, 203319 
Generation Tax-Exempt Bonds 2.50% - 2.70%
 December 1, 2025 - June 1, 2036 379
Generation
EGR IV Nonrecourse Debt(a)
3 month LIBOR + 2.50 %(b)December 15, 202717 
Generation 
ExGen Renewables IV Nonrecourse Debt(b)
 3mL +3%
 November 30, 2024 22
Generation
SolGen Nonrecourse Debt(a)
3.93 %September 30, 20367 
Generation 
Continental Wind Nonrecourse Debt(b)
 6.00% February 28, 2033 18
Generation
Antelope Valley DOE Nonrecourse Debt(a)
2.29 % - 3.56 %January 5, 20377 
Generation 
Antelope Valley DOE Nonrecourse Debt(b)
 2.29% - 3.56%
 January 5, 2037 7
Generation
West Medway II Nonrecourse Debt(a)
LIBOR + 3%(c)March 31, 20263 
Generation Energy Efficiency Project Financing 3.71% December 31, 2020 4
Generation
RPG Nonrecourse Debt(a)
4.11 %March 31, 20353 
Generation 
Renewable Power Generation Nonrecourse Debt(b)
 4.11% March 31, 2035 3
Generation SolGen Nonrecourse Debt 3.93% September 30, 2036 2
Generation Energy Efficiency Project Financing 4.12% November 30, 2020 1
ACE Tax-Exempt First Mortgage Bonds 4.88% June 1, 2029 23
ACEFirst Mortgage Bonds4.35 %April 1, 2021200 
ACE Transition Bonds 5.55% October 20, 2023 9
ACETax-Exempt First Mortgage Bonds6.80 %March 1, 202139 
ACEACETransition Bonds5.55 %October 20, 202110 
_________
(a)On July 1, Generation redeemed $550 million of 4.00% senior notes. On August 3, 2020, ComEd redeemed $500 million of first mortgage bonds, and DPL redeemed $78 million of tax-exempt bonds.
(b)See Note 12 — Debt and Credit Agreements of the Combined Notes to Consolidated Financial Statements for additional information of nonrecourse debt.
(a)See Note 17 — Debt and Credit Agreements of the Exelon 2020 Form 10-K for additional information on nonrecourse debt.
(b)The interest rate was amended to 3 month LIBOR + 2.50 % on June 16, 2021.
(c)The nonrecourse debt has an average blended interest rate.
Dividends
Quarterly dividends declared by the Exelon Board of Directors during the six months ended June 30, 20202021 and for the third quarter of 20202021 were as follows:
Period Declaration Date Shareholder of Record Date Dividend Payable Date 
Cash per Share(a)
First Quarter 2020 January 28, 2020 February 20, 2020 March 10, 2020 $0.3825
Second Quarter 2020 April 28, 2020 May 15, 2020 June 10, 2020 $0.3825
Third Quarter 2020 July 28, 2020 August 14, 2020 September 10, 2020 $0.3825
_________
(a)PeriodExelon's BoardDeclaration DateShareholder of Directors approved an updated dividend policy providing an increase of 5% each year for the period covering 2018 through 2020.Record DateDividend Payable Date
Cash per Share(a)
First Quarter 2021February 21, 2021March 8, 2021March 15, 2021$0.3825 
Second Quarter 2021April 27, 2021May 14, 2021June 10, 2021$0.3825 
Third Quarter 2021July 27, 2021August 13, 2021September 10, 2021$0.3825 

_________
(a)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.
Credit Matters (All Registrants)
The Registrants fund liquidity needs for capital investment, working capital, energy hedging, and other financial commitments through cash flows from continuing operations, public debt offerings, commercial paper markets, and large, diversified credit facilities. The credit facilities include $10.7$10.5 billion in aggregate total commitments of which $8.6$8.0 billion was available to support additional commercial paper as of June 30, 2020,2021, and of which no financial institution has more than 7% of the aggregate commitments for the Registrants. The Registrants had access to the commercial paper markets and had availability under their revolving credit facilitiesduring the second quarter of 2020six months ended June 30, 2021 to fund their short-term liquidity needs.needs, when necessary. Generation used its available credit facilities to manage short-term liquidity needs as a result of the impacts of the February 2021 extreme cold weather event and continues to believe it has sufficient cash on hand and available capacity on its revolver to meet its liquidity requirements. The Registrants routinely review the sufficiency of their liquidity position, including appropriate sizing of credit facility commitments, by performing various stress test scenarios, such as commodity price movements, increases in margin-related transactions, changes in hedging levels, and the impacts of hypothetical credit downgrades. The Registrants have continued to closely monitor events in the financial markets and the financial institutions associated with the credit facilities, including monitoring credit ratings and outlooks, credit default swap levels, capital raising, and merger activity. See PART I. ITEM 1A. RISK FACTORS of the Exelon 20192020 Form 10-K for additional information regarding the effects of uncertainty in the capital and credit markets.
The Registrants believe their cash flow from operating activities, access to credit markets, and their credit facilities provide sufficient liquidity. If Generation lost its investment grade credit rating as of June 30, 2020,2021, it would have been required to provide incremental collateral of $1.3approximately $1.9 billion to meet collateral
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obligations for derivatives, non-derivatives, normal purchases and normal sales contracts, and applicable payables and receivables, net of the contractual right of offset under master netting agreements, which is well within the $5$4.7 billion of available credit capacity of its revolver.
The following table presents the incremental collateral that each Utility Registrant would have been required to provide in the event each Utility Registrant lost its investment grade credit rating at June 30, 20202021 and available credit facility capacity prior to any incremental collateral at June 30, 2020:2021:
PJM Credit Policy CollateralOther Incremental Collateral Required(a)Available Credit Facility Capacity Prior to Any Incremental Collateral
PJM Credit Policy Collateral 
Other Incremental Collateral Required(a)
 Available Credit Facility Capacity Prior to Any Incremental Collateral
ComEd$4
 $—
 $998
ComEd$27 $— $965 
PECO—
 24
 600
PECO1 22 600 
BGE11
 26
 600
BGE4 40 600 
Pepco11
 —
 285
Pepco3 — 146 
DPL4
 10
 300
DPL4 12 300 
ACE—
 —
 295
ACE1 — 122 
_________
(a)
Represents incremental collateral related to natural gas procurementRepresents incremental collateral related to natural gas procurement contracts.
Exelon Credit Facilities
Exelon Corporate, ComEd, and BGE meet their short-term liquidity requirements primarily through the issuance of commercial paper. Generation and PECO meet their short-term liquidity requirements primarily through the issuance of commercial paper and borrowings from the Exelon intercompany money pool. Pepco, DPL, and ACE meet their short-term liquidity requirements primarily through the issuance of commercial paper and borrowings from the PHI intercompany money pool. PHI Corporate meets its short-term liquidity requirements primarily through the issuance of short-term notes and the Exelon intercompany money pool. The Registrants may use their respective credit facilities for general corporate purposes, including meeting short-term funding requirements and the issuance of letters of credit.
See Note 1213 — Debt and Credit Agreements of the Combined Notes to Consolidated Financial Statements for additional information on the Registrants’ short-term borrowing activity. See Note 1617 — Debt and Credit Agreements of the Exelon 20192020 Form 10-K for additional information on the Registrants’ credit facilities.
Security Ratings

The Registrants’ access to the capital markets, including the commercial paper market, and their respective financing costs in those markets, may depend on the securities ratings of the entity that is accessing the capital markets.
The Registrants’ borrowings are not subject to default or prepayment as a result of a downgrading of securities, although such a downgrading of a Registrant’s securities could increase fees and interest charges under that Registrant’s credit agreements.
As part of the normal course of business, the Registrants enter into contracts that contain express provisions or otherwise permit the Registrants and their counterparties to demand adequate assurance of future performance when there are reasonable grounds for doing so. In accordance with the contracts and applicable contracts law, if the Registrants are downgraded by a credit rating agency, it is possible that a counterparty would attempt to rely on such a downgrade as a basis for making a demand for adequate assurance of future performance, which could include the posting of collateral. See Note 1112 — Derivative Financial Instruments of the Combined Notes to Consolidated Financial Statements for additional information on collateral provisions.
The Registrants’ credit ratings for Exelon Corporate and the Utility Registrants did not change for the six months ended June 30, 2020.2021. On July 21, 2020,February 24, 2021, S&P lowered ComEd's long-term issuer creditGeneration's senior unsecured debt rating to 'BBB-' from 'A-' to a 'BBB+''BBB'. S&P also affirmed the current 'A' rating on ComEd's senior secured debt and 'A-2' short-term rating, which influences long and short-term borrowing cost.
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Intercompany Money Pool
To provide an additional short-term borrowing option that will generally be more favorable to the borrowing participants than the cost of external financing, both Exelon and PHI operate an intercompany money pool. Maximum amounts contributed to and borrowed from the money pool by participant and the net contribution or borrowing as of June 30, 2020,2021, are presented in the following table:table. ACE had no activity within the PHI Intercompany Money Pool for the three months ended June 30, 2021.
During the Three Months Ended June 30, 2021As of June 30, 2021
Exelon Intercompany Money PoolMaximum
Contributed		Maximum
Borrowed		Contributed
(Borrowed)
Exelon Corporate$469 $— $276 
Generation— (230)— 
PECO303 — — 
BSC— (435)(322)
PHI Corporate— (27)(9)
PCI55 — 55 
Exelon Intercompany Money Pool During the Three Months Ended June 30, 2020 As of June 30, 2020
Contributed (Borrowed) 
Maximum
Contributed
 
Maximum
Borrowed
 
Contributed
(Borrowed)
Exelon Corporate $1,364
 $—
 $372
Generation —
 (980) —
BSC —
 (504) (410)
PHI Corporate —
 (22) (22)
PCI 60
 —
 60
During the Three Months Ended June 30, 2021As of June 30, 2021
PHI Intercompany Money Pool During the Three Months Ended June 30, 2020 As of June 30, 2020PHI Intercompany Money PoolMaximum
Contributed		Maximum
Borrowed		Contributed
(Borrowed)
Contributed (Borrowed) 
Maximum
Contributed
 
Maximum
Borrowed
 
Contributed
(Borrowed)
Pepco $126
 $(57) $(50)Pepco$— $(30)$(9)
DPL 62
 (49) 55
DPL30 — 9 
ACE —
 (77) (5)
Shelf Registration Statements
Exelon, Generation, ComEd, PECO, BGE, Pepco, DPL and ACEthe Utility Registrants have a currently effective combined shelf registration statement unlimited in amount, filed with the SEC, that will expire in August 2022. The ability of each Registrant to sell securities off the shelf registration statement or to access the private placement markets will depend on a number of factors at the time of the proposed sale, including other required regulatory approvals, as applicable, the current financial condition of the Registrant, its securities ratings and market conditions.

Regulatory Authorizations
ComEd, PECO, BGE, Pepco, DPL and ACEThe Utility Registrants are required to obtain short-term and long-term financing authority from Federal and State Commissions as follows:
As of June 30, 2021
 As of June 30, 2020
Short-term Financing Authority(a)
Remaining Long-term Financing Authority(a)
 
Short-term Financing Authority(a)
 
Remaining Long-term Financing Authority(a)
CommissionExpiration DateAmountCommissionExpiration DateAmount
Commission Expiration Date AmountCommission Expiration Date Amount
ComEd FERC December 31, 2021 $2,500
 ICC February 1, 2023 $893
ComEd(b)
ComEd(b)
FERCDecember 31, 2021$2,500 ICC2023 & 2024$543 
PECO FERC December 31, 2021 1,500
 PAPUC December 31, 2021 1,225
PECOFERCDecember 31, 20211,500 PAPUCDecember 31, 2021850 
BGE FERC December 31, 2021 700
 MDPSC N/A 1,100
BGEFERCDecember 31, 2021700 MDPSCN/A500 
Pepco FERC December 31, 2021 500
 MDPSC / DCPSC December 31, 2022 1,050
PepcoFERCDecember 31, 2021500 MDPSC / DCPSCDecember 31, 2022750 
DPL FERC December 31, 2021 500
 MDPSC / DPSC December 31, 2022 375
DPLFERCDecember 31, 2021500 MDPSC / DPSCDecember 31, 2022172 
ACE NJBPU December 31, 2021 350
 NJBPU December 31, 2020 77
ACENJBPUDecember 31, 2021350 NJBPUDecember 31, 2022250 
_________
(a)
Generation currently has blanket financing authority it received from FERC in connection with its market-based rate authority.Generation currently has blanket financing authority it received from FERC in connection with its market-based rate authority.
(b)ComEd had $350 million available in long-term debt refinancing authority and $193 million available in new money long-term debt financing authority from the ICC as of June 30, 2021 and has an expiration date of February 1, 2024 and February 1, 2023, respectively. On June 29, 2021, ComEd filed an application for $2 billion in new money long-term debt financing authority from the ICC and expects approval by December 31, 2021.

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Contractual Obligations and Off-Balance Sheet Arrangements
Contractual obligations represent cash obligations that are considered to be firm commitments and commercial commitments triggered by future events. See Note 1815 — Commitments and Contingencies of the Combined Notes to Consolidated Financial Statements in the Exelon 2019 Form 10-K.for additional information.
Generation, ComEd, PECO, BGE, Pepco, DPL, and ACE have obligations related to contracts for the purchase of power and fuel supplies, and ComEd and PECO have obligations related to their financing trusts. The power and fuel purchase contracts and the financing trusts have been considered for consolidation in the Registrants’ respective financial statements pursuant to the authoritative guidance for VIEs. See Note 1 — Significant Accounting Policies of the Combined Notes to Consolidated Financial Statements in the Exelon 20192020 Form 10-K for additional information.
For an in-depth discussion of the Registrants' contractual obligations and off-balance sheet arrangements, see “Management’s Discussion and Analysis of Financial Condition and Results of Operations — Contractual Obligations and Off-Balance Sheet Arrangements” in the Exelon 20192020 Form 10-K. In addition, see discussion of off-balance sheet arrangement discussed below.
Sales of Customer10-K and Note 6 — Accounts Receivable
On April 8, 2020, Generation entered into an accounts receivable financing facility with a number of financial institutions and a commercial paper conduit to sell certain receivables, which expires on April 7, 2021 unless renewed by the mutual consent of the parties in accordance with its terms. The facility allows Generation to obtain financing at lower cost and diversify its sources of liquidity. See Note 5 — Accounts Receivable of the Combined Notes to Consolidated Financial Statements for additional information.Statements.


193


Item

ITEM 3.    Quantitative and Qualitative Disclosures about Market RiskQUANTITATIVE AND QUALITATIVE DISCLOSURE ABOUT MARKET RISK
The Registrants are exposed to market risks associated with adverse changes in commodity prices, counterparty credit, interest rates, and equity prices. Exelon’s RMC approves risk management policies and objectives for risk assessment, control and valuation, counterparty credit approval, and the monitoring and reporting of risk exposures. The RMC is chaired by the chief executive officer and includes the chief risk officer, chief strategy officer, chief executive officer of Exelon Utilities, chief commercial officer, chief financial officer, and chief executive officer of Constellation. The RMC reports to the Finance and Risk Committee of the Exelon Board of Directors on the scope of the risk management activities. The following discussion serves as an update to ITEM 7A. QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK of Exelon’s 20192020 Annual Report on Form 10-K incorporated herein by reference.
Commodity Price Risk (All Registrants)
Commodity price risk is associated with price movements resulting from changes in supply and demand, fuel costs, market liquidity, weather conditions, governmental regulatory and environmental policies, and other factors. To the extent the total amount of energy Exelon generates and purchases differs from the amount of energy it has contracted to sell, Exelon is exposed to market fluctuations in commodity prices. Exelon seeks to mitigate its commodity price risk through the sale and purchase of electricity, fossil fuel, and other commodities.
Generation
Electricity available from Generation’s owned or contracted generation supply in excess of Generation’s obligations to customers, including portions of the Utility Registrants' retail load, is sold into the wholesale markets. To reduce commodity price risk caused by market fluctuations, Generation enters into non-derivative contracts as well as derivative contracts, including swaps, futures, forwards, and options, with approved counterparties to hedge anticipated exposures. Generation uses derivative instruments as economic hedges to mitigate exposure to fluctuations in commodity prices. Generation expects the settlement of the majority of its economic hedges will occur during 20202021 through 2022.2023.
As of June 30, 2020,2021, the percentage of expected generation hedged for the Mid-Atlantic, Midwest, New York, and ERCOT reportable segments is 98%-101% and 76%-79% for 2020 and 2021, respectively.2021. Market price risk exposure is the risk of a change in the value of unhedged positions. The forecasted market price risk exposure for Generation’s entire economic hedge portfolio associated with a $5 reduction in the annual average around-the-clock energy price based on June 30, 20202021 market conditions and hedged position would be an increase in pre-tax net income of approximately $25 million for 2020 and a decrease of $189$39 million for 2021. See Note 1112 — Derivative Financial Instruments of the Combined Notes to Consolidated Financial Statements for additional information.
Fuel Procurement
Approximately 60% of Generation’s uranium concentrate requirements from 20202021 through 20242025 are supplied by three suppliers. In the event of non-performance by these or other suppliers, Generation believes that replacement uranium concentrates can be obtained, although at prices that may be unfavorable when compared to the prices under the current supply agreements. Non-performance by these counterparties could have a material adverse impact on Exelon’s and Generation’s financial statements.
Utility Registrants
There have been no significant changes or additions to the Utility Registrants exposures to commodity price risk that were described in ITEM 1A. RISK FACTORS of Exelon’s 20192020 Annual Report on Form 10-K. See Note 1112 — Derivative Financial Instruments of the Combined Notes to Consolidated Financial Statements for additional information regarding commodity price risk exposure.
Trading and Non-Trading Marketing Activities
The following table detailing Exelon’s, Generation’s, and ComEd’s trading and non-trading marketing activities areis included to address the recommended disclosures by the energy industry’s Committee of Chief Risk Officers (CCRO).

194



The following table provides detail on changes in Exelon’s, Generation’s, and ComEd’s commodity mark-to-market net asset or liability balance sheet position from December 31, 20192020 to June 30, 2020.2021. It indicates the drivers behind changes in the balance sheet amounts. This table incorporates the mark-to-market activities that are immediately recorded in earnings. This table excludes all NPNS contracts and does not segregate proprietary trading activity. See Note 1112 — Derivative Financial Instruments of the Combined Notes to Consolidated Financial Statements for additional information on the balance sheet classification of the mark-to-market energy contract net assets (liabilities) recorded as of June 30, 20202021 and December 31, 2019.2020.
ExelonGenerationComEd
Total mark-to-market energy contract net assets (liabilities) at December 31, 2020(a)
Total mark-to-market energy contract net assets (liabilities) at December 31, 2020(a)
$428 $729 $(301)
Total change in fair value during 2021 of contracts recorded in results of operationsTotal change in fair value during 2021 of contracts recorded in results of operations541 541 — 
Reclassification to realized at settlement of contracts recorded in results of operationsReclassification to realized at settlement of contracts recorded in results of operations(47)(47)— 
Exelon Generation ComEd
Total mark-to-market energy contract net assets (liabilities) at December 31, 2019(a)
$567
 $868
 $(301)
Total change in fair value during 2020 of contracts recorded in results of operations(182) (182) —
Reclassification to realized at settlement of contracts recorded in results of operations385
 385
 —
Changes in fair value — recorded through regulatory assets(b)
(17) —
 (17)
Changes in fair value — recorded through regulatory assets(b)
36 — 36 
Changes in allocated collateral(353) (353) —
Changes in allocated collateral(968)(968)— 
Net option premium paid102
 102
 —
Net option premium paid(2)(2)— 
Option premium amortization(27) (27) —
Option premium amortization(20)(20)— 
Upfront payments and amortizations(c)
(50) (50) —
Upfront payments and amortizations(c)
(48)(48)— 
Total mark-to-market energy contract net assets (liabilities) at June 30, 2020(a)
$425
 $743
 $(318)
Total mark-to-market energy contract net assets (liabilities) at June 30, 2021(a)
Total mark-to-market energy contract net assets (liabilities) at June 30, 2021(a)
$(80)$185 $(265)
_________
(a)Amounts are shown net of collateral paid to and received from counterparties.
(b)For ComEd, the changes in fair value are recorded as a change in regulatory assets. As of June 30, 2020, ComEd recorded a regulatory asset of $318 million related to its mark-to-market derivative liabilities with unaffiliated suppliers. For the six months ended June 30, 2020, ComEd recorded $35 million of decreases in fair value and an increase for realized losses due to settlements of $18 million recorded in purchased power expense associated with floating-to-fixed energy swap contracts with unaffiliated suppliers.
(c)Includes derivative contracts acquired or sold by Generation through upfront payments or receipts of cash, excluding option premiums, and the associated amortizations.
(a)Amounts are shown net of collateral paid to and received from counterparties.
(b)For ComEd, the changes in fair value are recorded as a change in regulatory assets. As of June 30, 2021, ComEd recorded a regulatory asset of $265 million related to its mark-to-market derivative liabilities with unaffiliated suppliers. For the six months ended June 30, 2021, ComEd recorded $23 million of increases in fair value and an increase for realized losses due to settlements of $13 million recorded in purchased power expense associated with floating-to-fixed energy swap contracts with unaffiliated suppliers.
(c)Includes derivative contracts acquired or sold by Generation through upfront payments or receipts of cash, excluding option premiums, and the associated amortizations.
Fair Values
The following tables present maturity and source of fair value for Exelon, Generation, and ComEd mark-to-market commodity contract net assets (liabilities). The tables provide two fundamental pieces of information. First, the tables provide the source of fair value used in determining the carrying amount of the Registrants’ total mark-to-market net assets (liabilities), net of allocated collateral. Second, the tables show the maturity, by year, of the Registrants’ commodity contract net assets (liabilities), net of allocated collateral, giving an indication of when these mark-to-market amounts will settle and either generate or require cash. See Note 1314 — Fair Value of Financial Assets and Liabilities of the Combined Notes to Consolidated Financial Statements for additional information regarding fair value measurements and the fair value hierarchy.

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Exelon
Maturities Within Total Fair
Value		Maturities WithinTotal Fair
Value
2020 2021 2022 2023 2024 2025 and Beyond 202120222023202420252026 and Beyond
Normal Operations, Commodity derivative contracts(a)(b):
             
Normal Operations, Commodity derivative contracts(a)(b):
Actively quoted prices (Level 1)$(72) $(11) $(20) $1
 $6
 $17
 $(79)Actively quoted prices (Level 1)$122 $135 $37 $28 $25 $20 $367 
Prices provided by external sources (Level 2)77
 35
 37
 13
 —
 1
 163
Prices provided by external sources (Level 2)7 224 52 (1)1 — 283 
Prices based on model or other valuation methods (Level 3)(c)
203
 223
 83
 3
 (12) (159) 341
Prices based on model or other valuation methods (Level 3)(c)
(107)(395)13 (30)(15)(196)(730)
Total$208
 $247
 $100
 $17
 $(6) $(141) $425
Total$22 $(36)$102 $(3)$11 $(176)$(80)
_________
(a)Mark-to-market gains and losses on other economic hedge and trading derivative contracts that are recorded in results of operations.
(b)Amounts are shown net of collateral paid to and received from counterparties (and offset against mark-to-market assets and liabilities) of $576 million at June 30, 2020.
(c)Includes ComEd’s net assets (liabilities) associated with the floating-to-fixed energy swap contracts with unaffiliated suppliers.
(a)Mark-to-market gains and losses on other economic hedge and trading derivative contracts that are recorded in results of operations.
(b)Amounts are shown net of collateral paid/(received) from counterparties (and offset against mark-to-market assets and liabilities) of $(552) million at June 30, 2021.
(c)Includes ComEd’s net assets (liabilities) associated with the floating-to-fixed energy swap contracts with unaffiliated suppliers.
Generation
Maturities Within Total Fair
Value		Maturities WithinTotal Fair
Value
2020 2021 2022 2023 2024 2025 and Beyond 202120222023202420252026 and Beyond
Normal Operations, Commodity derivative contracts(a)(b):
             
Normal Operations, Commodity derivative contracts(a)(b):
Actively quoted prices (Level 1)$(72) $(11) $(20) $1
 $6
 $17
 $(79)Actively quoted prices (Level 1)$122 $135 $37 $28 $25 $20 $367 
Prices provided by external sources (Level 2)77
 35
 37
 13
 —
 1
 163
Prices provided by external sources (Level 2)7 224 52 (1)1 — 283 
Prices based on model or other valuation methods (Level 3)220
 252
 112
 32
 16
 27
 659
Prices based on model or other valuation methods (Level 3)(96)(371)39 (4)10 (43)(465)
Total$225
 $276
 $129
 $46
 $22
 $45
 $743
Total$33 $(12)$128 $23 $36 $(23)$185 
_________
(a)Mark-to-market gains and losses on other economic hedge and trading derivative contracts that are recorded in the results of operations.
(b)Amounts are shown net of collateral paid to and received from counterparties (and offset against mark-to-market assets and liabilities) of $576 million at June 30, 2020.
(a)Mark-to-market gains and losses on other economic hedge and trading derivative contracts that are recorded in the results of operations.
(b)Amounts are shown net of collateral paid/(received) from counterparties (and offset against mark-to-market assets and liabilities) of $(552) million at June 30, 2021.
ComEd
Maturities Within Total Fair
Value		Maturities WithinTotal Fair
Value
2020 2021 2022 2023 2024 2025 and Beyond 202120222023202420252026 and Beyond
Commodity derivative contracts(a):
             
Commodity derivative contracts(a):
Prices based on model or other valuation methods (Level 3)(a)
$(17) $(29) $(29) $(29) $(28) $(186) $(318)
Prices based on model or other valuation methods (Level 3)(a)
$(11)$(24)$(26)$(26)$(25)$(153)$(265)
_________
(a)Represents ComEd’s net liabilities associated with the floating-to-fixed energy swap contracts with unaffiliated suppliers.
(a)Represents ComEd’s net liabilities associated with the floating-to-fixed energy swap contracts with unaffiliated suppliers.
Credit Risk (All Registrants)
The Registrants would be exposed to credit-related losses in the event of non-performance by counterparties that execute derivative instruments. The credit exposure of derivative contracts, before collateral, is represented by the

fair value of contracts at the reporting date. See Note 1112 — Derivative Financial Instruments of the Combined Notes to Consolidated Financial Statements for detailed discussion of credit risk.
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Generation
The following tables provide information on Generation’s credit exposure for all derivative instruments, normal purchases and normal sales agreements, and payables and receivables, net of collateral and instruments that are subject to master netting agreements, as of June 30, 2020.2021. The tables further delineate that exposure by credit rating of the counterparties and provide guidance on the concentration of credit risk to individual counterparties and an indication of the duration of a company’s credit risk by credit rating of the counterparties. The figuresamounts in the tables below exclude credit risk exposure from individual retail customers, uranium procurement contracts, and exposure through RTOs, ISOs, and commodity exchanges, which are discussed below.
Rating as of June 30, 2021Total  Exposure Before Credit Collateral
Credit
Collateral(a)
Net
Exposure		Number of
Counterparties
Greater than 10%
of Net Exposure		Net Exposure of
Counterparties
Greater than
10% of Net
Exposure
Investment grade$446 $56 $390 — $— 
Non-investment grade15 1 14 
No external ratings
Internally rated — investment grade134 1 133 
Internally rated — non-investment grade126 35 91 
Total$721 $93 $628 — $— 
Maturity of Credit Risk Exposure
Rating as of June 30, 2020 Total  Exposure Before Credit Collateral 
Credit
Collateral(a)
 
Net
Exposure
 
Number of
Counterparties
Greater than 10%
of Net Exposure
 
Net Exposure of
Counterparties
Greater than
10% of Net
Exposure
Rating as of June 30, 2021Rating as of June 30, 2021Less than
2 Years		2-5 YearsExposure
Greater than
5 Years		Total Exposure
Before Credit
Collateral
Investment grade $772
 $25
 $747
 $1
 $117
Investment grade$345 $48 $53 $446 
Non-investment grade 35
 26
 9
 

 

Non-investment grade15 — — 15 
No external ratings          No external ratings
Internally rated — investment grade 213
 1
 212
 

 

Internally rated — investment grade110 17 7 134 
Internally rated — non-investment grade 130
 17
 113
 

 

Internally rated — non-investment grade88 28 10 126 
Total $1,150
 $69
 $1,081
 $1
 $117
Total$558 $93 $70 $721 
  Maturity of Credit Risk Exposure
Rating as of June 30, 2020 
Less than
2 Years
 2-5 Years 
Exposure
Greater than
5 Years
 
Total Exposure
Before Credit
Collateral
Investment grade $690
 $55
 $27
 $772
Non-investment grade 35
 —
 —
 35
No external ratings        
Internally rated — investment grade 156
 32
 25
 213
Internally rated — non-investment grade 118
 6
 6
 130
Total $999
 $93
 $58
 $1,150
Net Credit Exposure by Type of Counterparty As of
June 30, 2020
Financial institutions $29
Investor-owned utilities, marketers, power producers 834
Energy cooperatives and municipalities 173
Other 45
Total $1,081
_________
(a)Net Credit Exposure by Type of CounterpartyAs of June 30, 2020, credit collateral held from counterparties where Generation had credit exposure included $31 million of cash2021
Financial institutions$27 
Investor-owned utilities, marketers, power producers448 
Energy cooperatives and $38 million of letters of credit.municipalities85 
Other68 
Total$628 
_________
(a)As of June 30, 2021, credit collateral held from counterparties where Generation had credit exposure included $53 million of cash and $40 million of letters of credit.
The Utility Registrants
There have been no significant changes or additions to the Utility Registrants exposures to credit risk that are described in ITEM 1A. RISK FACTORS of Exelon’s 20192020 Annual Report on Form 10-K.

See Note 1112 — Derivative Financial Instruments of the Combined Notes to Consolidated Financial Statements for additional information regarding credit exposure to suppliers.
Credit-Risk-Related Contingent Features (All Registrants)
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(All Registrants)

Generation
As part of the normal course of business, Generation routinely enters into physical or financial contracts for the sale and purchase of electricity, natural gas, and other commodities. In accordance with the contracts and applicable law, if Generation is downgraded by a credit rating agency, especially if such downgrade is to a level below investment grade, it is possible that a counterparty would attempt to rely on such a downgrade as a basis for making a demand for adequate assurance of future performance. Depending on Generation’s net position with a counterparty, the demand could be for the posting of collateral. In the absence of expressly agreed-to provisions that specify the collateral that must be provided, collateral requested will be a function of the facts and circumstances of the situation at the time of the demand. See Note 1112 — Derivative Financial Instruments of the Combined Notes to Consolidated Financial Statements for additional information regarding collateral requirements. See Note 1415 — Commitments and Contingencies of the Combined Notes to Consolidated Financial Statements for additional information regarding the letters of credit supporting the cash collateral.
Generation transacts output through bilateral contracts. The bilateral contracts are subject to credit risk, which relates to the ability of counterparties to meet their contractual payment obligations. Any failure to collect these payments from counterparties could have a material impact on Exelon’s and Generation’s financial statements. As market prices rise above or fall below contracted price levels, Generation is required to post collateral with purchasers; as market prices fall below contracted price levels, counterparties are required to post collateral with Generation. To post collateral, Generation depends on access to bank credit facilities, which serve as liquidity sources to fund collateral requirements. See Note 1617 — Debt and Credit Agreements of Exelon’s 20192020 Annual Report on Form 10-K for additional information.
Utility Registrants
As of June 30, 2020,2021, the Utility Registrants were not required to post collateral under their energy and/or natural gas procurement contracts. See Note 1112 — Derivative Financial Instruments of the Combined Notes to Consolidated Financial Statements for additional information.
Interest Rate and Foreign Exchange Risk (Exelon and Generation)
Exelon and Generation use a combination of fixed-rate and variable-rate debt to manage interest rate exposure. Exelon and Generation may also utilize interest rate swaps to manage their interest rate exposure. A hypothetical 50 basis pointspoint increase in the interest rates associated with unhedged variable-rate debt (excluding commercial paper)Commercial Paper) and fixed-to-floating swaps would result in approximately a $2$1 million decrease in Exelon pre-tax income for the six months ended June 30, 2020.2021. To manage foreign exchange rate exposure associated with international energy purchases in currencies other than U.S. dollars, Generation utilizes foreign currency derivatives, which are typically designated as economic hedges. See Note 1112 — Derivative Financial Instruments of the Combined Notes to Consolidated Financial Statements for additional information.
Equity Price Risk (Exelon and Generation)
Exelon and Generation maintain trust funds, as required by the NRC, to fund certain costs of decommissioning its nuclear plants. As of June 30, 2020,2021, Generation’s NDT funds are reflected at fair value in its Consolidated Balance Sheets. The mix of securities in the trust funds is designed to provide returns to be used to fund decommissioning and to compensate Generation for inflationary increases in decommissioning costs; however, the equity securities in the trust funds are exposed to price fluctuations in equity markets, and the value of fixed-rate, fixed-income securities are exposed to changes in interest rates. Generation actively monitors the investment performance of the trust funds and periodically reviews asset allocation in accordance with Generation’s NDT fund investment policy. A hypothetical 25 basis points increase in interest rates and 10% decrease in equity prices would result in a $696$886 million reduction in the fair value of the trust assets. This calculation holds all other variables constant and assumes only the discussed changes in interest rates and equity prices.

ItemITEM 4.    Controls and ProceduresCONTROLS AND PROCEDURES
During the second quarter of 2020,2021, each of the Registrants' management, including its principal executive officer and principal financial officer, evaluated its disclosure controls and procedures related to the recording, processing, summarizing, and reporting of information in its periodic reports that it files with the SEC. These
198



disclosure controls and procedures have been designed by the Registrants to ensure that (a) material information relating to that Registrant, including its consolidated subsidiaries, is accumulated and made known to Exelon’s management, including its principal executive officer and principal financial officer, by other employees of that Registrant and its subsidiaries as appropriate to allow timely decisions regarding required disclosure, and (b) this information is recorded, processed, summarized, evaluated, and reported, as applicable, within the time periods specified in the SEC’s rules and forms. Due to the inherent limitations of control systems, not all misstatements may be detected. These inherent limitations include the realities that judgments in decision-making can be faulty and that breakdowns can occur because of simple error or mistake. Additionally, controls could be circumvented by the individual acts of some persons or by collusion of two or more people.
Accordingly, as of June 30, 2020,2021, the principal executive officer and principal financial officer of each of the Registrants concluded that such Registrant’s disclosure controls and procedures were effective to accomplish its objectives. The Registrants continually strive to improve their disclosure controls and procedures to enhance the quality of its financial reporting and to maintain dynamic systems that change as conditions warrant. There were no changes in internal control over financial reporting during the second quarter of 20202021 that materially affected, or are reasonably likely to materially affect, any of the Registrants' internal control over financial reporting, including no changes resulting from COVID-19. See Item 2. Management's Discussion and Analysis of Financial Condition and Results of Operations - Executive Overview for additional information on COVID-19.reporting.
PART II — OTHER INFORMATION
ItemITEM 1.    Legal ProceedingsLEGAL PROCEEDINGS
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 (a) ITEM 3. LEGAL PROCEEDINGS of Exelon’s 20192020 Form 10-K and (b) Notes 23 — Regulatory Matters and 1415 — Commitments and Contingencies of the Combined Notes to Consolidated Financial Statements in PART I, ITEM 1. FINANCIAL STATEMENTS of this Report. Such descriptions are incorporated herein by these references.
ItemITEM 1A.    Risk FactorsRISK FACTORS
Risks Related to ExelonAll Registrants
At June 30, 2020,2021, the Registrants' risk factors were consistent with the risk factors described in the Registrants' combined 20192020 Form 10-K in ITEM 1A. RISK FACTORS, except for the following risk factors, which were added.FACTORS.
Our Results Could be Negatively Affected by the Impacts of COVID-19 (All Registrants).
The Registrants have taken steps to mitigate the potential risks posed by COVID-19. This 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 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 at this time. See Item 2. Management's Discussion and Analysis of Financial Condition and Results of Operations - Executive Overview for additional information on COVID-19.
Exelon and ComEd have received requests for information related to an SEC investigation into their lobbying activities. The outcome of the investigation 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 criminal or 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. 
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 ends 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, 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; (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.


ItemITEM 4.    Mine Safety DisclosuresMINE SAFETY DISCLOSURES
All Registrants
Not applicable to the Registrants.
ItemITEM 5.    Other InformationOTHER INFORMATION
Amendments to Exelon, ComEd, PECO, BGE and PHI Governing DocumentsAll Registrants
On August 3, 2020, Exelon, ComEd, PECO, and BGE each adopted Amended and Restated Bylaws, and PHI entered into an Amended and Restated Limited Liability Company Agreement, to address certain administrative and other non-material matters. In addition, the amendments to eachNone.

199



Table of the utilities’ governing documents provide that vacancies on the utilities’ respective boards of directors may only be filled by such utility’s shareholders and that the utilities’ respective governing documents may only be amended by such utility’s shareholders.Contents
ItemITEM 6.    ExhibitsEXHIBITS
Certain of the following exhibits are incorporated herein by reference under Rule 12b-32 of the Securities and Exchange Act of 1934, as amended. Certain other instruments which would otherwise be required to be listed below have not been so listed because such instruments do not authorize securities in an amount which exceeds 10% of the total assets of the applicable Registrant and its subsidiaries on a consolidated basis and the relevant Registrant agrees to furnish a copy of any such instrument to the Commission upon request.

Exhibit No.Description
Exhibit
No.
Description
3.1*
Amended and Restated Bylaws of Exelon*

3.2*
Amended and Restated Bylaws of ComEd*
3.3*
Amended and Restated Bylaws of PECO*
3.4*
Amended and Restated Bylaws of BGE*

3.5*
Amended and Restated Limited Liability Company Agreement of PHI*

4.1
Exelon Generation Form of 3.250% Senior Notes due 2025 (File No. 333-85496, Form 8-K dated May 15, 2020, Exhibit 4.1).
4.2101.INS
One Hundred and Eighteenth Supplemental Indenture dated as of June 1, 2020 from PECO to U.S. Bank National Association, as trustee (File No. 000-16844, Form 8-K dated June 8, 2020, Exhibit 4.1).


4.3
BGE Form of 2.900% notes due June 15, 2050 (File No. 001-01910, Form 8-K dated June 5, 2020, Exhibit 4.2).

4.4
Pollution Control Facilities Loan Agreement, dated as of June 1, 2020, between The Pollution Control Financing Authority of Salem County and ACE (File No. 001-03559, Form 8-K dated June 2, 2020, Exhibit 4.1).

4.5
Supplemental Indenture, dated as of June 1, 2020, with respect to the ACE Mortgage and Deed of Trust, dated as of January 15, 1937 (File No. 001-03559, Form 8-K dated June 9, 2020, Exhibit 4.2).

4.6
Supplemental Indenture, dated as of June 1, 2020, with respect to the DPL Mortgage and Deed of Trust, dated as of October 1, 1943 (File No. 001-01405, Form 8-K dated June 9, 2020, Exhibit 4.4).

4.7
Gas Facilities Loan Agreement, dated as of July 1, 2020, between The Delaware Economic Development Authority and DPL (File No. 001-01405, Form 8-K dated July 1, 2020, Exhibit 4.1).

10.1*
Exelon Corporation Form of Non-Employee Directors’ Deferred Stock Unit Program Agreement.*

10.2
Exelon Corporation 2020 Long-Term Incentive Plan (Effective April 28, 2020) (File No. 001-16169, Proxy Statement filed March 18, 2020, Appendix A).

10.3*
Exelon Corporation 2020 Long-Term Incentive Plan Prospectus, dated May 27, 2020.*

10.4*

Form of Restricted Stock Unit Award Notice and Agreement under the Exelon Corporation 2020 Long-Term Incentive Plan*

10.5*
Form of Performance Share Award Notice and Agreement under the Exelon Corporation 2020 Long-Term Incentive Plan*

101.INSInline XBRL Instance Document - the instance document does not appear in the Interactive Data File because its XBRL tags are embedded within the Inline XBRL document.
101.SCHInline XBRL Taxonomy Extension Schema Document.
101.CALInline XBRL Taxonomy Extension Calculation Linkbase Document.
101.DEF
Inline XBRL Taxonomy Extension Definition Linkbase Document.


101.LAB
101.LABInline XBRL Taxonomy Extension Labels Linkbase Document.
101.PRE
Inline XBRL Taxonomy Extension Presentation Linkbase Document.

104
Cover Page Interactive Data File (formatted as Inline XBRL and contained in Exhibit 101)

*Filed herewith
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Table of Contents
Certifications Pursuant to Rule 13a-14(a) and 15d-14(a) of the Securities and Exchange Act of 1934 as to the Quarterly Report on Form 10-Q for the quarterly period ended June 30, 20202021 filed by the following officers for the following companies:
Exhibit No.Description

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Table of Contents
Certifications Pursuant to Section 1350 of Chapter 63 of Title 18 United States Code (Sarbanes — Oxley Act of 2002) as to the Quarterly Report on Form 10-Q for the quarterly period ended June 30, 20202021 filed by the following officers for the following companies:
Exhibit No.Description

202



SIGNATURES

Pursuant to requirements of the Securities Exchange Act of 1934, the Registrant has duly caused this report to be signed on its behalf by the undersigned thereunto duly authorized.
EXELON CORPORATION
 
/s/    CHRISTOPHER M. CRANE/s/    JOSEPH NIGRO
Christopher M. CraneJoseph Nigro
President, and Chief Executive Officer

(Principal Executive Officer) and Director
Senior Executive Vice President and Chief Financial Officer

(Principal Financial Officer)
/s/    FABIAN E. SOUZA
Fabian E. Souza
Senior Vice President and Corporate Controller

(Principal Accounting Officer)
August 4, 20202021

203



Pursuant to requirements of the Securities Exchange Act of 1934, the Registrant has duly caused this report to be signed on its behalf by the undersigned thereunto duly authorized.
EXELON GENERATION COMPANY, LLC
 
/s/    KENNETH W. CORNEWCHRISTOPHER M. CRANE/s/    BRYAN P. WRIGHT
Kenneth W. CornewChristopher M. CraneBryan P. Wright
President and ChiefPrincipal Executive Officer
(Principal Executive Officer)
Senior Vice President and Chief Financial Officer

(Principal Financial Officer)
/s/    MATTHEW N. BAUER
Matthew N. Bauer
Vice President and Controller

(Principal Accounting Officer)
August 4, 20202021

204



Pursuant to requirements of the Securities Exchange Act of 1934, the Registrant has duly caused this report to be signed on its behalf by the undersigned thereunto duly authorized.
COMMONWEALTH EDISON COMPANY
 
/s/    JOSEPH DOMINGUEZ/s/    JEANNE M. JONES
Joseph DominguezJeanne M. Jones
Chief Executive Officer

(Principal Executive Officer)
Senior Vice President, Chief Financial Officer and Treasurer

(Principal Financial Officer)
/s/    GERALDSTEVEN J. KOZELCICHOCKI
GeraldSteven J. KozelCichocki
Vice President and Controller
Director, Accounting
(Principal Accounting Officer)
August 4, 20202021
205




Pursuant to requirements of the Securities Exchange Act of 1934, the Registrant has duly caused this report to be signed on its behalf by the undersigned thereunto duly authorized.
PECO ENERGY COMPANY
 
/s/    MICHAEL A. INNOCENZO/s/    ROBERT J. STEFANI
Michael A. InnocenzoRobert J. Stefani
President and Chief Executive Officer

(Principal Executive Officer)
Senior Vice President, Chief Financial Officer and Treasurer

(Principal Financial Officer)
/s/    CAROLINE FULGINITI

Caroline Fulginiti
Director, Accounting

(Principal Accounting Officer)
August 4, 20202021


206




Pursuant to requirements of the Securities Exchange Act of 1934, the Registrant has duly caused this report to be signed on its behalf by the undersigned thereunto duly authorized.
BALTIMORE GAS AND ELECTRIC COMPANY
 
/s/    CARIM V. KHOUZAMI/s/    DAVID M. VAHOS
Carim V. KhouzamiDavid M. Vahos
Chief Executive Officer

(Principal Executive Officer)
Senior Vice President, Chief Financial Officer and Treasurer

(Principal Financial Officer)
 /s/ JASON T. JONES
Jason T. Jones
Director, Accounting

(Principal Accounting Officer)
August 4, 20202021


207




Pursuant to requirements of the Securities Exchange Act of 1934, the Registrant has duly caused this report to be signed on its behalf by the undersigned thereunto duly authorized.
PEPCO HOLDINGS LLC

/s/ DAVID M. VELAZQUEZ/s/    PHILLIP S. BARNETT
David M. VelazquezPhillip S. Barnett
President and Chief Executive Officer

(Principal Executive Officer)
Senior Vice President, Chief Financial Officer and Treasurer

(Principal Financial Officer)
/s/ JULIE E. GIESE
Julie E. Giese
Director, Accounting

(Principal Accounting Officer)
August 4, 20202021


208




Pursuant to requirements of the Securities Exchange Act of 1934, the Registrant has duly caused this report to be signed on its behalf by the undersigned thereunto duly authorized.
POTOMAC ELECTRIC POWER COMPANY

/s/ DAVID M. VELAZQUEZ/s/    PHILLIP S. BARNETT
David M. VelazquezPhillip S. Barnett
President and Chief Executive Officer
(Principal Executive Officer)
Senior Vice President, Chief Financial Officer and Treasurer

(Principal Financial Officer)
/s/ JULIE E. GIESE
Julie E. Giese
Director, Accounting

(Principal Accounting Officer)
August 4, 20202021


209




Pursuant to requirements of the Securities Exchange Act of 1934, the Registrant has duly caused this report to be signed on its behalf by the undersigned thereunto duly authorized.
DELMARVA POWER & LIGHT COMPANY

/s/ DAVID M. VELAZQUEZ/s/    PHILLIP S. BARNETT
David M. VelazquezPhillip S. Barnett
President and Chief Executive Officer
(Principal Executive Officer)
Senior Vice President, Chief Financial Officer and Treasurer

(Principal Financial Officer)
/s/ JULIE E. GIESE
Julie E. Giese
Director, Accounting

(Principal Accounting Officer)
August 4, 20202021


210




Pursuant to requirements of the Securities Exchange Act of 1934, the Registrant has duly caused this report to be signed on its behalf by the undersigned thereunto duly authorized.
ATLANTIC CITY ELECTRIC COMPANY

/s/ DAVID M. VELAZQUEZ/s/    PHILLIP S. BARNETT
David M. VelazquezPhillip S. Barnett
President and Chief Executive Officer
(Principal Executive Officer)
Senior Vice President, Chief Financial Officer and Treasurer

(Principal Financial Officer)
/s/ JULIE E. GIESE
Julie E. Giese
Director, Accounting

(Principal Accounting Officer)
August 4, 20202021
211


207