UNITED STATES SECURITIES AND EXCHANGE COMMISSION
WASHINGTON, D.C. 20549
FORM 10-K
☒ ANNUAL REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934
For the Fiscal Year Ended December 31, 2020
or
☐ TRANSITION REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934
Name of Registrant; State or Other Jurisdiction of Incorporation; Address of Principal Executive Offices; and
Telephone Number
IRS Employer Identification
Number
EXELON CORPORATION
(a Pennsylvania corporation)
10 South Dearborn Street
P.O. Box 805379
Chicago, Illinois 60680-5379
(800) 483-3220
EXELON GENERATION COMPANY, LLC
(a Pennsylvania limited liability company)
300 Exelon Way
Kennett Square, Pennsylvania 19348-2473
(610) 765-5959
COMMONWEALTH EDISON COMPANY
(an Illinois corporation)
440 South LaSalle Street
Chicago, Illinois 60605-1028
(312) 394-4321
PECO ENERGY COMPANY
(a Pennsylvania corporation)
P.O. Box 8699
2301 Market Street
Philadelphia, Pennsylvania 19101-8699
(215) 841-4000
BALTIMORE GAS AND ELECTRIC COMPANY
(a Maryland corporation)
2 Center Plaza
110 West Fayette Street
Baltimore, Maryland 21201-3708
(410) 234-5000
PEPCO HOLDINGS LLC
(a Delaware limited liability company)
701 Ninth Street, N.W.
Washington, District of Columbia 20068
(202) 872-2000
POTOMAC ELECTRIC POWER COMPANY
(a District of Columbia and Virginia corporation)
701 Ninth Street, N.W.
Washington, District of Columbia 20068
(202) 872-2000
DELMARVA POWER & LIGHT COMPANY
(a Delaware and Virginia corporation)
500 North Wakefield Drive
Newark, Delaware 19702
(202) 872-2000
ATLANTIC CITY ELECTRIC COMPANY
(a New Jersey corporation)
500 North Wakefield Drive
Newark, Delaware 19702
(202) 872-2000
23-2990190
23-3064219
36-0938600
23-0970240
52-0280210
52-2297449
53-0127880
51-0084283
21-0398280
Commission
File Number
001-16169
333-85496
001-01839
000-16844
001-01910
001-31403
001-01072
001-01405
001-03559
Securities registered pursuant to Section 12(b) of the Act:
Title of each class
Trading Symbol(s)
Name of each exchange on which registered
EXELON CORPORATION:
Common Stock, without par value
EXC
The 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 Company
EXC/28
New York Stock Exchange
Securities registered pursuant to Section 12(g) of the Act:
Title of Each Class
COMMONWEALTH EDISON COMPANY:
Common Stock Purchase Warrants (1971 Warrants and Series B Warrants)
Indicate by check mark if the registrant is a well-known seasoned issuer, as defined in Rule 405 of the Securities Act.
Exelon 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
Atlantic City Electric Company
Indicate by check mark if the registrant is not required to file reports pursuant to Section 13 or Section 15(d) of the Act.
Exelon Corporation
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
Atlantic City Electric Company
Yes x
Yes ☐
Yes ☐
Yes ☐
Yes ☐
Yes ☐
Yes ☐
Yes ☐
Yes ☐
Yes ☐
Yes ☐
Yes ☐
Yes ☐
Yes ☐
Yes ☐
Yes ☐
Yes ☐
Yes ☐
No ☐
No x
No x
No x
No x
No x
No x
No x
No x
No x
No x
No x
No x
No x
No x
No x
No x
No x
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 ☒ No ☐
Indicate by check mark whether the registrant has submitted electronically every Interactive Data File required to be submitted pursuant to Rule 405 of Regulation S-T
(§232.405 of this chapter) during the preceding 12 months (or for such shorter period that the registrant was required to submit and post such files). Yes ☒ No ☐
Indicate by check mark whether the registrant is a large accelerated filer, an accelerated filer, a non-accelerated filer, a smaller reporting company, or an emerging growth
company. See the definitions of “large accelerated filer,” “accelerated filer,” “smaller reporting company,” and "emerging growth company" in Rule 12b-2 of the Exchange Act.
Exelon 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
Atlantic City Electric
Company
Large Accelerated Filer x
Accelerated Filer ☐
Non-accelerated Filer ☐
Large Accelerated Filer ☐
Accelerated Filer ☐
Non-accelerated Filer x
Large Accelerated Filer ☐
Accelerated Filer ☐
Non-accelerated Filer x
Large Accelerated Filer ☐
Accelerated Filer ☐
Non-accelerated Filer x
Large Accelerated Filer ☐
Accelerated Filer ☐
Non-accelerated Filer x
Large Accelerated Filer ☐
Accelerated Filer ☐
Non-accelerated Filer x
Large Accelerated Filer ☐
Accelerated Filer ☐
Non-accelerated Filer x
Large Accelerated Filer ☐
Accelerated Filer ☐
Non-accelerated Filer x
Large Accelerated Filer ☐
Accelerated Filer ☐
Non-accelerated Filer x
Smaller Reporting
Company ☐
Smaller Reporting
Company ☐
Smaller Reporting
Company ☐
Smaller Reporting
Company ☐
Smaller Reporting
Company ☐
Smaller Reporting
Company ☐
Smaller Reporting
Company ☐
Smaller Reporting
Company ☐
Smaller Reporting
Company ☐
Emerging Growth
Company ☐
Emerging Growth
Company ☐
Emerging Growth
Company ☐
Emerging Growth
Company ☐
Emerging Growth
Company ☐
Emerging Growth
Company ☐
Emerging Growth
Company ☐
Emerging Growth
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 has filed a report on and attestation to its management’s assessment of the effectiveness of its internal control over financial
reporting under Section 404(b) of the Sarbanes-Oxley Act by the registered public accounting firm that prepared or issued its audit report. x
Indicate by check mark whether the registrant is a shell company (as defined in Rule 12b-2 of the Act). Yes ☐ No x
The estimated aggregate market value of the voting and non-voting common equity held by nonaffiliates of each registrant as of June 30, 2020 was as follows:
Exelon Corporation Common Stock, without par value
Exelon Generation Company, LLC
Commonwealth Edison Company Common Stock, $12.50 par value
PECO Energy Company Common Stock, without par value
Baltimore Gas and Electric Company, without par value
Pepco Holdings LLC
Potomac Electric Power Company
Delmarva Power & Light Company
Atlantic City Electric Company
The number of shares outstanding of each registrant’s common stock as of January 31, 2021 was as follows:
Exelon Corporation Common Stock, without par value
Exelon Generation Company, LLC
Commonwealth Edison Company Common Stock, $12.50 par value
PECO Energy Company Common Stock, without par value
Baltimore Gas and Electric Company Common Stock, without par value
Pepco Holdings LLC
Potomac Electric Power Company Common Stock, $0.01 par value
Delmarva Power & Light Company Common Stock, $2.25 par value
Atlantic City Electric Company Common Stock, $3.00 par value
$35,402,501,369
Not applicable
No established market
None
None
Not applicable
None
None
None
976,337,799
Not applicable
127,021,370
170,478,507
1,000
Not applicable
100
1,000
8,546,017
Documents Incorporated by Reference
Portions of the Exelon Proxy Statement for the 2020 Annual Meeting of Shareholders and the Commonwealth Edison Company 2020 Information Statement are incorporated by
reference in Part III.
Exelon Generation Company, LLC, PECO Energy Company, Baltimore Gas and Electric Company, Pepco Holdings LLC, Potomac Electric Power Company, Delmarva Power &
Light Company, and Atlantic City Electric Company meet the conditions set forth in General Instruction I(1)(a) and (b) of Form 10-K and are therefore filing this Form in the
reduced disclosure format.
TABLE OF CONTENTS
Page No.
GLOSSARY OF TERMS AND ABBREVIATIONS
FILING FORMAT
CAUTIONARY STATEMENTS REGARDING FORWARD-LOOKING INFORMATION
WHERE TO FIND MORE INFORMATION
PART I
ITEM 1.
ITEM 1A.
ITEM 1B.
ITEM 2.
ITEM 3.
ITEM 4.
PART II
ITEM 5.
BUSINESS
General
Exelon Generation Company, LLC
Utility Operations
Employees
Environmental Regulation
Executive Officers of the Registrants
RISK FACTORS
UNRESOLVED STAFF COMMENTS
PROPERTIES
Exelon Generation Company, LLC
The Utility Registrants
LEGAL PROCEEDINGS
MINE SAFETY DISCLOSURES
MARKET FOR REGISTRANT’S COMMON EQUITY, RELATED STOCKHOLDER MATTERS, AND ISSUER
PURCHASES OF EQUITY SECURITIES
1
6
6
6
7
7
8
15
19
20
25
30
46
47
47
51
52
53
54
ITEM 7.
MANAGEMENT’S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS
Exelon Corporation
Executive Overview
Financial Results of Operations
Significant 2020 Transactions and Recent Developments
Exelon's Strategy and Outlook
Other Key Business Drivers and Management Strategies
Critical Accounting Policies and Estimates
Results of Operations
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
Atlantic City Electric Company
Liquidity and Capital Resources
Contractual Obligations and Off-Balance Sheet Arrangements
ITEM 7A.
QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK
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
Atlantic City Electric Company
Page No.
58
58
58
60
63
66
67
69
80
81
88
91
95
98
99
102
106
108
122
127
127
135
137
139
141
143
145
147
149
ITEM 8.
FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA
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
Atlantic City Electric Company
Combined Notes to Consolidated Financial Statements
1. Significant Accounting Policies
2. Mergers, Acquisitions, and Dispositions
3. Regulatory Matters
4. Revenue from Contracts with Customers
5. Segment Information
6. Accounts Receivable
7. Early Plant Retirements
8. Property, Plant, and Equipment
9. Jointly Owned Electric Utility Plant
10. Asset Retirement Obligations
11. Leases
12. Asset Impairments
13. Intangible Assets
14. Income Taxes
15. Retirement Benefits
16. Derivative Financial Instruments
17. Debt and Credit Agreements
18. Fair Value of Financial Assets and Liabilities
19. Commitments and Contingencies
20. Shareholders' Equity
21. Stock-Based Compensation Plans
22. Changes in Accumulated Other Comprehensive Income
23. Variable Interest Entities
24. Supplemental Financial Information
25. Related Party Transactions
26. Subsequent Events
ITEM 9.
ITEM 9A.
CHANGES IN AND DISAGREEMENTS WITH ACCOUNTANTS ON ACCOUNTING AND FINANCIAL DISCLOSURE
CONTROLS AND PROCEDURES
Page No.
151
179
184
189
194
199
204
209
214
219
224
224
233
235
252
256
267
269
272
274
275
280
285
286
288
296
308
313
323
338
348
349
353
353
358
365
368
368
368
ITEM 9B.
PART III
ITEM 10.
ITEM 11.
ITEM 12.
ITEM 13.
ITEM 14.
PART IV
ITEM 15.
ITEM 16.
SIGNATURES
OTHER INFORMATION
DIRECTORS, EXECUTIVE OFFICERS, AND CORPORATE GOVERNANCE
EXECUTIVE COMPENSATION
SECURITY OWNERSHIP OF CERTAIN BENEFICIAL OWNERS AND MANAGEMENT AND RELATED
STOCKHOLDER MATTERS
CERTAIN RELATIONSHIPS AND RELATED TRANSACTIONS AND DIRECTOR INDEPENDENCE
PRINCIPAL ACCOUNTING FEES AND SERVICES
EXHIBITS, FINANCIAL STATEMENT SCHEDULES
FORM 10-K SUMMARY
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
Atlantic City Electric Company
Page No.
369
370
371
372
373
374
375
423
424
424
425
426
427
428
429
430
431
432
Table of Contents
Exelon Corporation and Related Entities
Exelon
Generation
ComEd
PECO
BGE
Pepco Holdings or PHI
Pepco
DPL
ACE
Registrants
Utility Registrants
Legacy PHI
ACE Funding or ATF
Antelope Valley
BondCo
BSC
CENG
Constellation
EEDC
EGR IV
EGRP
Exelon Corporate
Exelon Transmission Company
FitzPatrick
Ginna
NER
PCI
PEC L.P.
PECO Trust III
PECO Trust IV
Pepco Energy Services or PES
PHI Corporate
PHISCO
RPG
SolGen
TMI
UII
GLOSSARY OF TERMS AND ABBREVIATIONS
Exelon Corporation
Exelon Generation Company, LLC
Commonwealth Edison Company
PECO Energy Company
Baltimore Gas and Electric Company
Pepco Holdings LLC (formerly Pepco Holdings, Inc.)
Potomac Electric Power Company
Delmarva Power & Light Company
Atlantic City Electric Company
Exelon, Generation, ComEd, PECO, BGE, PHI, Pepco, DPL, and ACE, collectively
ComEd, PECO, BGE, Pepco, DPL, and ACE, collectively
PHI, Pepco, DPL, ACE, PES, and PCI, collectively
Atlantic City Electric Transition Funding LLC
Antelope Valley Solar Ranch One
RSB BondCo LLC
Exelon Business Services Company, LLC
Constellation Energy Nuclear Group, LLC
Constellation Energy Group, Inc.
Exelon Energy Delivery Company, LLC
ExGen Renewables IV, LLC
ExGen Renewables Partners, LLC
Exelon in its corporate capacity as a holding company
Exelon Transmission Company, LLC
James A. FitzPatrick nuclear generating station
R. E. Ginna nuclear generating station
NewEnergy Receivables LLC
Potomac Capital Investment Corporation and its subsidiaries
PECO Energy Capital, L.P.
PECO Energy Capital Trust III
PECO Energy Capital Trust IV
Pepco Energy Services, Inc. and its subsidiaries
PHI in its corporate capacity as a holding company
PHI Service Company
Renewable Power Generation
SolGen, LLC
Three Mile Island nuclear facility
Unicom Investments, Inc.
1
Table of Contents
Other Terms and Abbreviations
ABO
AEC
AESO
AFUDC
AMI
AOCI
ARC
ARO
ARP
ASA
BGS
Brookfield Renewable
CAISO
CBAs
CERCLA
CES
Clean Air Act
Clean Water Act
CODM
Conectiv
DC PLUG
DCPSC
DOE
DOEE
DOJ
DPP
DPSC
DSP
EDF
EIMA
EPA
ERCOT
ERISA
EROA
ERP
FASB
FEJA
FERC
FRCC
FRR
GAAP
GCR
GHG
GSA
GLOSSARY OF TERMS AND ABBREVIATIONS
Accumulated Benefit Obligation
Alternative Energy Credit that is issued for each megawatt hour of generation from a qualified
alternative energy source
Alberta Electric Systems Operator
Allowance for Funds Used During Construction
Advanced Metering Infrastructure
Accumulated Other Comprehensive Income (Loss)
Asset Retirement Cost
Asset Retirement Obligation
Alternative Revenue Program
Asset Sale Agreement
Basic Generation Service
Brookfield Renewable Partners, L.P.
California ISO
Collective Bargaining Agreements
Comprehensive Environmental Response, Compensation, and Liability Act of 1980, as
amended
Clean Energy Standard
Clean Air Act of 1963, as amended
Federal Water Pollution Control Amendments of 1972, as amended
Chief Operating Decision Maker
Conectiv, LLC, a wholly owned subsidiary of PHI and the parent of DPL and ACE during the
Predecessor periods
District of Columbia Power Line Undergrounding Initiative
District of Columbia Public Service Commission
United States Department of Energy
Department of Energy & Environment
United States Department of Justice
Deferred Purchase Price
Delaware Public Service Commission
Default Service Provider
Electricite de France SA and its subsidiaries
Energy Infrastructure Modernization Act (Illinois Senate Bill 1652 and Illinois House Bill 3036)
United States Environmental Protection Agency
Electric Reliability Council of Texas
Employee Retirement Income Security Act of 1974, as amended
Expected Rate of Return on Assets
Enterprise Resource Program
Financial Accounting Standards Board
Illinois Public Act 99-0906 or Future Energy Jobs Act
Federal Energy Regulatory Commission
Florida Reliability Coordinating Council
Fixed Resource Requirement
Generally Accepted Accounting Principles in the United States
Gas Cost Rate
Greenhouse Gas
Generation Supply Adjustment
2
Table of Contents
Other Terms and Abbreviations
GWh
ICC
ICE
IIP
Illinois Settlement Legislation
IPA
IRC
IRS
ISO
ISO-NE
NYISO
kV
kWh
LIBOR
LLRW
LNG
LTIP
MATS
MDE
MDPSC
MGP
MISO
mmcf
MOPR
MRV
MW
MWh
N/A
NAV
NDT
NEIL
NERC
NJBPU
NJDEP
Non-Regulatory Agreement Units
NOSA
NPDES
NPNS
NRC
NWPA
NYMEX
NYPSC
OCI
OIESO
OPEB
GLOSSARY OF TERMS AND ABBREVIATIONS
Gigawatt hour
Illinois Commerce Commission
Intercontinental Exchange
Infrastructure Investment Program
Legislation enacted in 2007 affecting electric utilities in Illinois
Illinois Power Agency
Internal Revenue Code
Internal Revenue Service
Independent System Operator
ISO New England Inc.
New York ISO
Kilovolt
Kilowatt-hour
London Interbank Offered Rate
Low-Level Radioactive Waste
Liquefied Natural Gas
Long-Term Incentive Plan
U.S. EPA Mercury and Air Toxics Standards
Maryland Department of the Environment
Maryland Public Service Commission
Manufactured Gas Plant
Midcontinent Independent System Operator, Inc.
Million Cubic Feet
Minimum Offer Price Rule
Market-Related Value
Megawatt
Megawatt hour
Not applicable
Net Asset Value
Nuclear Decommissioning Trust
Nuclear Electric Insurance Limited
North American Electric Reliability Corporation
New Jersey Board of Public Utilities
New Jersey Department of Environmental Protection
Nuclear generating units or portions thereof whose decommissioning-related activities are not
subject to contractual elimination under regulatory accounting
Nuclear Operating Services Agreement
National Pollutant Discharge Elimination System
Normal Purchase Normal Sale scope exception
Nuclear Regulatory Commission
Nuclear Waste Policy Act of 1982
New York Mercantile Exchange
New York Public Service Commission
Other Comprehensive Income
Ontario Independent Electricity System Operator
Other Postretirement Employee Benefits
3
Table of Contents
Other Terms and Abbreviations
PA DEP
PAPUC
PCB
PGC
PG&E
PJM
POLR
PPA
PP&E
Price-Anderson Act
PRP
PSEG
PV
RCRA
REC
Regulatory Agreement Units
RES
RFP
Rider
RGGI
RMC
RNF
ROE
ROU
RPS
RTEP
RTO
S&P
SEC
SERC
SGIG
SNF
SOA
SOS
SPP
SSA
TCJA
Transition Bond Charge
GLOSSARY OF TERMS AND ABBREVIATIONS
Pennsylvania Department of Environmental Protection
Pennsylvania Public Utility Commission
Polychlorinated Biphenyl
Purchased Gas Cost Clause
Pacific Gas and Electric Company
PJM Interconnection, LLC
Provider of Last Resort
Power Purchase Agreement
Property, Plant, and Equipment
Price-Anderson Nuclear Industries Indemnity Act of 1957
Potentially Responsible Parties
Public Service Enterprise Group Incorporated
Photovoltaic
Resource Conservation and Recovery Act of 1976, as amended
Renewable Energy Credit which is issued for each megawatt hour of generation from a qualified
renewable energy source
Nuclear generating units or portions thereof whose decommissioning-related activities are
subject to contractual elimination under regulatory accounting
Retail Electric Suppliers
Request for Proposal
Reconcilable Surcharge Recovery Mechanism
Regional Greenhouse Gas Initiative
Risk Management Committee
Revenue Net of Purchased Power and Fuel Expense
Return on equity
Right-of-use
Renewable Energy Portfolio Standards
Regional Transmission Expansion Plan
Regional Transmission Organization
Standard & Poor’s Ratings Services
United States Securities and Exchange Commission
SERC Reliability Corporation (formerly Southeast Electric Reliability Council)
Smart Grid Investment Grant from DOE
Spent Nuclear Fuel
Society of Actuaries
Standard Offer Service
Southwest Power Pool
Social Security Administration
Tax Cuts and Jobs Act
Revenue ACE receives, and pays to ACE Funding, to fund the principal and interest payments
on Transition Bonds and related taxes, expenses, and fees
Transition Bonds
U.S. Court of Appeals for the D.C. Circuit
VIE
WECC
Transition Bonds issued by ACE Funding
United States Court of Appeals for the District of Columbia Circuit
Variable Interest Entity
Western Electric Coordinating Council
4
Table of Contents
Other Terms and Abbreviations
ZEC
ZES
Zero Emission Credit
Zero Emission Standard
GLOSSARY OF TERMS AND ABBREVIATIONS
5
Table of Contents
FILING FORMAT
This combined Annual Report on Form 10-K is being filed separately by Exelon Corporation, Exelon Generation Company, LLC, Commonwealth Edison
Company, PECO Energy Company, Baltimore Gas and Electric Company, Pepco Holdings LLC, Potomac Electric Power Company, Delmarva Power & Light
Company, and Atlantic City Electric Company (Registrants). Information contained herein relating to any individual Registrant is filed by such Registrant on
its own behalf. No Registrant makes any representation as to information relating to any other Registrant.
CAUTIONARY STATEMENTS REGARDING FORWARD-LOOKING INFORMATION
This Report contains certain forward-looking statements within the meaning of the Private Securities Litigation Reform Act of 1995 that are subject to risks
and uncertainties including, among others, those related to the timing, manner, tax-free nature and expected benefits associated with the potential
separation of Exelon’s competitive power generation and customer-facing energy business from its six regulated electric and gas utilities. Words such as
“could,” “may,” “expects,” “anticipates,” “will,” “targets,” “goals,” “projects,” “intends,” “plans,” “believes,” “seeks,” “estimates,” “predicts,” and variations on
such words, and similar expressions that reflect our current views with respect to future events and operational, economic and financial performance, are
intended to identify such forward-looking statements.
The factors that could cause actual results to differ materially from the forward-looking statements made by the Registrants include those factors discussed
herein, including those factors discussed with respect to the Registrants discussed in (a) Part I, ITEM 1A. Risk Factors, (b) Part II, ITEM 7. Management’s
Discussion and Analysis of Financial Condition and Results of Operations, (c) Part II, ITEM 8. Financial Statements and Supplementary Data: Note 19,
Commitments and Contingencies, and (d) other factors discussed in filings with the SEC by the Registrants. Readers are cautioned not to place undue
reliance on these forward-looking statements, which apply only as of the date of this Report. None of the Registrants undertakes any obligation to publicly
release any revision to its forward-looking statements to reflect events or circumstances after the date of this Report.
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.
WHERE TO FIND MORE INFORMATION
6
Table of Contents
ITEM 1.
General
PART I
Corporate Structure and Business and Other Information
Exelon is a utility services holding company engaged in the generation, delivery, and marketing of energy through Generation and the energy distribution and
transmission businesses through ComEd, PECO, BGE, Pepco, DPL, and ACE.
Name of Registrant
Exelon Generation
Company, LLC
Business
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.
Commonwealth Edison Company
PECO Energy Company
Purchase and regulated retail sale of electricity
Transmission and distribution of electricity to retail customers
Purchase and regulated retail sale of electricity and natural gas
Baltimore Gas and Electric Company
Purchase and regulated retail sale of electricity and natural gas
Transmission and distribution of electricity and distribution of natural gas to retail
customers
Service
Territories
Five reportable segments: Mid-Atlantic, Midwest, New York,
ERCOT, and Other Power Regions
Northern Illinois, including the City of Chicago
Southeastern Pennsylvania, including the City of Philadelphia
(electricity)
Pennsylvania counties surrounding the City of Philadelphia
(natural gas)
Central Maryland, including the City of Baltimore (electricity and
natural gas)
Pepco Holdings LLC
Potomac Electric
Power Company
Delmarva Power & Light Company
Atlantic City Electric Company
Transmission and distribution of electricity and distribution of natural gas to retail
customers
Utility services holding company engaged, through its reportable segments Pepco,
DPL, and ACE
Service Territories of Pepco, DPL, and ACE
Purchase and regulated retail sale of electricity
District of Columbia and Major portions of Montgomery and
Prince George’s Counties, Maryland
Transmission and distribution of electricity to retail customers
Purchase and regulated retail sale of electricity and natural gas
Transmission and distribution of electricity and distribution of natural gas to retail
customers
Purchase and regulated retail sale of electricity
Transmission and distribution of electricity to retail customers
Portions of Delaware and Maryland (electricity)
Portions of New Castle County, Delaware (natural gas)
Portions of Southern New Jersey
On February 21, 2021, Exelon’s Board of Directors approved a plan to separate the Utility Registrants and Generation, creating two publicly traded
companies with the resources necessary to best serve customers and sustain long-term investment and operating excellence. The separation gives each
company the financial and strategic independence to focus on its specific customer needs, while executing its core business strategy. See Note 26 —
Subsequent Events of the Combined Notes to Consolidated Financial Statements for additional information.
Business Services
Through its business services subsidiary, BSC, Exelon provides its subsidiaries with a variety of support services at cost, including legal, human resources,
financial, information technology, and supply management services. PHI also has a business services subsidiary, PHISCO, which provides a variety of
support services at cost, including legal, accounting, engineering, customer operations, distribution and transmission planning, asset management, system
operations, and power procurement, to PHI operating companies. The costs of BSC and PHISCO are directly charged or allocated to the applicable
subsidiaries. The results of Exelon’s corporate operations are presented as “Other” within the consolidated financial statements and include intercompany
eliminations unless otherwise disclosed.
7
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Generation
Generation, one of the largest competitive electric generation companies in the United States as measured by owned and contracted MW, physically delivers
and markets power across multiple geographic regions through its customer-facing business, Constellation. Constellation sells electricity and natural gas,
including renewable energy, in competitive energy markets to both wholesale and retail customers. Generation leverages its energy generation portfolio to
ensure delivery of energy to both wholesale and retail customers under long-term and short-term contracts, and in wholesale power markets. Generation
operates in well-developed energy markets and employs an integrated hedging strategy to manage commodity price volatility. Generation's fleet also
provides geographic and supply source diversity. Generation’s customers include distribution utilities, municipalities, cooperatives, financial institutions, and
commercial, industrial, governmental, and residential customers in competitive markets. Generation’s customer-facing activities foster development and
delivery of other innovative energy-related products and services for its customers.
Generation is a public utility under the Federal Power Act and is subject to FERC’s exclusive ratemaking jurisdiction over wholesale sales of electricity and
the transmission of electricity in interstate commerce. Under the Federal Power Act, FERC has the authority to grant or deny market-based rates for sales of
energy, capacity, and ancillary services to ensure that such sales are just and reasonable. FERC’s jurisdiction over ratemaking includes the authority to
suspend the market-based rates of utilities and set cost-based rates should FERC find that its previous grant of market-based rates authority is no longer
just and reasonable. Other matters subject to FERC jurisdiction include, but are not limited to, third-party financings; review of mergers; dispositions of
jurisdictional facilities and acquisitions of securities of another public utility or an existing operational generating facility; affiliate transactions; intercompany
financings and cash management arrangements; certain internal corporate reorganizations; and certain holding company acquisitions of public utility and
holding company securities.
RTOs and ISOs exist in a number of regions to provide transmission service across multiple transmission systems. FERC has approved PJM, MISO, ISO-
NE, and SPP as RTOs and CAISO and NYISO as ISOs. These entities are responsible for regional planning, managing transmission congestion, developing
wholesale markets for energy and capacity, maintaining reliability, market monitoring, the scheduling of physical power sales brokered through ICE and
NYMEX, and the elimination or reduction of redundant transmission charges imposed by multiple transmission providers when wholesale customers take
transmission service across several transmission systems. ERCOT is not subject to regulation by FERC but performs a similar function in Texas to that
performed by RTOs in markets regulated by FERC.
Specific operations of Generation are also subject to the jurisdiction of various other Federal, state, regional, and local agencies, including the NRC, and
Federal and state environmental protection agencies. Additionally, Generation is subject to NERC mandatory reliability standards, which protect the nation’s
bulk power system against potential disruptions from cyber and physical security breaches.
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Generating Resources
At December 31, 2020, the generating resources of Generation consisted of the following:
Type of Capacity
Owned generation assets
(a)(b)
Nuclear
Fossil (primarily natural gas and oil)
Renewable
(c)
Owned generation assets
Contracted generation
(d)
Total generating resources
MW
18,880
9,340
3,051
31,271
3,966
35,237
__________
(a) See “Fuel” for sources of fuels used in electric generation.
(b) Net generation capacity is stated at proportionate ownership share. See ITEM 2. PROPERTIES—Generation for additional information.
(c)
(d) Electric supply procured under site specific agreements.
Includes wind, hydroelectric, solar, and biomass generation.
Generation has five reportable segments, as described in the table below, representing the different geographical areas in which Generation’s owned
generating resources are located and Generation's customer-facing activities are conducted.
Segment
Mid-Atlantic
Midwest
New York
ERCOT
Other Power Regions
Total
Net Generation Capacity
(MW)
(a)
% of Net Generation
Capacity
Geographical Area
9,729
11,911
1,971
3,623
4,037
31,271
Eastern half of PJM, which includes New Jersey, Maryland, Virginia, West
Virginia, Delaware, the District of Columbia, and parts of Pennsylvania and
North Carolina
Western half of PJM and the United States footprint of MISO, excluding
MISO’s Southern Region
31 %
38 %
6 % NYISO
12 % Electric Reliability Council of Texas
13 % New England, South, West, and Canada
100 %
__________
(a) Net generation capacity is stated at proportionate ownership share. See ITEM 2. PROPERTIES—Generation for additional information.
Nuclear Facilities
Generation has ownership interests in thirteen nuclear generating stations currently in service, consisting of 23 units with an aggregate of 18,880 MW of
capacity. These stations include FitzPatrick located in Scriba, New York, which was acquired on March 31, 2017 and exclude TMI located in Middletown,
Pennsylvania, which permanently ceased generation operations on September 20, 2019 and Oyster Creek located in Forked River, New Jersey, which
permanently ceased generation operations on September 17, 2018 and was subsequently sold to Holtec International (Holtec) on July 1, 2019. Generation
wholly owns all of its nuclear generating stations, except for undivided ownership interests in three jointly-owned nuclear stations: Quad Cities (75%
ownership), Peach Bottom (50% ownership), and Salem (42.59% ownership), which are consolidated in Exelon’s and Generation's financial statements
relative to its proportionate ownership interest in each unit, and a 50.01% membership interest in CENG, a joint venture with EDF, which wholly owns the
Calvert Cliffs and Ginna nuclear stations and Nine Mile Point Unit 1, in addition to an 82% undivided ownership interest in Nine Mile Point Unit 2. CENG is
100% consolidated in Exelon's and Generation's financial statements.
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Generation and EDF entered into a Put Option Agreement on April 1, 2014, pursuant to which EDF has an option to sell its 49.99% equity interest in CENG
to Generation. The put option became exercisable on January 1, 2016 and may be exercised any time until June 30, 2022. On November 20, 2019,
Generation received notice of EDF’s intention to exercise the put option and sell its ownership share in CENG to Generation and the put automatically
exercised on January 19, 2020 at the end of the sixty-day advance notice period. At this time, Generation cannot reasonably predict the ultimate purchase
price that will be paid to EDF for its interest in CENG. The transaction will require approval by the NYPSC and the FERC. The FERC approval was obtained
on July 30, 2020. From the date the put was exercised, the process and regulatory approvals could take one to two years to complete.
See ITEM 2. PROPERTIES for additional information on Generation's nuclear facilities, Note 2 — Mergers, Acquisitions, and Dispositions of the Combined
Notes to Consolidated Financial Statements for additional information on the disposition of Oyster Creek, and Note 23 — Variable Interest Entities of the
Combined Notes to Consolidated Financial Statements for additional information regarding the CENG consolidation.
Generation’s nuclear generating stations are all operated by Generation, with the exception of the two units at Salem, which are operated by PSEG Nuclear,
LLC (PSEG Nuclear), an indirect, wholly owned subsidiary of PSEG. In 2020, 2019, and 2018 electric supply (in GWh) generated from the nuclear
generating facilities was 62%, 64%, and 68%, respectively, of Generation’s total electric supply, which also includes fossil, hydroelectric, and renewable
generation and electric supply purchased for resale. Generation’s wholesale and retail power marketing activities are, in part, supplied by the output from the
nuclear generating stations. See ITEM 7. MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS
for additional information of Generation’s electric supply sources.
Nuclear Operations
Capacity factors, which are significantly affected by the number and duration of refueling and non-refueling outages, can have a significant impact on
Generation’s results of operations. Generation’s operations from its nuclear plants have historically had minimal environmental impact and the plants have a
safe operating history.
Generation manages its scheduled refueling outages to minimize their duration and to maintain high nuclear generating capacity factors, resulting in a stable
generation base for Generation’s wholesale and retail power marketing activities. During scheduled refueling outages, Generation performs maintenance
and equipment upgrades in order to minimize the occurrence of unplanned outages and to maintain safe, reliable operations. During 2020, 2019, and 2018,
the nuclear generating facilities operated by Generation, achieved capacity factors of 95.4%, 95.7%, and 94.6%, respectively, at ownership percentage.
In addition to the maintenance and equipment upgrades performed by Generation during scheduled refueling outages, Generation has extensive operating
and security procedures in place to ensure the safe operation of the nuclear units. Generation also has extensive safety systems in place to protect the plant,
personnel, and surrounding area in the unlikely event of an accident or other incident.
Regulation of Nuclear Power Generation
Generation is subject to the jurisdiction of the NRC with respect to the operation of its nuclear generating stations, including the licensing for operation of
each unit. The NRC subjects nuclear generating stations to continuing review and regulation covering, among other things, operations, maintenance,
emergency planning, security, and environmental and radiological aspects of those stations. As part of its reactor oversight process, the NRC continuously
assesses unit performance indicators and inspection results and communicates its assessment on a semi-annual basis. All nuclear generating stations
operated by Generation are categorized by the NRC in the Licensee Response Column, which is the highest of five performance bands. The NRC may
modify, suspend, or revoke operating licenses and impose civil penalties for failure to comply with the Atomic Energy Act or the terms of the operating
licenses. Changes in regulations by the NRC may require a substantial increase in capital expenditures and/or operating costs for nuclear generating
facilities.
Licenses
Generation has original 40-year operating licenses from the NRC for each of its nuclear units and has received 20-year operating license renewals from the
NRC for all its nuclear units except Clinton. PSEG has received 20-year operating license renewals for Salem Units 1 and 2. Peach Bottom has received a
second 20-year license
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renewal from the NRC for Units 2 and 3. On August 27, 2020, Generation announced that it intends to permanently cease generation operations at Byron in
September 2021 and at Dresden in November 2021. See Note 7 — Early Plant Retirements of the Combined Notes to Consolidated Financial Statements
for additional information.
The following table summarizes the current license expiration dates for Generation’s operating nuclear facilities in service:
Station
Braidwood
Byron
Calvert Cliffs
(b)
Clinton
Dresden
FitzPatrick
LaSalle
Limerick
Nine Mile Point
Peach Bottom
Quad Cities
Ginna
Salem
Unit
In-Service
Date
(a)
Current License
Expiration
1
2
1
2
1
2
1
2
3
1
1
2
1
2
1
2
2
3
1
2
1
1
2
1988
1988
1985
1987
1975
1977
1987
1970
1971
1974
1984
1984
1986
1990
1969
1988
1974
1974
1973
1973
1970
1977
1981
2046
2047
2044
2046
2034
2036
2027
2029
2031
2034
2042
2043
2044
2049
2029
2046
2053
2054
2032
2032
2029
2036
2040
__________
(a) Denotes year in which nuclear unit began commercial operations.
(b) Although timing has been delayed, Generation currently plans to seek license renewal for Clinton and has notified the NRC that any license renewal application would not
be filed until the first quarter of 2024. In 2019, the NRC approved a change of the operating license expiration for Clinton from 2026 to 2027.
The operating license renewal process takes approximately four to five years from the commencement of the renewal process, which includes approximately
two years for Generation to develop the application and approximately two years for the NRC to review the application. Depreciation provisions are based on
the estimated useful lives of the stations, which reflect the first renewal of the operating licenses for all of Generation’s operating nuclear generating stations
except for Clinton, Peach Bottom, Byron, and Dresden. Clinton depreciation provisions are based on an estimated useful life of 2027 which is the last year of
the Illinois ZES. Peach Bottom depreciation provisions are based on estimated useful life of 2053 and 2054 for Unit 2 and Unit 3, respectively, which reflects
the second renewal of its operating licenses. Byron and Dresden depreciation provisions are based on the announced shutdown dates of September 2021
and November 2021, respectively. See Note 3 — Regulatory Matters of the Combined Notes to Consolidated Financial Statements for additional information
on the Illinois ZES and Note 7 — Early Plant Retirements of the Combined Notes to Consolidated Financial Statements for additional information on early
retirements.
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Nuclear Waste Storage and Disposal
There are no facilities for the reprocessing or permanent disposal of SNF currently in operation in the United States, nor has the NRC licensed any such
facilities. Generation currently stores all SNF generated by its nuclear generating facilities on-site in storage pools or in dry cask storage facilities. Since
Generation’s SNF storage pools generally do not have sufficient storage capacity for the life of the respective plant, Generation has developed dry cask
storage facilities to support operations.
As of December 31, 2020, Generation had approximately 87,100 SNF assemblies (21,600 tons) stored on site in SNF pools or dry cask storage which
includes SNF assemblies at Zion Station, for which Generation retains ownership even though the responsibility for decommissioning Zion Station has been
assumed by another party, and TMI, which is no longer operational. See the Decommissioning section below for additional information regarding Zion
Station. All currently operating Generation-owned nuclear sites have on-site dry cask storage. TMI's on-site dry cask storage is projected to be in operation
in 2021. On-site dry cask storage in concert with on-site storage pools will be capable of meeting all current and future SNF storage requirements at
Generation’s sites through the end of the license renewal periods and through decommissioning.
For a discussion of matters associated with Generation’s contracts with the DOE for the disposal of SNF, see Note 19 — Commitments and Contingencies of
the Combined Notes to Consolidated Financial Statements.
As a by-product of their operations, nuclear generating units produce LLRW. LLRW is accumulated at each generating station and permanently disposed of
at licensed disposal facilities. The Federal Low-Level Radioactive Waste Policy Act of 1980 provides that states may enter into agreements to provide
regional disposal facilities for LLRW and restrict use of those facilities to waste generated within the region. Illinois and Kentucky have entered into such an
agreement, although neither state currently has an operational site and none is anticipated to be operational for the next ten years.
Generation ships its Class A LLRW, which represents 93% of LLRW generated at its stations, to disposal facilities in Utah and South Carolina, which have
enough storage capacity to store all Class A LLRW for the life of all stations in Generation's nuclear fleet. The disposal facility in South Carolina at present is
only receiving LLRW from LLRW generators in South Carolina, New Jersey (which includes Salem), and Connecticut.
Generation utilizes on-site storage capacity at all its stations to store and stage for shipping Class B and Class C LLRW. Generation has a contract through
2032 to ship Class B and Class C LLRW to a disposal facility in Texas. The agreement provides for disposal of all current Class B and Class C LLRW
currently stored at each station as well as the Class B and Class C LLRW generated during the term of the agreement. However, because the production of
LLRW from Generation’s nuclear fleet will exceed the capacity at the Texas site (3.9 million curies for 15 years beginning in 2012), Generation will still be
required to utilize on-site storage at its stations for Class B and Class C LLRW. Generation currently has enough storage capacity to store all Class B and
Class C LLRW for the life of all stations in Generation’s nuclear fleet. Generation continues to pursue alternative disposal strategies for LLRW, including an
LLRW reduction program to minimize on-site storage and cost impacts.
Nuclear Insurance
Generation is subject to liability, property damage, and other risks associated with major incidents at all of its nuclear stations. Generation has reduced its
financial exposure to these risks through insurance and other industry risk-sharing provisions. See “Nuclear Insurance” within Note 19 — Commitments and
Contingencies of the Combined Notes to Consolidated Financial Statements for additional information.
For information regarding property insurance, see ITEM 2. PROPERTIES — Generation. Generation is self-insured to the extent that any losses may exceed
the amount of insurance maintained or are within the policy deductible for its insured losses. Such losses could have a material adverse effect on Exelon’s
and Generation’s future financial statements.
Decommissioning
NRC regulations require that licensees of nuclear generating facilities demonstrate reasonable assurance that funds will be available in specified minimum
amounts at the end of the life of the facility to decommission the facility. The ultimate decommissioning obligation will be funded by the NDT funds. See ITEM
7. MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF
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OPERATIONS — Exelon Corporation, Liquidity and Capital Resources; ITEM 7. MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL
CONDITION AND RESULTS OF OPERATIONS, Critical Accounting Policies and Estimates, Nuclear Decommissioning, Asset Retirement Obligations, and
Nuclear Decommissioning Trust Fund Investments; and Note 3 — Regulatory Matters, Note 2 — Mergers, Acquisitions, and Dispositions, Note 18 — Fair
Value of Financial Assets and Liabilities, and Note 10 — Asset Retirement Obligations of the Combined Notes to Consolidated Financial Statements for
additional information regarding Generation’s NDT funds and its decommissioning obligations.
Oyster Creek Decommissioning. On July 1, 2019, Generation completed the sale with Holtec and its indirect wholly owned subsidiary, Oyster Creek
Environmental Protection, LLC (OCEP), of Oyster Creek under which Holtec has assumed the responsibility for decommissioning. See Note 2 — Mergers,
Acquisitions, and Dispositions of the Combined Notes to Consolidated Financial Statements for additional information.
Zion Station Decommissioning. On September 1, 2010, Generation completed an ASA with EnergySolutions, Inc. and its wholly owned subsidiaries,
EnergySolutions, LLC and ZionSolutions under which ZionSolutions has assumed responsibility for decommissioning Zion Station. See Note 10 — Asset
Retirement Obligations of the Combined Notes to Consolidated Financial Statements for additional information.
Fossil and Renewable Facilities (including Hydroelectric)
Generation wholly owns all of its fossil and renewable generating stations, with the exception of: (1) Wyman; (2) certain wind project entities and a biomass
project entity with minority interest owners; and (3) EGRP which is owned 49% by another owner. See Note 23 — Variable Interest Entities of the Combined
Notes to Consolidated Financial Statements for additional information regarding EGRP which is a VIE. Generation’s fossil and renewable generating stations
are all operated by Generation, with the exception of Wyman, which is operated by a third party. In 2020, 2019, and 2018, electric supply (in GWh)
generated from owned fossil and renewable generating facilities was 9%, 11%, and 11%, respectively, of Generation’s total electric supply. The majority of
this output was dispatched to support Generation’s wholesale and retail power marketing activities. On December 8, 2020, Generation entered into an
agreement to sell a significant portion of Generation's solar business. See ITEM 2. PROPERTIES for additional information regarding Generation's electric
generating facilities and Note 2 - Mergers, Acquisitions and Dispositions of the Combined Notes to Consolidated Financial Statements for additional
information on the sale of Generation's solar business.
Licenses
Fossil and renewable generation plants are generally not licensed, and, therefore, the decision on when to retire plants is, fundamentally, a commercial one.
FERC has the exclusive authority to license most non-Federal hydropower projects located on navigable waterways or Federal lands, or connected to the
interstate electric grid, which include Generation's Conowingo Hydroelectric Project (Conowingo) and Muddy Run Pumped Storage Facility Project (Muddy
Run). Muddy Run's license expires on December 1, 2055. On August 29, 2012, Generation submitted a hydroelectric license application to the FERC for a
new license for Conowingo. Based on the FERC procedural schedule, the FERC licensing process for Conowingo was not completed prior to the expiration
of the plant’s license on September 1, 2014. As a result, on September 10, 2014, FERC issued an annual license for Conowingo, effective as of the
expiration of the previous license. The annual license renews automatically absent any further FERC action. The stations are currently being depreciated
over their estimated useful lives, which include actual and anticipated license renewal periods. See Note 3 — Regulatory Matters of the Combined Notes to
Consolidated Financial Statements for additional information on Conowingo.
Insurance
Generation maintains business interruption insurance for its renewable projects, but not for its fossil and hydroelectric operations unless required by contract
or financing agreements. See Note 17 — Debt and Credit Agreements of the Combined Notes to Consolidated Financial Statements for additional
information on financing agreements. Generation maintains both property damage and liability insurance. For property damage and liability claims for these
operations, Generation is self-insured to the extent that losses are within the policy deductible or exceed the amount of insurance maintained. Such losses
could have a material adverse effect on Exelon’s and Generation’s future financial conditions and their results of operations and cash flows. For information
regarding property insurance, see ITEM 2. PROPERTIES — Generation.
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Contracted Generation
In addition to energy produced by owned generation assets, Generation sources electricity from plants it does not own under long-term contracts. The
following tables summarize Generation’s long-term contracts to purchase unit-specific physical power with an original term in excess of one year in duration,
by region, in effect as of December 31, 2020:
Region
Mid-Atlantic
Midwest
ERCOT
Other Power Regions
Total
Capacity Expiring (MW)
Fuel
Number of
Agreements
Expiration
Dates
2021 - 2032
2021 - 2032
2021 - 2035
2021 - 2032
8
3
5
17
33
Capacity (MW)
183
351
864
2,568
3,966
2021
2022
2023
2024
2025
Thereafter
Total
884
304
103
101
461
2,113
3,966
The following table shows sources of electric supply in GWh for 2020 and 2019:
(a)
Nuclear
Purchases — non-trading portfolio
Fossil (primarily natural gas and oil)
Renewable
Total supply
(b)
Source of Electric Supply
2020
2019
175,085
79,972
19,501
7,052
281,610
181,326
70,939
21,554
7,777
281,596
__________
(a)
Includes the proportionate share of output where Generation has an undivided ownership interest in jointly-owned generating plants and includes the total output of plants
that are fully consolidated (e.g., CENG). Nuclear generation for 2020 and 2019 includes physical volumes of 35,052 GWh and 35,745 GWh, respectively, for CENG.
Includes wind, hydroelectric, solar, and biomass generating assets.
(b)
The cycle of production and utilization of nuclear fuel includes the mining and milling of uranium ore into uranium concentrates, the conversion of uranium
concentrates to uranium hexafluoride, the enrichment of the uranium hexafluoride, and the fabrication of fuel assemblies. Generation has inventory in
various forms and does not anticipate difficulty in obtaining the necessary uranium concentrates or conversion, enrichment, or fabrication services to meet
the nuclear fuel requirements of its nuclear units.
Natural gas is procured through long-term and short-term contracts, as well as spot-market purchases. Fuel oil inventories are managed so that in the winter
months sufficient volumes of fuel are available in the event of extreme weather conditions and during the remaining months to take advantage of favorable
market pricing.
Generation uses financial instruments to mitigate price risk associated with certain commodity price exposures, using both over-the-counter and exchange-
traded instruments. See ITEM 1A. RISK FACTORS, ITEM 7. MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS
OF OPERATIONS, Critical Accounting Policies and Estimates and Note 16 — Derivative Financial Instruments of the Combined Notes to Consolidated
Financial Statements for additional information regarding derivative financial instruments.
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Power Marketing
Generation’s integrated business operations include physical delivery and marketing of power. Generation largely obtains physical power supply from its
owned and contracted generation in multiple geographic regions. The commodity risks associated with the output from owned and contracted generation is
managed using various commodity transactions including sales to customers. The main objective is to obtain low-cost energy supply to meet physical
delivery obligations to both wholesale and retail customers. Generation sells electricity, natural gas, and other energy related products and solutions to
various customers, including distribution utilities, municipalities, cooperatives, and commercial, industrial, governmental, and residential customers in
competitive markets. Where necessary, Generation may also purchase transmission service to ensure that it has reliable transmission capacity to physically
move its power supplies to meet customer delivery needs.
Price and Supply Risk Management
Generation also manages the price and supply risks for energy and fuel associated with generation assets and the risks of power marketing activities.
Generation implements a three-year ratable sales plan to align its hedging strategy with its financial objectives. Generation may also enter into transactions
that are outside of this ratable sales plan. Generation is exposed to commodity price risk in 2021 and beyond for portions of its electricity portfolio that are
unhedged. As of December 31, 2020, the percentage of expected generation hedged for the Mid-Atlantic, Midwest, New York, and ERCOT reportable
segments is 94%-97% for 2021. The percentage of expected generation hedged is the amount of equivalent sales divided by the expected generation.
Expected generation is the volume of energy that best represents our commodity position in energy markets from owned or contracted generation based
upon a simulated dispatch model that makes assumptions regarding future market conditions, which are calibrated to market quotes for power, fuel, load
following products, and options. Equivalent sales represent all hedging products, which include economic hedges and certain non-derivative contracts,
including sales to the Utility Registrants to serve their retail load. A portion of Generation’s hedging strategy may be implemented through the use of fuel
products based on assumed correlations between power and fuel prices. The risk management group and Exelon’s RMC monitor the financial risks of the
wholesale and retail power marketing activities. Generation also uses financial and commodity contracts for proprietary trading purposes, but this activity
accounts for only a small portion of Generation’s efforts. The proprietary trading portfolio is subject to a risk management policy that includes stringent risk
management limits. See ITEM 7A. QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK for additional information.
Capital Expenditures
Generation’s business is capital intensive and requires significant investments primarily in nuclear fuel and energy generation assets. Generation’s estimated
capital expenditures for 2021 include Generation's share of the investment in the co-owned Salem plant and the total capital expenditures for CENG. See
ITEM 7. MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS, Liquidity and Capital
Resources, for additional information regarding projected 2021 capital expenditures.
Utility Registrants
Merger with Pepco Holdings, Inc.
On March 23, 2016, Exelon completed the merger among Exelon, Purple Acquisition Corp., a wholly owned subsidiary of Exelon (Merger Sub), and PHI. As
a result of that merger, Merger Sub was merged into PHI (the PHI merger) with PHI surviving as a wholly owned subsidiary of Exelon and EEDC, a wholly
owned subsidiary of Exelon which also owns Exelon's interests in ComEd, PECO, and BGE (through a special purpose subsidiary in the case of BGE).
Following the completion of the PHI merger, Exelon, and PHI completed a series of internal corporate organization restructuring transactions resulting in the
transfer of PHI’s unregulated business interests to Exelon and Generation and the transfer of PHI, Pepco, DPL, and ACE to a special purpose subsidiary of
EEDC.
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Utility Operations
Service Territories and Franchise Agreements
The following table presents the size of service territories, populations of each service territory and the number of customers within each service territory for
the Utility Registrants as of December 31, 2020:
ComEd
PECO
BGE
Pepco
DPL
ACE
Service Territories (in square miles)
Electric
Natural Gas
Total
Service Territory Population (in millions)
Electric
Natural Gas
Total
11,400
N/A
11,400
9.6
N/A
9.6
2,100
1,960
2,100
4.0
2.5
4.0
2,300
3,050
3,250
3.0
2.9
3.1
Main City
Main City Population
Chicago
2.7
Philadelphia
1.6
Baltimore
0.6
Number of Customers (in millions)
Electric
Natural Gas
Total
4.1
N/A
4.1
1.7
0.5
1.7
1.3
0.7
1.3
640
N/A
640
2.4
N/A
2.4
District of
Columbia
0.7
0.9
N/A
0.9
5,400
270
5,400
1.5
0.6
1.5
2,800
N/A
2,800
1.1
N/A
1.1
Wilmington
0.1
Atlantic City
0.1
0.5
0.1
0.5
0.6
N/A
0.6
The Utility Registrants have the necessary authorizations to perform their current business of providing regulated electric and natural gas distribution
services in the various municipalities and territories in which they now supply such services. These authorizations include charters, franchises, permits, and
certificates of public convenience issued by local and state governments and state utility commissions. ComEd's, BGE's (gas), Pepco DC's, and ACE's rights
are generally non-exclusive while PECO's, BGE's (electric), Pepco MD's, and DPL's rights are generally exclusive. Certain authorizations are perpetual while
others have varying expiration dates. The Utility Registrants anticipate working with the appropriate governmental bodies to extend or replace the
authorizations prior to their expirations.
Utility Regulations
State utility commissions regulate the Utility Registrants' electric and gas distribution rates and service, issuances of certain securities, and certain other
aspects of the business. The following table outlines the state commissions responsible for utility oversight.
Registrant
ComEd
PECO
BGE
Pepco
DPL
ACE
Commission
ICC
PAPUC
MDPSC
DCPSC/MDPSC
DPSC/MDPSC
NJBPU
The Utility Registrants are public utilities under the Federal Power Act subject to regulation by FERC related to transmission rates and certain other aspects
of the utilities' business. The U.S. Department of Transportation also regulates pipeline safety and other areas of gas operations for PECO, BGE, and DPL.
Additionally, the Utility Registrants are subject to NERC mandatory reliability standards, which protect the nation's bulk power system against potential
disruptions from cyber and physical security breaches.
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Seasonality Impacts on Delivery Volumes
The Utility Registrants' electric distribution volumes are generally higher during the summer and winter months when temperature extremes create demand
for either summer cooling or winter heating. For PECO, BGE, and DPL, natural gas distribution volumes are generally higher during the winter months when
cold temperatures create demand for winter heating.
ComEd, BGE, Pepco, and DPL Maryland have electric distribution decoupling mechanisms and BGE has a natural gas decoupling mechanism that eliminate
the favorable and unfavorable impacts of weather and customer usage patterns on electric distribution and natural gas delivery volumes. As a result,
ComEd's, BGE's, Pepco's, and DPL's Maryland electric distribution revenues and BGE's natural gas distribution revenues are not materially impacted by
delivery volumes. PECO's and DPL's Delaware electric distribution revenues and natural gas distribution revenues and ACE's electric distribution revenues
are impacted by delivery volumes.
Electric and Natural Gas Distribution Services
The Utility Registrants are allowed to recover reasonable costs and fair and prudent capital expenditures associated with electric and natural gas distribution
services and earn a return on those capital expenditures, subject to commission approval. ComEd recovers costs through a performance-based rate
formula. ComEd is required to file an update to the performance-based rate formula on an annual basis. PECO's, BGE's, and DPL's electric and gas
distribution costs and Pepco's and ACE's electric distribution costs have generally been recovered through traditional rate case proceedings. However, the
MDPSC and the DCPSC allow utilities to file multi-year rate plans. In certain instances, the Utility Registrants use specific recovery mechanisms as
approved by their respective regulatory agencies.
ComEd, Pepco, and ACE customers have the choice to purchase electricity, and PECO, BGE, and DPL customers have the choice to purchase electricity
and natural gas from competitive electric generation and natural gas suppliers. The Utility Registrants remain the distribution service providers for all
customers and are obligated to deliver electricity and natural gas to customers in their respective service territories while charging a regulated rate for
distribution service. In addition, the Utility Registrants also retain significant default service obligations to provide electricity to certain groups of customers in
their respective service areas who do not choose a competitive electric generation supplier. PECO and BGE also retain significant default service obligations
to provide natural gas to certain groups of customers in their respective service areas who do not choose a competitive natural gas supplier. For natural gas,
DPL does not retain default service obligations for its residential customers.
For customers that choose to purchase electric generation or natural gas from competitive suppliers, the Utility Registrants act as the billing agent and
therefore do not record Operating revenues or Purchased power and fuel expense related to the electricity and/or natural gas. For customers that choose to
purchase electric generation or natural gas from a Utility Registrant, the Utility Registrants are permitted to recover the electricity and natural gas
procurement costs without mark-up and therefore record equal and offsetting amounts of Operating revenues and Purchased power and fuel expense
related to the electricity and/or natural gas. As a result, fluctuations in electricity or natural gas sales and procurement costs have no impact on the Utility
Registrants’ Net Income.
See ITEM 7. MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS, Results of Operations and
Note 3 — Regulatory Matters of the Combined Notes to Consolidated Financial Statements for additional information regarding electric and natural gas
distribution services.
Procurement of Electricity and Natural Gas
The Utility Registrants' electric supply for its customers is primarily procured through contracts as required by their respective state commissions. The Utility
Registrants procure electricity supply from various approved bidders, including Generation. RTO spot market purchases and sales are utilized to balance the
utility electric load and supply as required. Charges incurred for electric supply procured through contracts with Generation are included in Purchased power
from affiliates on the Utility Registrants' Statements of Operations and Comprehensive Income.
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PECO's, BGE’s, and DPL's natural gas supplies are purchased from a number of suppliers for terms of up to three years. PECO, BGE, and DPL have
annual firm supply and transportation contracts of 132,000 mmcf, 264,000 mmcf and 61,000 mmcf, respectively. In addition, to supplement gas supply at
times of heavy winter demands and in the event of temporary emergencies, PECO, BGE, and DPL have available storage capacity from the following
sources:
PECO
BGE
DPL
LNG Facility
Propane-Air Plant
Underground Storage Service Agreements
(a)
Peak Natural Gas Sources (in mmcf)
1,200
1,056
250
150
550
N/A
19,400
22,000
3,900
___________
(a) Natural gas from underground storage represents approximately 28%, 20%, and 33% of PECO's, BGE’s, and DPL's 2020-2021 heating season planned supplies,
respectively.
PECO, BGE, and DPL have long-term interstate pipeline contracts and also participate in the interstate markets by releasing pipeline capacity or bundling
pipeline capacity with gas for off-system sales. Off-system gas sales are low-margin direct sales of gas to wholesale suppliers of natural gas. Earnings from
these activities are shared between the utilities and customers. PECO, BGE, and DPL make these sales as part of a program to balance its supply and cost
of natural gas. The off-system gas sales are not material to PECO, BGE, and DPL.
See ITEM 7A. QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK, Commodity Price Risk (All Registrants), for additional
information regarding Utility Registrants' contracts to procure electric supply and natural gas.
Energy Efficiency Programs
The Utility Registrants are generally allowed to recover costs associated with the energy efficiency and demand response programs they offer. Each
commission approved program seeks to meet mandated electric consumption reduction targets and implement demand response measures to reduce peak
demand. The programs are designed to meet standards required by each respective regulatory agency.
ComEd is allowed to earn a return on its energy efficiency costs. See Note 3 — Regulatory Matters of the Combined Notes to Consolidated Financial
Statements for additional information.
Capital Investment
The Utility Registrants' businesses are capital intensive and require significant investments, primarily in electric transmission and distribution and natural gas
transportation and distribution facilities, to ensure the adequate capacity, reliability, and efficiency of their systems. See ITEM 7. MANAGEMENT'S
DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS, Liquidity and Capital Resources, for additional information
regarding projected 2021 capital expenditures.
Transmission Services
Under FERC’s open access transmission policy, the Utility Registrants, as owners of transmission facilities, are required to provide open access to their
transmission facilities under filed tariffs at cost-based rates approved by FERC. The Utility Registrants and their affiliates are required to comply with FERC’s
Standards of Conduct regulation governing the communication of non-public transmission information between the transmission owner’s employees and
wholesale merchant employees.
PJM is the regional grid operator and operates pursuant to FERC-approved tariffs. PJM is the transmission provider under, and the administrator of, the PJM
Open Access Transmission Tariff (PJM Tariff). PJM operates the PJM energy, capacity, and other markets, and, through central dispatch, controls the day-to-
day operations of the bulk power system for the region. The Utility Registrants are members of PJM and provide regional transmission service pursuant to
the PJM Tariff. The Utility Registrants and the other transmission owners in PJM have turned over control of certain of their transmission facilities to PJM,
and their transmission systems are under the dispatch control of PJM. Under the PJM Tariff, transmission service is provided on a region-wide, open-
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access basis using the transmission facilities of the PJM transmission owners at rates based on the costs of transmission service.
The Utility Registrants' transmission rates are established based on a formula that was initially approved by FERC as shown below:
Approval Date
ComEd
PECO
BGE
Pepco
DPL
ACE
Employees
January 2008
December 2019
April 2006
April 2006
April 2006
April 2006
The Registrants strive to create a workplace that is diverse, innovative, and safe for their employees. In order to provide the services and products that their
customers expect, the Registrants must create the best teams. These teams must reflect the diversity of the communities that the Registrants serve.
Therefore, the Registrants strive to attract highly qualified and diverse talent and routinely review their hiring and promotion practices to ensure they maintain
equitable and bias free processes to neutralize any unconscious bias. The Registrants provide growth opportunities, competitive compensation and benefits,
and a variety of training and development programs. The Registrants are committed to helping employees grow their skills and careers largely through
numerous training opportunities in technical, safety and business acumen areas, mentorship programs, and continuous feedback and development
discussions and evaluations. Employees are encouraged to thrive outside the workplace as well. The Registrants provide a full suite of wellness benefits
targeted at supporting work-life balance, physical, mental and financial health, and industry-leading paid leave policies.
The Registrants conduct an employee engagement survey every other year to help identify their successes and areas where they can grow. The survey
results are reviewed with senior management and the Exelon Board of Directors.
Diversity Metrics
The following tables show diversity metrics for all employees and management as of December 31, 2020:
Employees
Female
(a) (b)
(b)
People of Color
Aged <30
Aged 30-50
Aged >50
Total Employees
(c)
Exelon
Generation
ComEd
PECO
BGE
PHI
Pepco
DPL
ACE
7,993
9,298
3,268
17,119
11,953
32,340
2,492
2,083
1,363
6,712
4,407
12,482
1,517
2,432
625
3,491
2,138
6,254
727
890
279
1,292
1,227
2,798
765
1,067
273
1,694
1,172
3,139
1,281
1,748
425
2,207
1,594
4,226
366
898
183
756
517
1,456
154
194
85
466
385
936
121
139
62
369
219
650
Management
(d)
Female
(a) (b)
(b)
People of Color
Aged <30
Aged 30-50
Aged >50
Within 10 years of
retirement eligibility
Total Employees in
Management
(c)
Exelon
Generation
ComEd
PECO
BGE
PHI
Pepco
DPL
ACE
1,175
1,132
78
2,790
2,219
299
220
51
1,220
841
2,936
1,113
5,087
2,112
209
276
4
441
369
487
814
112
104
5
137
213
250
355
112
132
3
238
170
235
411
177
232
11
341
277
370
629
46
112
3
102
73
95
178
14
27
4
59
63
82
126
19
14
—
47
34
46
81
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__________
(a) The Registrants are devoted to creating an environment that allows women to stay in the workforce, grow with the company, and move up the ranks, all with parity of pay.
Exelon employs an independent third-party vendor to run regression analysis on all management positions each year. The analysis consistently shows that the Registrants
have no systemic pay equity issues.
(b) This is based on self-disclosed information.
(c) Total employees represents the sum of the aged categories.
(d) Management is defined as executive/senior level officials and managers as well as all employees who have direct reports and supervisory responsibilities.
Turnover Rates
As turnover is inherent, management succession planning is performed and tracked for all executives and critical key manager positions. Management
frequently reviews succession planning to ensure the Registrants are prepared when positions become available.
The table below shows the average turnover rate for all employees for the last three years of 2018 to 2020:
Exelon
Generation
ComEd
PECO
BGE
PHI
Pepco
DPL
ACE
Retirement Age
Voluntary
Non-Voluntary
4.13 %
2.87 %
0.97 %
4.80 %
3.88 %
0.86 %
3.69 %
1.37 %
0.61 %
2.64 %
1.55 %
1.15 %
3.64 %
1.37 %
0.97 %
4.31 %
2.18 %
0.94 %
4.90 %
2.51 %
1.78 %
3.70 %
1.10 %
0.25 %
3.37 %
1.21 %
0.63 %
Collective Bargaining Agreements
Approximately 37% of Exelon’s employees participate in CBAs. The following table presents employee information, including information about CBAs, as of
December 31, 2020:
Total Employees Covered by
CBAs
Number of CBAs
CBAs New and Renewed in
2020
(a)
Total Employees Under CBAs
New and Renewed
in 2020
Exelon
Generation
ComEd
PECO
BGE
PHI
Pepco
DPL
ACE
11,964
3,418
3,476
1,350
1,423
2,203
954
626
390
32
22
2
2
1
5
1
2
2
11
8
1
—
—
2
—
2
—
1,715
1,001
71
—
—
626
—
626
—
__________
(a) Does not include CBAs that were extended in 2020 while negotiations are ongoing for renewal.
Environmental Regulation
General
The Registrants are subject to comprehensive and complex environmental legislation and regulation at the federal, state, and local levels, including
requirements relating to climate change, air and water quality, solid and hazardous waste, and impacts on species and habitats.
The Exelon Board of Directors is responsible for overseeing the management of environmental matters. Exelon has a management team to address
environmental compliance and strategy, including the CEO; the Senior Vice President, Corporate Strategy & Chief Innovation and Sustainability Officer; the
Senior Vice President, Competitive Market Policy; and the Vice President, Corporate Environmental Strategy, as well as senior management of the
Registrants. Performance of those individuals directly involved in environmental compliance and strategy is reviewed and affects compensation as part of the
annual individual performance review process. The Exelon Board of Directors has delegated to its Generation Oversight Committee and the Corporate
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Governance Committee the authority to oversee Exelon’s compliance with health, environmental, and safety laws and regulations and its strategies and
efforts to protect and improve the quality of the environment, including Exelon’s internal climate change and sustainability policies and programs, as
discussed in further detail below. The respective Boards of the Utility Registrants oversee environmental, health, and safety issues related to these
companies.
Climate Change Mitigation
Exelon supports comprehensive federal climate legislation, including a cap-and-trade program for GHG emissions that addresses the urgent need to
substantially reduce national GHG emissions while providing appropriate protections for consumers, businesses, and the economy. In the absence of
comprehensive federal legislation, Exelon supports EPA moving forward with meaningful regulation of GHG emissions under the Clean Air Act.
The Registrants currently are subject to, and may become subject to additional, federal and/or state legislation and/or regulations addressing GHG
emissions. Generation produces electricity predominantly from low- and zero-carbon generating facilities (such as nuclear, hydroelectric, natural gas, wind,
and solar PV) and neither owns nor operates any coal-fueled generating assets. Generation’s natural gas and biomass fired generating plants produce GHG
emissions, most notably CO2. However, Generation’s owned-asset emission intensity, or rate of carbon dioxide equivalent (CO e) emitted per unit of
electricity generated, is among the lowest in the industry.
2
Other GHG emission sources associated with the Utility Registrants include natural gas (methane) leakage on the natural gas systems, sulfur hexafluoride
(SF6) leakage from electric transmission and distribution operations, refrigerant leakage from chilling and cooling equipment, and fossil fuel combustion in
motor vehicles. In addition, PECO, BGE, and DPL distribute natural gas and Generation sells natural gas at retail; and consumers’ use of such natural gas
produces GHG emissions.
International Climate Change Agreements. At the international level, the United States is a party to the United Nations Framework Convention on Climate
Change (UNFCCC). The Parties to the UNFCCC adopted the Paris Agreement at the 21st session of the UNFCCC Conference of the Parties (COP 21) on
December 12, 2015. Under the Agreement, which became effective on November 4, 2016, the parties committed to try to limit the global average
temperature increase and to develop national GHG reduction commitments. On November 4, 2020, the United States formally withdrew from the Paris
Agreement, retracting its commitment to reduce domestic GHG emissions by 26%-28% by 2025 compared with 2005 levels. However, on January 20, 2021,
President Biden accepted the Paris Agreement, which resulted in the United States’ formal re-entry on February 19, 2021. The Biden administration has
announced its intent to pursue ambitious GHG reductions in the United States and internationally.
Federal Climate Change Legislation and Regulation. It is highly uncertain whether federal legislation to significantly reduce GHG emissions will be
enacted in the near-term. If such legislation were adopted, it would likely increase the value of Exelon's low-carbon fleet even though Exelon may incur costs
either to further limit or offset the GHG emissions from its operations or to procure emission allowances or credits. Continued inaction could negatively
impact the value of Exelon’s low-carbon fleet.
The Clean Power Plan and Affordable Clean Energy Rule. The EPA’s 2015 Clean Power Plan (CPP) established regulations addressing carbon dioxide
emissions from existing fossil-fired power plants under Clean Air Act Section 111(d). The CPP’s carbon pollution limits could be met through changes to the
electric generation system, including shifting generation from higher-emitting units to lower- or zero-emitting units, as well as the development of new or
expanded zero-emissions generation. In July 2019, the EPA published its final Affordable Clean Energy rule, which repealed the CPP and replaced it with
less stringent emissions guidelines for existing fossil-fired power plants based on heat rate improvement measures that could be achieved within the fence
line of individual plants. Exelon, together with a coalition of other electric utilities, filed a lawsuit in the U.S. Court of Appeals for the D.C. Circuit on
September 6, 2019, challenging the Affordable Clean Energy rule as unlawful. This lawsuit was consolidated with separate challenges to the Affordable
Clean Energy rule filed by various states, non-governmental organizations, and business coalitions. On January 19, 2021, the U.S. Court of Appeals for the
D.C. Circuit held the Affordable Clean Energy Rule to be unlawful, vacated the rule, and remanded it to the EPA. The EPA has indicated it will promulgate
new GHG limits for existing power plants in accordance with the U.S. Court of Appeals for the D.C. Circuit's order.
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State Climate Change Legislation and Regulation. A number of states in which the Registrants operate have state and regional programs to reduce GHG
emissions and renewable and other portfolio standards, which impact the power sector. See discussion below for additional information on renewable and
other portfolio standards. As the nation’s largest generator of carbon-free electricity, Generation’s fleet supports these efforts to produce safe, reliable
electricity with minimal GHGs.
Eleven northeast and mid-Atlantic states (Connecticut, Delaware, Maine, Maryland, Massachusetts, New Hampshire, New Jersey, New York, Rhode Island,
Vermont, and Virginia) currently participate in the RGGI, which is in the process of strengthening its requirements. The program requires most fossil fuel-fired
power plants in the region to hold allowances, purchased at auction, for each ton of CO2 emissions. Non-emitting resources do not have to purchase or hold
these allowances. In October 2019, the Governor of Pennsylvania issued an Executive Order directing the PA DEP to begin a rulemaking process to allow
Pennsylvania to join the RGGI, with the goal of reducing carbon emissions from the electricity sector. On November 7, 2020, the PA DEP proposed its rule.
Broader state programs impact other sectors as well, such as New York’s Climate Leadership and Community Protection Act, which establishes statewide
emission limits; and Massachusetts’ Clean Energy and Climate Plan, which aims to reduce GHG emissions across all sectors through increased efficiency in
buildings and vehicles, the electrification of vehicles and thermal conditioning in buildings, and the replacement of carbon intensive fuels with renewable
energy sources.
While the Registrants cannot predict the nature of future regulations or how such regulations might impact future financial statements, Generation has a low
emission portfolio, and GHG restrictions would likely benefit zero- and low-emission generating units relative to higher-emission fossil fuel-fired generating
units.
In addition, Exelon facilities and operations are subject to the global impacts of climate change. Exelon believes its operations could be significantly affected
by the physical risks of climate change. See ITEM 1A. RISK FACTORS for additional information.
Renewable and Clean Energy Standards
Thirty states and the District of Columbia, incorporating the vast majority of states where Exelon operates, have adopted some form of renewable or clean
energy procurement requirement. These standards impose varying levels of mandates for procurement of renewable or clean electricity (the definition of
which varies by state) and/or energy efficiency. These are generally expressed as a percentage of annual electric load, often increasing by year. The Utility
Registrants comply with these various requirements through purchasing qualifying renewables, implementing efficiency programs, acquiring sufficient credits
(e.g., RECs), paying an alternative compliance payment, and/or a combination of these compliance alternatives. The Utility Registrants are permitted to
recover from retail customers the costs of complying with their state RPS requirements, including the procurement of RECs or other alternative energy
resources. Illinois, New York, and New Jersey adopted standards targeted at preserving the zero-carbon attributes of certain nuclear-powered generating
facilities. Generation owns multiple facilities participating in these programs within these states. Other states in which Exelon operates are considering
similar programs.
See Note 3 — Regulatory Matters of the Combined Notes to Consolidated Financial Statements for additional information.
Air Quality
Mercury and Air Toxics Standards (MATS). In 2011, the EPA signed a final rule, known as MATS, to reduce emissions of hazardous air pollutants from
power plants. MATS requires coal-fired power plants to achieve high removal rates of mercury, acid gases, and other metals, and to make capital
investments in pollution control equipment and incur higher operating expenses. In 2016, in response to a Supreme Court decision requiring the EPA to
consider costs in determining whether it was appropriate and necessary to regulate power plant emissions of hazardous air pollutants, the EPA issued a
supplemental finding that, after considering costs, it remained appropriate and necessary. On May 22, 2020, the EPA reversed course, publishing a final rule
revoking the "appropriate and necessary" finding underpinning MATS. A coal mining company filed a lawsuit in the U.S. Court of Appeals for the D.C. Circuit
seeking vacatur of MATS based on the EPA’s May 22, 2020 finding; on September 11, 2020, the U.S. Court of Appeals for the D.C. Circuit granted a motion
by Exelon and two other
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entities to intervene in that lawsuit to defend MATS, and on September 28, 2020, the U.S. Court of Appeals for the D.C. Circuit issued an Executive Order
holding this portion of the MATS litigation in abeyance. On July 21, 2020, Exelon and two other entities filed a lawsuit in the U.S. Court of Appeals for the
D.C. Circuit challenging the EPA’s May 22, 2020 rescission of the appropriate and necessary finding underpinning MATS. This portion of the case is also
being held in abeyance in response to the DOJ’s motion filed February 12, 2021. On January 20, 2021, President Biden issued an Executive Order directing
the EPA to reconsider its May 22, 2020 recission by August 2021; the EPA will likely re-affirm the finding that it is appropriate and necessary to regulate
power plant emissions of hazardous air pollutants. As a result, this litigation is likely to be rendered moot, and MATS will likely remain in place in the interim.
Water Quality
Under the federal Clean Water Act, NPDES permits for discharges into waterways are required to be obtained from the EPA or from the state environmental
agency to which the permit program has been delegated, and permits must be renewed periodically. Certain of Exelon's facilities discharge stormwater,
industrial wastewater, and/or cooling water into waterways and are therefore subject to these regulations and operate under NPDES permits.
Clean Water Act Section 316(b) is implemented through the NDPES program and requires that the cooling water intake structures at electric power plants
reflect the best technology available to minimize adverse environmental impacts. Generation’s power generation facilities with cooling water intake systems
are subject to the EPA’s Section 316(b) regulations finalized in 2014; the regulation’s requirements have been or will be addressed through renewal of these
facilities’ NPDES permits. Until the compliance requirements are determined by the applicable state permitting director on a site-specific basis for each plant,
Generation cannot estimate the effect that compliance with the EPA’s 2014 rule will have on the operation of its generating facilities and its financial
statements. Should a state permitting director determine that a facility must install cooling towers to comply with the rule, that facility’s economic viability
could be called into question. However, the final rule does not mandate cooling towers and allows state permitting directors to require alternative, less costly
technologies and/or operational measures, based on a site-specific assessment of the feasibility, costs, and benefits of available options.
On July 28, 2016, the NJDEP issued a final permit for Salem that did not require the installation of cooling towers and allows Salem to continue to operate
utilizing the existing cooling water system with certain required system modifications. However, the permit is being challenged by an environmental
organization, and if successful, could result in additional costs for Clean Water Act compliance. Potential cooling water system modification costs could be
material and could adversely impact the economic competitiveness of this facility.
Under Clean Water Act Section 404 and state laws and regulations, the Registrants may be required to obtain permits for projects involving dredge or fill
activities in Waters of the United States.
Where Registrants’ facilities are required to secure a federal license or permit for activities that may result in a discharge to covered waters, they may be
required to obtain a state water quality certification under Clean Water Act section 401.
Generation is also subject to the jurisdiction of the Delaware River Basin Commission and the Susquehanna River Basin Commission, regional agencies that
primarily regulate water usage.
Solid and Hazardous Waste and Environmental Remediation
CERCLA provides for response and removal actions coordinated by the EPA in the event of threatened releases of hazardous substances and authorizes
the EPA either to clean up sites at which hazardous substances have created actual or potential environmental hazards or to order persons responsible for
the situation to do so. Under CERCLA, generators and transporters of hazardous substances, as well as past and present owners and operators of
hazardous waste sites, are strictly, jointly and severally liable for the cleanup costs of hazardous waste at sites, many of which are listed by the EPA on the
National Priorities List (NPL). These PRPs can be ordered to perform a cleanup, can be sued for costs associated with an EPA-directed cleanup, may
voluntarily settle with the EPA concerning their liability for cleanup costs, or may voluntarily begin a site investigation and site remediation under state
oversight. Most states have also enacted statutes that contain provisions substantially similar to CERCLA. Such statutes apply in many states where the
Registrants currently own or
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operate, or previously owned or operated, facilities, including Delaware, Illinois, Maryland, New Jersey, and Pennsylvania and the District of Columbia. In
addition, RCRA governs treatment, storage and disposal of solid and hazardous wastes and cleanup of sites where such activities were conducted.
The Registrants’ operations have in the past, and may in the future, require substantial expenditures in order to comply with these Federal and state
environmental laws. Under these laws, the Registrants may be liable for the costs of remediating environmental contamination of property now or formerly
owned by them and of property contaminated by hazardous substances generated by them. The Registrants own or lease a number of real estate parcels,
including parcels on which their operations or the operations of others may have resulted in contamination by substances that are considered hazardous
under environmental laws. The Registrants and their subsidiaries are, or could become in the future, parties to proceedings initiated by the EPA, state
agencies, and/or other responsible parties under CERCLA and RCRA or similar state laws with respect to a number of sites or may undertake to investigate
and remediate sites for which they may be subject to enforcement actions by an agency or third-party.
ComEd’s and PECO’s environmental liabilities primarily arise from contamination at former MGP sites. ComEd, pursuant to an ICC order, and PECO,
pursuant to settlements of natural gas distribution rate cases with the PAPUC, have an on-going process to recover environmental remediation costs of the
MGP sites through a provision within customer rates. BGE, ACE, Pepco, and DPL do not have material contingent liabilities relating to MGP sites. The
amount to be expended in 2021 for compliance with environmental remediation related to contamination at former MGP sites and other gas purification sites
is estimated to be approximately $35 million which consists primarily of $30 million at ComEd.
As of December 31, 2020, the Registrants have established appropriate contingent liabilities for environmental remediation requirements. In addition, the
Registrants may be required to make significant additional expenditures not presently determinable for other environmental remediation costs.
See Note 3 — Regulatory Matters and Note 19 — Commitments and Contingencies of the Combined Notes to Consolidated Financial Statements for
additional information regarding the Registrants’ environmental matters, remediation efforts, and related impacts to the Registrants’ Consolidated Financial
Statements.
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Information about our Executive Officers as of February 24, 2021
Exelon
Name
Crane, Christopher M.
Position
Age
62 Chief Executive Officer, Exelon;
President, Exelon
Cornew, Kenneth W.
55 Senior Executive Vice President and Chief Commercial Officer, Exelon;
Butler, Calvin G.
President and CEO, Generation
51 Senior Executive Vice President, Exelon; Chief Executive Officer, Exelon
Utilities
Chief Executive Officer, BGE
Dominguez, Joseph
58 Chief Executive Officer, ComEd
Executive Vice President, Governmental & Regulatory Affairs and Public
Policy, Exelon
Glockner, David
60 Executive Vice President, Compliance and Audit, Exelon
Chief Compliance Officer, Citadel LLC
Regional Director, U.S. Securities and Exchange Commission
Hanson, Bryan C.
55 Executive Vice President and Chief Generation Officer, Generation
President and Chief Nuclear Officer, Exelon Nuclear; Senior Vice President,
Generation
Innocenzo, Michael A.
55 President and Chief Executive Officer, PECO
Senior Vice President and Chief Operations Officer, PECO
Khouzami, Carim V.
45 Chief Executive Officer, BGE
Senior Vice President, Chief Operating Officer, Exelon Utilities
Senior Vice President, Chief Financial Officer, Exelon Utilities
Senior Vice President, Chief Integration Officer, Exelon
Velazquez, David M.
61 President and Chief Executive Officer, PHI
President and Chief Executive Officer, Pepco, DPL, and ACE
Executive Vice President, Pepco Holdings, Inc.
Von Hoene Jr., William A.
67 Senior Executive Vice President and Chief Strategy Officer, Exelon
Period
2012 - Present
2008 - Present
2013 - Present
2013 - Present
2019 - Present
2014 - 2019
2018 - Present
2015 - 2018
2020 - Present
2017 - 2020
2013 - 2017
2020 - Present
2015 - 2020
2018 - Present
2012 - 2018
2019 - Present
2018 - 2019
2016 - 2018
2014 - 2016
2016 - Present
2009 - Present
2009 - 2016
2012 - Present
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Name
Nigro, Joseph
Age
Position
56 Senior Executive Vice President and Chief Financial Officer, Exelon
Executive Vice President, Exelon; Chief Executive Officer, Constellation
Souza, Fabian E.
50 Senior Vice President and Corporate Controller, Exelon
Senior Vice President and Deputy Controller, Exelon
Vice President, Controller and Chief Accounting Officer, The AES
Corporation
Generation
Name
Crane, Christopher M.
Position
Age
62 Principle Executive Officer, Generation
Chief Executive Officer, Exelon;
President, Exelon
Cornew, Kenneth W.
55 Senior Executive Vice President and Chief Commercial Officer, Exelon;
President and Chief Executive Officer, Generation
Period
2018 - Present
2013 - 2018
2018 - Present
2017 - 2018
2015 - 2017
Period
2020 - Present
2012 - Present
2008 - Present
2013 - Present
2013 - Present
Swahl, William
51 Senior Vice President, Generation; Chief Operating Officer, Exelon Power
2021 - Present
Vice President, Generation; Vice President, Mid-Atlantic Operations, Exelon
Power
2014 - 2020
Hanson, Bryan C.
55 Executive Vice President and Chief Generation Officer, Generation
2020 - Present
McHugh, James
Rhoades, David
Wright, Bryan P.
Bauer, Matthew N.
President and Chief Nuclear Officer, Exelon Nuclear, Senior Vice President,
Generation
2015 - 2020
49 Executive Vice President, Exelon; Chief Executive Officer, Constellation
Senior Vice President, Portfolio Management & Strategy, Constellation
Vice President, Portfolio Management, Constellation
54 Senior Vice President, Generation; President and Chief Nuclear Officer,
Exelon Nuclear
Chief Operating Officer, Fleet Operations, Exelon Nuclear
54 Senior Vice President and Chief Financial Officer, Generation
44 Vice President and Controller, Generation
Vice President and Controller, BGE
2018 - Present
2016 - 2018
2012 - 2016
2020 - Present
2015 - 2020
2013 - Present
2016 - Present
2014 - 2016
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ComEd
Name
Dominguez, Joseph
Position
Age
58 Chief Executive Officer, ComEd
Donnelly, Terence R.
60 President and Chief Operating Officer, ComEd
Executive Vice President and Chief Operating Officer, ComEd
Jones, Jeanne M.
41 Senior Vice President, Chief Financial Officer and Treasurer, ComEd
Executive Vice President, Governmental & Regulatory Affairs and Public
Policy, Exelon
Park, Jane
Gomez, Veronica
Washington, Melissa
Perez, David
Vice President, Finance, Exelon Nuclear
48 Senior Vice President, Customer Operations, ComEd
Vice President, Regulatory Policy & Strategy, ComEd
Director, Business Strategy & Technology, ComEd
51 Senior Vice President, Regulatory and Energy Policy and General Counsel,
ComEd
Vice President and Deputy General Counsel, Litigation, Exelon
51 Senior Vice President, Governmental and External Affairs, ComEd
Vice President, Governmental and External Affairs, ComEd
Vice President, External Affairs and Large Customer Services, ComEd
Vice President, Corporate Affairs, Exelon Business Services Company
51 Senior Vice President, Distribution Operations, ComEd
Vice President, Transmission and Substation, ComEd
Vice President, Regional Operations, ComEd
Period
2018 - Present
2015 - 2018
2018 - Present
2012 - 2018
2018 - Present
2014 - 2018
2018 - Present
2016 - 2018
2014 - 2016
2017 - Present
2012 - 2017
2019 - Present
2019 -2019
2016 - 2019
2014 - 2016
2019 - Present
2016 - 2019
2010 - 2016
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PECO
Name
Innocenzo, Michael A.
Position
Age
55 President and Chief Executive Officer, PECO
Senior Vice President and Chief Operations Officer, PECO
McDonald, John
63 Senior Vice President and Chief Operations Officer, PECO
Vice President, Integration, PHI
Vice President, Technical Services
Stefani, Robert J.
47 Senior Vice President, Chief Financial Officer and Treasurer, PECO
Murphy, Elizabeth A.
Webster Jr., Richard G.
Williamson, Olufunmilayo
Vice President, Corporate Development, Exelon
61 Senior Vice President, Governmental and External Affairs, PECO
Vice President, Governmental and External Affairs, PECO
59 Vice President, Regulatory Policy and Strategy, PECO
42 Senior Vice President, Customer Operations, PECO
Senior Vice President, Chief Commercial Risk Officer, Exelon
Vice President, Commercial Risk Management, Exelon
Gay, Anthony
55 Vice President and General Counsel, PECO
Vice President, Governmental and External Affairs, PECO
Associate General Counsel, Exelon
Period
2018 - Present
2012 - 2018
2018 - Present
2016 - 2018
2006 - 2016
2018 - Present
2015 - 2018
2016 - Present
2012 - 2016
2012 - Present
2020 - Present
2017 - 2020
2015 - 2017
2019 - Present
2016 - 2019
2010 - 2016
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BGE
Name
Khouzami, Carim V.
Position
Age
45 Chief Executive Officer, BGE
Senior Vice President, Chief Operating Officer, Exelon Utilities
Senior Vice President, Chief Financial Officer, Exelon Utilities
Senior Vice President, Chief Integration Officer, Exelon
Woerner, Stephen J.
53 President, BGE
Vahos, David M.
Núñez, Alexander G.
Case, Mark D.
Oddoye, Rodney
Chief Operating Officer, BGE
48 Senior Vice President, Chief Financial Officer and Treasurer, BGE
Vice President, Chief Financial Officer and Treasurer, BGE
49 Senior Vice President, Regulatory Affairs and Strategy, BGE
Senior Vice President, Regulatory and External Affairs, BGE
Vice President, Governmental and External Affairs, BGE
59 Vice President, Strategy and Regulatory Affairs, BGE
44 Senior Vice President, Governmental and External Affairs, BGE
Vice President, Customer Operations, BGE
Director, Northeast Regional Electric Operations, BGE
Director, Financial Operations, BGE
Olivier, Tamla
48 Senior Vice President, Customer Operations, BGE
Senior Vice President, Constellation NewEnergy, Inc.
VP, Human Resources, Exelon Business Services Company
Corse, John
60 Vice President and General Counsel, BGE
Associate General Counsel, Exelon
Period
2019 - Present
2018 - 2019
2016 - 2018
2014 - 2016
2014 - Present
2012 - Present
2016 - Present
2014 - 2016
2020 - Present
2016 - 2020
2013 - 2016
2012 - Present
2020 - Present
2018 - 2020
2016 - 2018
2015 - 2016
2020 - Present
2016 - 2020
2012 - 2016
2018 - Present
2012 - 2018
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PHI, Pepco, DPL, and ACE
Name
Velazquez, David M.
Position
Age
61 President and Chief Executive Officer, PHI
Executive Vice President, Pepco Holdings, Inc.
President and Chief Executive Officer, Pepco, DPL, and ACE
Anthony, J. Tyler
56 Senior Vice President and Chief Operating Officer, PHI, Pepco, DPL, and
Barnett, Phillip S.
Lavinson, Melissa
Stark, Wendy E.
ACE
Senior Vice President, Distribution Operations, ComEd
57 Senior Vice President, Chief Financial Officer and Treasurer, PHI, Pepco,
DPL, and ACE
Senior Vice President and Chief Financial Officer, PECO
Treasurer, PECO
51 Senior Vice President, Governmental & External Affairs, PHI, Pepco, DPL,
and ACE
Vice President, Federal Affairs and Policy and Chief Sustainability Officer,
PG&E Corporation
48 Senior Vice President, Legal and Regulatory Strategy and General Counsel,
PHI, Pepco, DPL, and ACE
Vice President and General Counsel, PHI, Pepco, DPL, and ACE
Deputy General Counsel, Pepco Holdings, Inc.
McGowan, Kevin M.
59 Vice President, Regulatory Policy and Strategy, PHI, Pepco, DPL, and ACE
Vice President, Regulatory Affairs, Pepco Holdings, Inc.
Dickens, Derrick
56 Senior Vice President, Customer Operations, PHI
Vice President, Technical Services, BGE
Director, Advanced Meter Infrastructure, PECO
Humphrey, Marissa
41 Vice President, Regulatory Policy and Strategy, PHI, DPL, and ACE
Vice President Finance, Exelon Utilities
Vice President, Finance, PHI
ITEM 1A.
RISK FACTORS
Period
2016 - Present
2009 - 2016
2009 - Present
2016 - Present
2010 - 2016
2018 - Present
2007 - 2018
2012 - 2018
2018 - Present
2015 - 2018
2019 - Present
2016 - 2018
2012 - 2016
2016 - Present
2012 - 2016
2020 - Present
2016 - 2020
2012 - 2016
2021 - Present
2019 - 2020
2016 - 2019
Each of the Registrants operates in a complex market and regulatory environment that involves significant risks, many of which are beyond that Registrant’s
direct control. Such risks, which could negatively affect one or more of the Registrants’ consolidated financial statements, fall primarily under the categories
below:
Market and Financial Factors primarily include:
•
•
•
the price of fuels, in particular the price of natural gas, which affects power prices,
the generation resources in the markets in which the Registrants operate,
the demand for electricity, reliability of service, and affordability in the markets where the Registrants conduct their business,
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•
•
•
the ability of the Registrants to operate their respective generating and transmission and distribution assets, their ability to access capital markets,
and the impacts on their results of operations due to the global outbreak (pandemic) of the 2019 novel coronavirus (COVID-19),
the impacts of on-going competition, and
emerging technologies and business models, including those related to climate change mitigation and transition to a low carbon economy.
Regulatory, Legislative, and Legal Factors primarily include changes to, and compliance with, the laws and regulations that govern:
•
•
•
•
•
the design of power markets,
ZEC programs,
utility regulatory business models,
environmental and climate policy, and
tax policy.
Operational Factors primarily include:
•
•
•
•
changes in the global climate could produce extreme weather events, which could put the Registrant’s facilities at risk, and such changes could also
affect the levels and patterns of demand for energy and related services,
the safe, secure, and effective operation of Generation’s nuclear facilities and the ability to effectively manage the associated decommissioning
obligations,
the ability of the Registrants to maintain the reliability, resiliency, and safety of their energy delivery systems, which could affect the operating costs
of the Registrants and the opinions of their customers and regulators, and
physical and cyber security risks for the Registrants as the owner-operators of generation, transmission, and distribution facilities and as
participants in commodities trading.
Risks Related to the Planned Separation primarily include:
•
•
•
the timing and conditions associated with required regulatory approvals, which may affect the costs to achieve the separation and its timing,
challenges to achieving the benefits of separation, including maintaining investment grade credit ratings, and
the risk that the separation could be treated as a taxable transaction to both Exelon and its shareholders.
There may be further risks and uncertainties that are not presently known or that are not currently believed by the Registrants to be material that could
negatively affect its consolidated financial statements in the future.
Market and Financial Factors
Generation is exposed to price volatility associated with both the wholesale and retail power markets and the procurement of
nuclear and fossil fuel (Exelon and Generation).
Generation is exposed to commodity price risk for the unhedged portion of its electricity generation supply portfolio. Generation’s earnings and cash flows
are therefore exposed to variability of spot and forward market prices in the markets in which it operates.
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Price of Fuels. The spot market price of electricity for each hour is generally determined by the marginal cost of supplying the next unit of electricity to the
market during that hour. Thus, the market price of power is affected by the market price of the marginal fuel used to generate the electricity unit.
Demand and Supply. The market price for electricity is also affected by changes in the demand for electricity and the available supply of
electricity. Unfavorable economic conditions, milder than normal weather, and the growth of energy efficiency and demand response programs could each
depress demand. In addition, in some markets, the supply of electricity could often exceed demand during some hours of the day, resulting in loss of
revenue for base-load generating plants such as Generation's nuclear plants. Conversely, new demand sources such as electrification of transportation
could increase demand and change demand patterns.
Retail Competition. Generation’s retail operations compete for customers in a competitive environment, which affects the margins that Generation can earn
and the volumes that it is able to serve. In periods of sustained low natural gas and power prices and low market volatility, retail competitors can aggressively
pursue market share because the barriers to entry can be low and wholesale generators (including Generation) use their retail operations to hedge
generation output.
The impact of sustained low market prices or depressed demand and over-supply could be emphasized given Generation’s concentration of base-load
electric generating capacity within primarily two geographic market regions, namely the Midwest and the Mid-Atlantic. These impacts could adversely affect
Generation’s ability to fund regulated utility growth for the benefit of customers, reduce debt and provide attractive shareholder returns. In addition, such
conditions may no longer support the continued operation of certain generating facilities, which could adversely affect Generation's financial statements
primarily through accelerated depreciation and amortization expenses and one-time charges. See Note 7 — Early Plant Retirements of the Combined Notes
to Consolidated Financial Statements for additional information.
Cost of Fuel. Generation depends on nuclear fuel and fossil fuels to operate most of its generating facilities. The supply markets for nuclear fuel, natural
gas, and oil are subject to price fluctuations, availability restrictions, and counterparty default.
Market Designs. The wholesale markets vary from region to region with distinct rules, practices, and procedures. Changes in these market rules, problems
with rule implementation, or failure of any of these markets could adversely affect Generation’s business. In addition, a significant decrease in market
participation could affect market liquidity and have a detrimental effect on market stability.
The Registrants are potentially affected by emerging technologies that could over time affect or transform the energy industry (All
Registrants).
Some of these technologies include, but are not limited to, further development or applications of technologies related to shale gas production, renewable
energy technologies, energy efficiency, distributed generation, and energy storage devices. Such developments could affect the price of energy, levels of
customer-owned generation, customer expectations, and current business models and make portions of our electric system power supply and transmission
and/or distribution facilities obsolete prior to the end of their useful lives. Such technologies could also result in further declines in commodity prices or
demand for delivered energy. Each of these factors could affect the Registrants’ consolidated financial statements through, among other things, reduced
operating revenues, increased operating and maintenance expenses, increased capital expenditures, and potential asset impairment charges or accelerated
depreciation and decommissioning expenses over shortened remaining asset useful lives.
Market performance and other factors could decrease the value of NDT funds and employee benefit plan assets and could increase
the related employee benefit plan obligations, which then could require significant additional funding (All Registrants).
Disruptions in the capital markets and their actual or perceived effects on particular businesses and the greater economy could adversely affect the value of
the investments held within Generation’s NDTs and Exelon’s employee benefit plan trusts. The Registrants have significant obligations in these areas and
Exelon and Generation hold substantial assets in these trusts to meet those obligations. The asset values are subject to market fluctuations and will yield
uncertain returns, which could fall below the Registrants’ projected return rates. A decline in the market value of the NDT fund investments could increase
Generation’s funding requirements to
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decommission its nuclear plants. A decline in the market value of the pension and OPEB plan assets would increase the funding requirements associated
with Exelon’s pension and OPEB plan obligations. Additionally, Exelon’s pension and OPEB plan liabilities are sensitive to changes in interest rates. As
interest rates decrease, the liabilities increase, potentially increasing benefit costs and funding requirements. Changes in demographics, including increased
numbers of retirements or changes in life expectancy assumptions or changes to Social Security or Medicare eligibility requirements could also increase the
costs and funding requirements of the obligations related to the pension and OPEB plans. See Note 10 — Asset Retirement Obligations and Note 15 —
Retirement Benefits of the Combined Notes to Consolidated Financial Statements for additional information.
The Registrants could be negatively affected by unstable capital and credit markets and increased volatility in commodity markets
(All Registrants).
The Registrants rely on the capital markets, particularly for publicly offered debt, as well as the banking and commercial paper markets, to meet their
financial commitments and short-term liquidity needs. Disruptions in the capital and credit markets in the United States or abroad could negatively affect the
Registrants’ ability to access the capital markets or draw on their respective bank revolving credit facilities. The banks may not be able to meet their funding
commitments to the Registrants if they experience shortages of capital and liquidity or if they experience excessive volumes of borrowing requests within a
short period of time. The inability to access capital markets or credit facilities, and longer-term disruptions in the capital and credit markets as a result of
uncertainty, changing or increased regulation, reduced alternatives, or failures of significant financial institutions could result in the deferral of discretionary
capital expenditures, Generation’s ability to hedge effectively its generation portfolio, changes to Generation’s hedging strategy in order to reduce collateral
posting requirements, or a reduction in dividend payments or other discretionary uses of cash. In addition, the Registrants have exposure to worldwide
financial markets, including Europe, Canada, and Asia. Disruptions in these markets could reduce or restrict the Registrants’ ability to secure sufficient
liquidity or secure liquidity at reasonable terms. As of December 31, 2020, approximately 23%, 19%, and 18% of the Registrants’ available credit facilities
were with European, Canadian, and Asian banks, respectively. See Note 17 — Debt and Credit Agreements of the Combined Notes to Consolidated
Financial Statements for additional information on the credit facilities.
The strength and depth of competition in energy markets depend heavily on active participation by multiple trading parties, which could be negatively
affected by disruptions in the capital and credit markets and legislative and regulatory initiatives that could affect participants in commodities transactions.
Reduced capital and liquidity and failures of significant institutions that participate in the energy markets could diminish the liquidity and competitiveness of
energy markets that are important to the respective businesses of the Registrants. Perceived weaknesses in the competitive strength of the energy markets
could lead to pressures for greater regulation of those markets or attempts to replace market structures with other mechanisms for the sale of power,
including the requirement of long-term contracts.
If any of the Registrants were to experience a downgrade in its credit ratings to below investment grade or otherwise fail to satisfy
the credit standards in its agreements with its counterparties, it would be required to provide significant amounts of collateral
under its agreements with counterparties and could experience higher borrowing costs (All Registrants).
Generation’s business is subject to credit quality standards that could require market participants to post collateral for their obligations. If Generation were to
be downgraded or lose its investment grade credit rating (based on its senior unsecured debt rating) or otherwise fail to satisfy the credit standards of trading
counterparties, it would be required under its hedging arrangements to provide collateral in the form of letters of credit or cash, which could have a material
adverse effect upon its liquidity. The amount of collateral required to be provided by Generation at any point in time depends on a variety of factors, including
(1) the notional amount of the applicable hedge, (2) the nature of counterparty and related agreements, and (3) changes in power or other commodity prices.
In addition, if Generation were downgraded, it could experience higher borrowing costs as a result of the downgrade. Changes in ratings methodologies by
the credit rating agencies could also have a negative impact on the ratings of Generation.
Generation has project-specific financing arrangements and must meet the requirements of various agreements relating to those financings. Failure to meet
those arrangements could give rise to a project-specific financing default which, if not cured or waived, could result in the specific project being required to
repay the associated
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debt or other borrowings earlier than otherwise anticipated, and if such repayment were not made, the lenders or security holders would generally have
broad remedies, including rights to foreclose against the project assets and related collateral or to force the Exelon subsidiaries in the project-specific
financings to enter into bankruptcy proceedings. The impact of bankruptcy could result in the impairment of certain project assets.
The Utility Registrants' operating agreements with PJM and PECO's, BGE's, and DPL's natural gas procurement contracts contain collateral provisions that
are affected by their credit rating and market prices. If certain wholesale market conditions were to exist and the Utility Registrants were to lose their
investment grade credit ratings (based on their senior unsecured debt ratings), they would be required to provide collateral in the forms of letters of credit or
cash, which could have a material adverse effect upon their remaining sources of liquidity. PJM collateral posting requirements will generally increase as
market prices rise and decrease as market prices fall. Collateral posting requirements for PECO, BGE, and DPL, with respect to their natural gas supply
contracts, will generally increase as forward market prices fall and decrease as forward market prices rise. If the Utility Registrants were downgraded, they
could experience higher borrowing costs as a result of the downgrade. In addition, changes in ratings methodologies by the agencies could also have an
adverse negative impact on the ratings of the Utility Registrants.
The Utility Registrants conduct their respective businesses and operate under governance models and other arrangements and procedures intended to
assure that the Utility Registrants are treated as separate, independent companies, distinct from Exelon and other Exelon subsidiaries in order to isolate the
Utility Registrants from Exelon and other Exelon subsidiaries in the event of financial difficulty at Exelon or another Exelon subsidiary. These measures
(commonly referred to as “ring-fencing”) could help avoid or limit a downgrade in the credit ratings of the Utility Registrants in the event of a reduction in the
credit rating of Exelon. Despite these ring-fencing measures, the credit ratings of the Utility Registrants could remain linked, to some degree, to the credit
ratings of Exelon. Consequently, a reduction in the credit rating of Exelon could result in a reduction of the credit rating of some or all of the Utility
Registrants. A reduction in the credit rating of a Utility Registrant could have a material adverse effect on the Utility Registrant.
See ITEM 7. MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS — Liquidity and Capital
Resources — Credit Matters — Market Conditions and Security Ratings for additional information regarding the potential impacts of credit downgrades on
the Registrants’ cash flows.
Generation’s risk management policies cannot fully eliminate the risk associated with its commodity trading activities (Exelon and
Generation).
Generation’s asset-based power position as well as its power marketing, fuel procurement, and other commodity trading activities expose Generation to risks
of commodity price movements. Generation buys and sells energy and other products and enters into financial contracts to manage risk and hedge various
positions in Generation’s power generation portfolio. Generation is exposed to volatility in financial results for unhedged positions as well as the risk of
ineffective hedges. Generation attempts to manage this exposure through enforcement of established risk limits and risk management procedures. These
risk limits and risk management procedures may not work as planned and cannot eliminate all risks associated with these activities. Even when its policies
and procedures are followed, and decisions are made based on projections and estimates of future performance, results of operations could be diminished if
the judgments and assumptions underlying those decisions prove to be incorrect. Factors, such as future prices and demand for power and other energy-
related commodities, become more difficult to predict and the calculations become less reliable the further into the future estimates are made. As a result,
Generation cannot predict the impact that its commodity trading activities and risk management decisions could have on its consolidated financial
statements.
Financial performance and load requirements could be negatively affected if Generation is unable to effectively manage its power
portfolio (Exelon and Generation).
A significant portion of Generation’s power portfolio is used to provide power under procurement contracts with the Utility Registrants and other customers.
To the extent portions of the power portfolio are not needed for that purpose, Generation’s output is sold in the wholesale power markets. To the extent its
power portfolio is not sufficient to meet the requirements of its customers under the related agreements, Generation must purchase power in the wholesale
power markets. Generation’s financial results could be negatively affected if it is unable to cost-effectively meet the load requirements of its customers,
manage its power portfolio or effectively address the changes in the wholesale power markets.
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The impacts of significant economic downturns or increases in customer rates, could lead to decreased volumes delivered and
increased expense for uncollectible customer balances (All Registrants).
The impacts of significant economic downturns on the Utility Registrants' customers, such as less demand for products and services provided by commercial
and industrial customers, and the related regulatory limitations on residential service terminations, could result in an increase in the number of uncollectible
customer balances. Further, increases in customer rates, including those related to increases in purchased power and natural gas prices, could result in
declines in customer usage and lower revenues for the Utility Registrants that do not have decoupling mechanisms.
Generation's customer-facing energy delivery activities face similar economic downturn risks, such as lower volumes sold and increased expense for
uncollectible customer balances.
See ITEM 7A. QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK for additional information of the Registrants’ credit risk.
The Registrants' results could be negatively affected by the impacts of COVID-19 (All Registrants).
COVID-19 is an evolving situation that could lead to extended disruption of economic activity in the Registrants’ respective markets. COVID-19 could
negatively affect the Registrants’ ability to operate their respective generating and transmission and distribution assets, their ability to access capital markets,
and their results of operations. The Registrants cannot predict the extent of the impacts of COVID-19, which will depend on future developments and which
are highly uncertain. See Item 7. MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS -
Executive Overview for additional information.
The Registrants could be negatively affected by the impacts of weather (All Registrants).
Weather conditions directly influence the demand for electricity and natural gas and affect the price of energy commodities. Temperatures above normal
levels in the summer tend to increase summer cooling electricity demand and revenues, and temperatures below normal levels in the winter tend to increase
winter heating electricity and gas demand and revenues. Moderate temperatures adversely affect the usage of energy and resulting revenues at PECO, DPL
Delaware, and ACE. Due to revenue decoupling, BGE, Pepco, and DPL Maryland recognize revenues at MDPSC and DCPSC-approved levels per
customer, regardless of what actual distribution volumes are for a billing period and are not affected by actual weather with the exception of major storms.
ComEd’s customer rates are adjusted to eliminate the favorable and unfavorable impacts of weather and customer usage patterns on distribution revenue.
Extreme weather conditions or damage resulting from storms could stress the Utility Registrants' transmission and distribution systems, communication
systems, and technology, resulting in increased maintenance and capital costs and limiting each company’s ability to meet peak customer demand. First and
third quarter financial results, in particular, are substantially dependent on weather conditions, and could make period comparisons less relevant.
Generation’s operations are also affected by weather, which affects demand for electricity as well as operating conditions. To the extent that weather is
warmer in the summer or colder in the winter than assumed, Generation could require greater resources to meet its contractual commitments. Extreme
weather conditions or storms could affect the availability of generation and its transmission, limiting Generation’s ability to source or send power to where it is
sold. In addition, drought-like conditions limiting water usage could impact Generation’s ability to run certain generating assets at full capacity. These
conditions, which cannot be accurately predicted, could cause Generation to seek additional capacity at a time when wholesale markets are tight or to seek
to sell excess capacity at a time when markets are weak.
Climate change projections suggest increases to summer temperature and humidity trends, as well as more erratic precipitation and storm patterns over the
long-term in the areas where Registrants have generation, transmission, and distribution assets. The frequency in which weather conditions emerge outside
the current expected climate norms could contribute to weather-related impacts discussed above.
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Long-lived assets, goodwill, and other assets could become impaired (All Registrants).
Long-lived assets represent the single largest asset class on the Registrants’ statements of financial position. In addition, Exelon, ComEd, and PHI have
material goodwill balances.
The Registrants evaluate the recoverability of the carrying value of long-lived assets to be held and used whenever events or circumstances indicating a
potential impairment exist. Factors such as, but not limited to, the business climate, including current and future energy and market conditions,
environmental regulation, and the condition of assets are considered.
ComEd and PHI perform an assessment for possible impairment of their goodwill at least annually or more frequently if an event occurs or circumstances
change that would more likely than not reduce the fair value of the reporting units below their carrying amount. Regulatory actions or changes in significant
assumptions, including discount and growth rates, utility sector market performance and transactions, projected operating and capital cash flows for
ComEd’s, Pepco’s, DPL’s, and ACE’s business, and the fair value of debt, could potentially result in future impairments of Exelon’s, ComEd's, and PHI’s
goodwill.
An impairment would require the Registrants to reduce the carrying value of the long-lived asset or goodwill to fair value through a non-cash charge to
expense by the amount of the impairment. See ITEM 7. MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF
OPERATIONS — Critical Accounting Policies and Estimates, Note 8 — Property, Plant, and Equipment, Note 12 — Asset Impairments and Note 13 —
Intangible Assets of the Combined Notes to the Consolidated Financial Statements for additional information on long-lived asset impairments and goodwill
impairments.
The Registrants could incur substantial costs in the event of non-performance by third-parties under indemnification agreements,
or when the Registrants have guaranteed their performance. Generation is exposed to other credit risks in the power markets that
are beyond its control (All Registrants).
The Registrants have entered into various agreements with counterparties that require those counterparties to reimburse a Registrant and hold it harmless
against specified obligations and claims. To the extent that any of these counterparties are affected by deterioration in their creditworthiness or the
agreements are otherwise determined to be unenforceable, the affected Registrant could be held responsible for the obligations. Each of the Utility
Registrants has transferred its former generation business to a third party and in each case the transferee has agreed to assume certain obligations and to
indemnify the applicable Utility Registrant for such obligations. In connection with the restructurings under which ComEd, PECO, and BGE transferred their
generating assets to Generation, Generation assumed certain of ComEd’s, PECO’s, and BGE's rights and obligations with respect to their former generation
businesses. Further, ComEd, PECO, and BGE have entered into agreements with third parties under which the third-party agreed to indemnify ComEd,
PECO, or BGE for certain obligations related to their respective former generation businesses that have been assumed by Generation as part of the
restructuring. If the third-party, Generation, or the transferee of Pepco's, DPL's, or ACE’s generation facilities experienced events that reduced its
creditworthiness or the indemnity arrangement became unenforceable, the applicable Utility Registrant could be liable for any existing or future claims. In
addition, the Utility Registrants have residual liability under certain laws in connection with their former generation facilities.
The Registrants have issued indemnities to third parties regarding environmental or other matters in connection with purchases and sales of assets and they
could incur substantial costs to fulfill their obligations under these indemnities.
The Registrants have issued guarantees of the performance of third parties, which obligate the Registrants to perform in the event that the third parties do
not perform. In the event of non-performance by those third parties, the Registrants could incur substantial cost to fulfill their obligations under these
guarantees.
In the bilateral markets, Generation is exposed to the risk that counterparties that owe Generation money or are obligated to purchase energy or fuel from
Generation, will not perform under their obligations for operational or financial reasons. In the event the counterparties to these arrangements fail to perform,
Generation could be forced to purchase or sell energy or fuel in the wholesale markets at less favorable prices and incur additional losses, to the extent
amounts, if any, were already paid to the counterparties. In the spot markets, Generation is
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exposed to risk as a result of default sharing mechanisms that exist within certain markets, primarily RTOs and ISOs. Generation is also a party to
agreements with entities in the energy sector that have experienced rating downgrades or other financial difficulties. In addition, Generation’s retail sales
subject it to credit risk through competitive electricity and natural gas supply activities to serve commercial and industrial companies, governmental entities
and residential customers. Retail credit risk results when customers default on their contractual obligations. This risk represents the loss that could be
incurred due to the nonpayment of a customer’s account balance, as well as the loss from the resale of energy previously committed to serve the customer.
Regulatory, Legislative, and Legal Factors
Federal or state legislative or regulatory actions could negatively affect the scope and functioning of the wholesale markets
(Exelon and Generation).
Approximately 70% of Generation’s generating resources, which include directly owned assets and capacity obtained through long-term contracts, are
located in the area encompassed by PJM. Generation’s future results of operations are impacted by (1) FERC’s and PJM's support for policies that favor the
preservation of competitive wholesale power markets and recognize the value of zero-carbon electricity and resiliency and for states' energy objectives and
policies (2) the absence of material changes to market structures that would limit or otherwise negatively affect Exelon or Generation. Generation could also
be affected by state laws, regulations, or initiatives to subsidize existing or new generation.
FERC’s requirements for market-based rate authority could pose a risk that Generation may no longer satisfy FERC’s tests for market-based rates.
The Registrants’ are highly regulated and could be negatively affected by regulatory and legislative actions (All Registrants).
Substantially all aspects of the businesses of the Registrants are subject to comprehensive Federal or state regulation and legislation.
Generation’s consolidated financial statements are significantly affected by its sales and purchases of commodities at market-based rates, as opposed to
cost-based or other similarly regulated rates and Federal and state regulatory and legislative developments related to emissions, climate change, capacity
market mitigation, energy price information, resilience, fuel diversity, and RPS. Legislative and regulatory efforts in Illinois, New York, and New Jersey to
preserve the environmental attributes and reliability benefits of zero-emission nuclear-powered generating facilities through ZEC programs are or could be
subject to legal and regulatory challenges and, if overturned, could result in the early retirement of certain of Generation’s nuclear plants. See Note 3 —
Regulatory Matters and Note 7 — Early Plant Retirements of the Combined Notes to Consolidated Financial Statements for additional information.
The Utility Registrants' consolidated financial statements are heavily dependent on the ability of the Utility Registrants to recover their costs for the retail
purchase and distribution of power and natural gas to their customers.
Fundamental changes in regulations or other adverse legislative actions affecting the Registrants’ businesses would require changes in their business
planning models and operations. The Registrants cannot predict when or whether legislative and regulatory proposals could become law or what their effect
will be on the Registrants.
Changes in the Utility Registrants' respective terms and conditions of service, including their respective rates, are subject to
regulatory approval proceedings and/or negotiated settlements that are at times contentious, lengthy, and subject to appeal, which
lead to uncertainty as to the ultimate result and which could introduce time delays in effectuating rate changes (Exelon and the
Utility Registrants).
The Utility Registrants are required to engage in regulatory approval proceedings as a part of the process of establishing the terms and rates for their
respective services. These proceedings typically involve multiple parties, including governmental bodies and officials, consumer advocacy groups, and
various consumers of
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energy, who have differing concerns but who have the common objective of limiting rate increases or even reducing rates. Decisions are subject to appeal,
potentially leading to additional uncertainty associated with the approval proceedings. The potential duration of such proceedings creates a risk that rates
ultimately approved by the applicable regulatory body may not be sufficient for a Utility Registrant to recover its costs by the time the rates become effective.
Established rates are also subject to subsequent prudency reviews by state regulators, whereby various portions of rates could be adjusted, subject to
refund or disallowed, including recovery mechanisms for costs associated with the procurement of electricity or gas, credit losses, MGP remediation, smart
grid infrastructure, and energy efficiency and demand response programs. In certain instances, the Utility Registrants could agree to negotiated settlements
related to various rate matters, customer initiatives, or franchise agreements. These settlements are subject to regulatory approval. The ultimate outcome
and timing of regulatory rate proceedings have a significant effect on the ability of the Utility Registrants to recover their costs or earn an adequate return.
See Note 3 — Regulatory Matters of the Combined Notes to the Consolidated Financial Statements for additional information.
NRC actions could negatively affect the operations and profitability of Generation’s nuclear generating fleet (Exelon and
Generation).
Regulatory risk. A change in the Atomic Energy Act or the applicable regulations or licenses could require a substantial increase in capital expenditures or
could result in increased operating or decommissioning costs. Events at nuclear plants owned by others, as well as those owned by Generation, could cause
the NRC to initiate such actions.
Spent nuclear fuel storage. The approval of a national repository for the storage of SNF and the timing of such a facility opening, will significantly affect the
costs associated with storage of SNF and the ultimate amounts received from the DOE to reimburse Generation for these costs.
Any regulatory action relating to the timing and availability of a repository for SNF could adversely affect Generation’s ability to fully decommission its nuclear
units. Generation cannot predict what, if any, fee may be established in the future for SNF disposal. See Note 19 — Commitments and Contingencies of the
Combined Notes to Consolidated Financial Statements for additional information on the SNF obligation.
The Registrants could be subject to higher costs and/or penalties related to mandatory reliability standards, including the likely
exposure of the Utility Registrants to the results of PJM’s RTEP and NERC compliance requirements (All Registrants).
The Registrants as users, owners, and operators of the bulk power transmission system, including Generation and the Utility Registrants, are subject to
mandatory reliability standards promulgated by NERC and enforced by FERC. PECO, BGE, and DPL, as operators of natural gas distribution systems, are
also subject to mandatory reliability standards of the U.S. Department of Transportation. The standards are based on the functions that need to be performed
to ensure the bulk power system operates reliably and are guided by reliability and market interface principles. Compliance with or changes in the reliability
standards could subject the Registrants to higher operating costs and/or increased capital expenditures. In addition, the ICC, PAPUC, MDPSC, DCPSC,
DPSC, and NJBPU impose certain distribution reliability standards on the Utility Registrants. If the Registrants were found not to be in compliance with the
Federal and state mandatory reliability standards, they could be subject to remediation costs as well as sanctions, which could include substantial monetary
penalties.
The Registrants could incur substantial costs to fulfill their obligations related to environmental and other matters (All
Registrants).
The businesses that the Registrants operate are subject to extensive environmental regulation and legislation by local, state, and Federal authorities. These
laws and regulations affect the manner in which the Registrants conduct their operations and make capital expenditures including how they handle air and
water emissions, hazardous and solid waste, and activities affecting surface waters, groundwater, and aquatic and other species. Violations of these
requirements could subject the Registrants to enforcement actions, capital expenditures to bring existing facilities into compliance, additional operating costs
for remediation and clean-up costs, civil penalties and exposure to third parties’ claims for alleged health or property damages, or operating restrictions to
achieve compliance. In addition, the Registrants are subject to liability under these laws for the remediation costs for environmental contamination of
property now or formerly owned by the Registrants and of property
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contaminated by hazardous substances they generated or released. Remediation activities associated with MGP operations conducted by predecessor
companies are one component of such costs. Also, the Registrants are currently involved in a number of proceedings relating to sites where hazardous
substances have been deposited and could be subject to additional proceedings in the future. See ITEM 1. BUSINESS — Environmental Regulation for
additional information.
The Registrants could be negatively affected by challenges to tax positions taken, tax law changes, and the inherent difficulty in
quantifying potential tax effects of business decisions. (All Registrants).
The Registrants are required to make judgments in order to estimate their obligations to taxing authorities. These tax obligations include income, real estate,
sales and use, and employment-related taxes and ongoing appeal issues related to these tax matters. These judgments include reserves established for
potential adverse outcomes regarding tax positions that have been taken that could be subject to challenge by the tax authorities. See Note 1 — Significant
Accounting Policies and Note 14 — Income Taxes of the Combined Notes to Consolidated Financial Statements for additional information.
The Registrants could be negatively affected by federal and state RPS and/or energy conservation legislation, along with energy
conservation by customers (All Registrants).
Changes to current state legislation or the development of Federal legislation that requires the use of clean, renewable, and alternate fuel sources could
significantly impact Generation and the Utility Registrants, especially if timely cost recovery is not allowed for Utility Registrants. The impact could include
increased costs and increased rates for customers.
Federal and state legislation mandating the implementation of energy conservation programs that require the implementation of new technologies, such as
smart meters and smart grid, could increase capital expenditures and could significantly impact the Utility Registrants consolidated financial statements if
timely cost recovery is not allowed. Furthermore, regulated energy consumption reduction targets and declines in customer energy consumption resulting
from the implementation of new energy conservation technologies could lead to a decline in the revenues of the Registrants. See ITEM 1. BUSINESS —
Environmental Regulation — Renewable and Clean Energy Standards for additional information.
Generation’s affiliation with the Utility Registrants, together with the presence of a substantial percentage of Generation’s physical
asset base within the Utility Registrants' service territories, could increase Generation’s cost of doing business to the extent future
complaints or challenges regarding the Utility Registrants' retail rates result in settlements or legislative or regulatory
requirements funded in part by Generation (Exelon and Generation).
Generation has significant generating resources within the service areas of the Utility Registrants and makes significant sales to each of them. Those facts
tend to cause Generation to be directly affected by developments in those markets. Government officials, legislators, and advocacy groups are aware of
Generation’s affiliation with the Utility Registrants and its sales to each of them. In periods of rising utility rates, particularly when driven by increased costs of
energy production and supply, those officials and advocacy groups could question or challenge costs and transactions incurred by the Utility Registrants with
Generation, irrespective of any previous regulatory processes or approvals underlying those transactions. These challenges could increase the time,
complexity, and cost of the associated regulatory proceedings, and the occurrence of such challenges could subject Generation to a level of scrutiny not
faced by other unaffiliated competitors in those markets. In addition, government officials and legislators could seek ways to force Generation to contribute to
efforts to mitigate potential or actual rate increases, through measures such as generation-based taxes.
The Registrants could be subject to adverse publicity and reputational risks, which make them vulnerable to negative customer
perception and could lead to increased regulatory oversight or other consequences (All Registrants).
The Registrants could be the subject of public criticism. Adverse publicity of this nature could render public service commissions and other regulatory and
legislative authorities less likely to view energy companies such as Exelon and its subsidiaries in a favorable light, and could cause Exelon and its
subsidiaries to be susceptible
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to less favorable legislative and regulatory outcomes, as well as increased regulatory oversight and more stringent legislative or regulatory requirements
(e.g. disallowances of costs, lower ROEs).
Legal proceedings could result in a negative outcome, which the Registrants cannot predict (All Registrants).
The Registrants are involved in legal proceedings, claims, and litigation arising out of their business operations. The material ones are summarized in Note
19 — Commitments and Contingencies of the Combined Notes to Consolidated Financial Statements. Adverse outcomes in these proceedings could require
significant expenditures, result in lost revenue, or restrict existing business activities.
Exelon and ComEd have received requests for information related to an SEC investigation into their lobbying activities. The
outcome of the investigations could have a material adverse effect on their reputation and consolidated financial statements
(Exelon and ComEd).
On October 22, 2019, the SEC notified Exelon and ComEd that it had opened an investigation into their lobbying activities in the state of Illinois. Exelon and
ComEd have cooperated fully, including by providing all information requested by the SEC, and intend to continue to cooperate fully and expeditiously with
the SEC. The outcome of the SEC’s investigation cannot be predicted and could subject Exelon and ComEd to civil penalties, sanctions, or other remedial
measures. Any of the foregoing, as well as the appearance of non-compliance with anti-corruption and anti-bribery laws, could have an adverse impact on
Exelon’s and ComEd’s reputations or relationships with regulatory and legislative authorities, customers, and other stakeholders, as well as their
consolidated financial statements. See Note 19 — Commitments and Contingencies of the Combined Notes to Consolidated Financial Statements.
If ComEd violates its Deferred Prosecution Agreement announced on July 17, 2020, it could have an adverse effect on the
reputation and consolidated financial statements of Exelon and ComEd (Exelon and ComEd).
On July 17, 2020, ComEd entered into a Deferred Prosecution Agreement (DPA) with the U.S. Attorney’s Office for the Northern District of Illinois (USAO) to
resolve the USAO’s investigation into Exelon’s and ComEd’s lobbying activities in the State of Illinois. Exelon was not made a party to the DPA and the
investigation by the USAO into Exelon’s activities ended with no charges being brought against Exelon. Under the DPA, the USAO filed a single charge
alleging that ComEd improperly gave and offered to give jobs, vendor subcontracts, and payments associated with those jobs and subcontracts for the
benefit of the Speaker of the Illinois House of Representatives and the Speaker’s associates, with the intent to influence the Speaker’s action regarding
legislation affecting ComEd’s interests. The DPA provides that the USAO will defer any prosecution of such charge and any other criminal or civil case
against ComEd in connection with the matters identified therein for a three-year period subject to certain obligations of ComEd, including, but not limited to,
the following: (i) payment to the United States Treasury of $200 million; (ii) continued full cooperation with the government’s investigation; and (iii) ComEd’s
adoption and maintenance of remedial measures involving compliance and reporting undertakings as specified in the DPA. If ComEd is found to have
breached the terms of the DPA, the USAO may elect to prosecute, or bring a civil action against, ComEd for conduct alleged in the DPA or known to the
government, which could result in fines or penalties and could have an adverse impact on Exelon’s and ComEd’s reputation or relationships with regulatory
and legislative authorities, customers and other stakeholders, as well as their consolidated financial statements. See Note 19 — Commitments and
Contingencies of the Combined Notes to Consolidated Financial Statements.
Generation’s financial performance could be negatively affected by risks arising from its ownership and operation of hydroelectric
facilities (Exelon and Generation).
FERC has the exclusive authority to license most non-Federal hydropower projects located on navigable waterways, Federal lands or connected to the
interstate electric grid. Generation cannot predict whether it will receive all the regulatory approvals for the renewed licenses of its hydroelectric facilities. If
FERC does not issue new operating licenses for Generation’s hydroelectric facilities or a station cannot be operated through the end of its operating license,
Generation’s results of operations could be adversely affected by increased depreciation rates and accelerated future decommissioning costs, since
depreciation rates and decommissioning cost estimates currently include assumptions that license renewal will be received. Generation could also lose
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revenue and incur increased fuel and purchased power expense to meet supply commitments. In addition, conditions could be imposed as part of the license
renewal process that could adversely affect operations, could require a substantial increase in capital expenditures, could result in increased operating costs
or could render the project uneconomic. Similar effects could result from a change in the Federal Power Act or the applicable regulations due to events at
hydroelectric facilities owned by others, as well as those owned by Generation.
Operational Factors
The Registrants are subject to risks associated with climate change (All Registrants).
The Registrants periodically perform analyses to better understand how climate change could affect their facilities and operations. The Registrants primarily
operate in the Midwest and East Coast of the United States, areas that historically have been prone to various types of severe weather events, such that the
Registrants have well-developed response and recovery programs based on these historical events. However, the Registrants’ physical facilities could be
placed at greater risk of damage should changes in the global climate impact temperature and weather patterns, resulting in more intense, frequent and
extreme weather events, unprecedented levels of precipitation, sea level rise, increased surface water temperatures, and/or other effects. In addition,
changes to the climate may impact levels and patterns of demand for energy and related services, which could affect Registrants’ operations. Over time, the
Registrants may need to make additional investments to protect facilities from physical climate-related risks and/or adapt to changes in operational
requirements as a result of climate change.
The Registrants also periodically perform analyses of potential pathways to reduce power sector and economy-wide GHG emissions to mitigate climate
change. To the extent additional GHG reduction regulation or legislation becomes effective at the Federal and/or state levels, the Registrants could incur
costs to further limit the GHG emissions from their operations or otherwise comply with applicable requirements. To the extent such additional regulation or
legislation does not become effective, the potential competitive advantage offered by Registrant’s low-carbon emission profile may be reduced. See ITEM 1.
BUSINESS — Climate Change Mitigation.
Generation’s financial performance could be negatively affected by matters arising from its ownership and operation of nuclear
facilities (Exelon and Generation).
Nuclear capacity factors. Capacity factors for nuclear generating units, significantly affect Generation’s results of operations. Lower capacity factors could
decrease Generation’s revenues and increase operating costs by requiring Generation to produce additional energy from primarily its fossil facilities or
purchase additional energy in the spot or forward markets in order to satisfy Generation’s obligations to committed third-party sales, including the Utility
Registrants. These sources generally have higher costs than Generation incurs to produce energy from its nuclear stations.
Nuclear refueling outages. In general, refueling outages are planned to occur once every 18 to 24 months. The total number of refueling outages, along
with their duration, could have a significant impact on Generation’s results of operations. When refueling outages last longer than anticipated or Generation
experiences unplanned outages, capacity factors decrease, and Generation faces lower margins due to higher energy replacement costs and/or lower
energy sales and higher operating and maintenance costs.
Nuclear fuel quality. The quality of nuclear fuel utilized by Generation could affect the efficiency and costs of Generation’s operations. Remediation actions
could result in increased costs due to accelerated fuel amortization, increased outage costs, and/or increased costs due to decreased generation
capabilities.
Operational risk. Operations at any of Generation’s nuclear generation plants could degrade to the point where Generation must shut down the plant or
operate at less than full capacity. If this were to happen, identifying and correcting the causes could require significant time and expense. Generation could
choose to close a plant rather than incur the expense of restarting it or returning the plant to full capacity. In either event, Generation could lose revenue and
incur increased fuel and purchased power expense to meet supply commitments.
For plants operated but not wholly owned by Generation, Generation could also incur liability to the co-owners. For nuclear plants not operated and not
wholly owned by Generation, from which Generation receives a portion of the plants’ output, Generation’s results of operations are dependent on the
operational performance of the operators and could be adversely affected by a significant event at those plants. Additionally, poor operating
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performance at nuclear plants not owned by Generation could result in increased regulation and reduced public support for nuclear-fueled energy. In
addition, closure of generating plants owned by others, or extended interruptions of generating plants, or failure of transmission lines, could affect
transmission systems that could adversely affect the sale and delivery of electricity in markets served by Generation.
Nuclear major incident risk and insurance. The consequences of a major incident could be severe and include loss of life and property damage. Any
resulting liability from a nuclear plant major incident within the United States, owned or operated by Generation or owned by others, could exceed
Generation’s resources, including insurance coverage. Generation is a member of an industry mutual insurance company, NEIL, which provides property
and business interruption insurance for Generation’s nuclear operations. Uninsured losses and other expenses, to the extent not recovered from insurers or
the nuclear industry, could be borne by Generation. Additionally, an accident or other significant event at a nuclear plant within the United States or abroad,
whether owned by Generation or others, could result in increased regulation and reduced public support for nuclear-fueled energy.
As required by the Price-Anderson Act, Generation carries the maximum available amount of nuclear liability insurance, $450 million for each operating site.
Claims exceeding that amount are covered through mandatory participation in a financial protection pool. In addition, the U.S. Congress could impose
revenue-raising measures on the nuclear industry to pay claims exceeding the $13.8 billion limit for a single incident.
See Note 19 — Commitments and Contingencies of the Combined Notes to Consolidated Financial Statements for additional information of nuclear
insurance.
Decommissioning obligation and funding. NRC regulations require that licensees of nuclear generating facilities demonstrate reasonable assurance that
funds will be available in certain minimum amounts at the end of the life of the facility to decommission the facility.
Generation recognizes as a liability the present value of the estimated future costs to decommission its nuclear facilities. The estimated liability is based on
assumptions in the approach and timing of decommissioning the nuclear facilities, estimation of decommissioning costs, and Federal and state regulatory
requirements. The costs of such decommissioning may substantially exceed such liability, as facts, circumstances or our estimates may change, including
changes in the approach and timing of decommissioning activities, changes in decommissioning costs, changes in Federal or state regulatory requirements
on the decommissioning of such facilities, other changes in our estimates or Generation’s ability to effectively execute on its planned decommissioning
activities.
Generation makes contributions to certain trust funds of the former PECO units based on amounts being collected by PECO from its customers and remitted
to Generation. While Generation, through PECO, has recourse to collect additional amounts from PECO customers (subject to certain limitations and
thresholds), it has no recourse to collect additional amounts from utility customers for any of its other nuclear units if there is a shortfall of funds necessary
for decommissioning. If circumstances changed such that Generation would be unable to continue to make contributions to the trust funds of the former
PECO units based on amounts collected from PECO customers, or if Generation no longer had recourse to collect additional amounts from PECO
customers if there was a shortfall of funds for decommissioning, the adequacy of the trust funds related to the former PECO units could be negatively
affected.
Should the expected value of the NDT fund for any former ComEd unit fall below the amount of the expected decommissioning obligation for that unit, the
accounting to offset decommissioning-related activities in the Consolidated Statement of Operations and Comprehensive Income for that unit would be
discontinued, the decommissioning-related activities would be recognized in the Consolidated Statements of Operations and Comprehensive Income, and
the adverse impact to Exelon’s and Generation’s financial statements could be material. Any changes to the existing PECO regulatory agreements could
impact Exelon’s and Generation’s ability to offset decommissioning-related activities within the Consolidated Statement of Operations and Comprehensive
Income, and the impact to Exelon’s and Generation’s financial statements could be material.
Forecasting trust fund investment earnings and costs to decommission nuclear generating stations requires significant judgment, and actual results could
differ significantly from current estimates. If the investments held by Generation’s NDT funds are not sufficient to fund the decommissioning of Generation’s
nuclear units, Generation could be required to take steps, such as providing financial guarantees through letters of credit or parent
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company guarantees or making additional contributions to the trusts, which could be significant, to ensure that the trusts are adequately funded and that
current and future NRC minimum funding requirements are met.
See Note 10 — Asset Retirement Obligations of the Combined Notes to Consolidated Financial Statements for additional information.
The Utility Registrants' operating costs are affected by their ability to maintain the availability and reliability of their delivery and
operational systems (Exelon and the Utility Registrants).
Failures of the equipment or facilities used in the Utility Registrants' delivery systems could interrupt the electric transmission and electric and natural gas
delivery, which could result in a loss of revenues and an increase in maintenance and capital expenditures. Equipment or facilities failures can be due to a
number of factors, including natural causes such as weather or information systems failure. Specifically, if the implementation of AMI, smart grid, or other
technologies in the Utility Registrants' service territory fail to perform as intended or are not successfully integrated with billing and other information systems,
or if any of the financial, accounting, or other data processing systems fail or have other significant shortcomings, the Utility Registrants' financial results
could be negatively impacted. In addition, dependence upon automated systems could further increase the risk that operational system flaws or internal
and/or external tampering or manipulation of those systems will result in losses that are difficult to detect.
Regulated utilities, which are required to provide service to all customers within their service territory, have generally been afforded liability protections
against claims by customers relating to failure of service. Under Illinois law, however, ComEd could be required to pay damages to its customers in some
circumstances involving extended outages affecting large numbers of its customers, which could be material.
The Registrants are subject to physical security and cybersecurity risks (All Registrants).
The Registrants face physical security and cybersecurity risks. Threat sources continue to seek to exploit potential vulnerabilities in the electric and natural
gas utility industry associated with protection of sensitive and confidential information, grid infrastructure, and other energy infrastructures, and such attacks
and disruptions, both physical and cyber, are becoming increasingly sophisticated and dynamic. Continued implementation of advanced digital technologies
increases the potentially unfavorable impacts of such attacks. A security breach of the physical assets or information systems of the Registrants, their
competitors, vendors, business partners and interconnected entities in RTOs and ISOs, or regulators could impact the operation of the generation fleet
and/or reliability of the transmission and distribution system or result in the theft or inappropriate release of certain types of information, including critical
infrastructure information, sensitive customer, vendor, and employee data, trading or other confidential data. The risk of these system-related events and
security breaches occurring continues to intensify, and while the Registrants have been, and will likely continue to be, subjected to physical and cyber-
attacks, to date none has directly experienced a material breach or disruption to its network or information systems or our service operations. However, as
such attacks continue to increase in sophistication and frequency, the Registrants may be unable to prevent all such attacks in the future. If a significant
breach were to occur, the reputation of the Registrants could be negatively affected, customer confidence in the Registrants or others in the industry could
be diminished, or the Registrants could be subject to legal claims, loss of revenues, increased costs, or operations shutdown. Moreover, the amount and
scope of insurance maintained against losses resulting from any such events or security breaches may not be sufficient to cover losses or otherwise
adequately compensate for any disruptions to business that could result.
The Utility Registrants' deployment of smart meters throughout their service territories could increase the risk of damage from an intentional disruption of the
system by third parties.
In addition, new or updated security regulations or unforeseen threat sources could require changes in current measures taken by the Registrants or their
business operations and could adversely affect their consolidated financial statements.
The Registrants’ employees, contractors, customers, and the general public could be exposed to a risk of injury due to the nature
of the energy industry (All Registrants).
Employees and contractors throughout the organization work in, and customers and the general public could be exposed to, potentially dangerous
environments near the Registrants’ operations. As a result, employees,
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contractors, customers, and the general public are at some risk for serious injury, including loss of life. These risks include nuclear accidents, dam failure,
gas explosions, pole strikes, and electric contact cases.
Natural disasters, war, acts and threats of terrorism, pandemic, and other significant events could negatively impact the
Registrants' results of operations, their ability to raise capital and their future growth (All Registrants).
Generation’s fleet of power plants and the Utility Registrants' distribution and transmission infrastructures could be affected by natural disasters and extreme
weather events, which could result in increased costs, including supply chain costs. An extreme weather event within the Registrants’ service areas can also
directly affect their capital assets, causing disruption in service to customers due to downed wires and poles or damage to other operating equipment.
Natural disasters and other significant events increase the risk to Generation that the NRC or other regulatory or legislative bodies could change the laws or
regulations governing, among other things, operations, maintenance, licensed lives, decommissioning, SNF storage, insurance, emergency planning,
security, and environmental and radiological matters. In addition, natural disasters could affect the availability of a secure and economical supply of water in
some locations, which is essential for Generation’s continued operation, particularly the cooling of generating units.
The impact that potential terrorist attacks could have on the industry and on Exelon is uncertain. The Registrants face a risk that their operations would be
direct targets or indirect casualties of an act of terror. Any retaliatory military strikes or sustained military campaign could affect their operations in
unpredictable ways, such as changes in insurance markets and disruptions of fuel supplies and markets, particularly oil. Furthermore, these catastrophic
events could compromise the physical or cybersecurity of Exelon’s facilities, which could adversely affect Exelon’s ability to manage its business effectively.
Instability in the financial markets as a result of terrorism, war, natural disasters, pandemic, credit crises, recession, or other factors also could result in a
decline in energy consumption or interruption of fuel or the supply chain. In addition, the implementation of security guidelines and measures has resulted in
and is expected to continue to result in increased costs.
The Registrants could be significantly affected by the outbreak of a pandemic. Exelon has plans in place to respond to a pandemic. However, depending on
the severity of a pandemic and the resulting impacts to workforce and other resource availability, the ability to operate Exelon's generating and transmission
and distribution assets could be affected.
In addition, Exelon maintains a level of insurance coverage consistent with industry practices against property, casualty and cybersecurity losses subject to
unforeseen occurrences or catastrophic events that could damage or destroy assets or interrupt operations. However, there can be no assurance that the
amount of insurance will be adequate to address such property and casualty losses.
The Registrants’ businesses are capital intensive, and their assets could require significant expenditures to maintain and are
subject to operational failure, which could result in potential liability (All Registrants).
The Registrants’ businesses are capital intensive and require significant investments by Generation in electric generating facilities and by the Utility
Registrants in transmission and distribution infrastructure projects. Equipment, even if maintained in accordance with good utility practices, is subject to
operational failure, including events that are beyond the Registrants’ control, and could require significant expenditures to operate efficiently. The Registrants
consolidated financial statements could be negatively affected if they were unable to effectively manage their capital projects or raise the necessary capital.
See ITEM 7. MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS — Liquidity and Capital
Resources for additional information regarding the Registrants’ potential future capital expenditures.
The Utility Registrants' respective ability to deliver electricity, their operating costs, and their capital expenditures could be
negatively impacted by transmission congestion and failures of neighboring transmission systems (Exelon and the Utility
Registrants).
Demand for electricity within the Utility Registrants' service areas could stress available transmission capacity requiring alternative routing or curtailment of
electricity usage. Also, insufficient availability of electric supply to meet customer demand could jeopardize the Utility Registrants' ability to comply with
reliability standards and strain customer and regulatory agency relationships. As with all utilities, potential concerns over transmission
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capacity or generation facility retirements could result in PJM or FERC requiring the Utility Registrants to upgrade or expand their respective transmission
systems through additional capital expenditures.
PJM’s systems and operations are designed to ensure the reliable operation of the transmission grid and prevent the operations of one utility from having an
adverse impact on the operations of the other utilities. However, service interruptions at other utilities may cause interruptions in the Utility Registrants’
service areas.
The Registrants consolidated financial statements could be negatively affected if they fail to attract and retain an appropriately
qualified workforce (All Registrants).
Certain events, such as an employee strike, loss of contract resources due to a major event, and an aging workforce without appropriate replacements,
could lead to operating challenges and increased costs for the Registrants. The challenges include lack of resources, loss of knowledge and a lengthy time
period associated with skill development. In this case, costs, including costs for contractors to replace employees, productivity costs, and safety costs, could
arise. The Registrants are particularly affected due to the specialized knowledge required of the technical and support employees for their generation,
transmission, and distribution operations.
The Registrants could make acquisitions or investments in new business initiatives and new markets, which may not be
successful or achieve the intended financial results (All Registrants).
Generation could continue to pursue growth in its existing businesses and markets and further diversification across the competitive energy value chain. This
could include investment opportunities in renewables, development of natural gas generation, nuclear advisory or operating services for third parties,
distributed generation, potential expansion of the existing wholesale gas businesses, and entry into LNG. Such initiatives could involve significant risks and
uncertainties, including distraction of management from current operations, inadequate return on capital, and unidentified issues not discovered during
diligence performed prior to launching an initiative or entering a market. Additionally, it is possible that FERC, state public utility commissions or others could
impose certain other restrictions on such transactions. All of these factors could result in higher costs or lower revenues than expected, resulting in lower
than planned returns on investment.
The Utility Registrants face risks associated with their regulatory-mandated initiatives, such as smart grids and utility of the future. These risks include, but
are not limited to, cost recovery, regulatory concerns, cybersecurity, and obsolescence of technology. Such initiatives may not be successful.
The Registrants may not realize or achieve the anticipated cost savings through the cost management efforts (All Registrants).
The Registrants’ future financial performance and level of profitability is dependent, in part, on various cost reduction initiatives. The Registrants may
encounter challenges in executing these cost reduction initiatives and not achieve the intended cost savings.
Risks Related to the Planned Separation (Exelon and Generation)
The planned separation is contingent upon regulatory approvals and satisfaction of other conditions and may not be completed in
accordance with the expected plans or anticipated timeline, or at all, which could negatively affect Exelon’s and Generation’s
consolidated financial statements.
Exelon is targeting to complete the separation in the first quarter of 2022, subject to final approval by Exelon’s Board of Directors, a Form 10 registration
statement being declared effective by the SEC, regulatory approvals, and satisfaction of other conditions. The planned separation is subject to approval by
the FERC, NRC and NYPSC. There can be no assurance that any separation transaction will ultimately occur or, if one does occur, of its terms or timing. If
the planned separation is not completed or is delayed, Exelon’s and Generation’s consolidated financial statements may be materially adversely affected,
and the market price of Exelon’s common stock may be affected.
45
Table of Contents
The plan to separate into two publicly traded companies will involve significant time and expense, which could disrupt or
adversely affect our business.
The planned separation is complex in nature, and unanticipated developments or changes, including challenges in executing the separation, could delay or
prevent the completion of the proposed separation, or cause the separation to occur on terms or conditions that are different or less favorable than expected.
Additionally, Exelon’s Board of Directors, in its sole and absolute discretion, may decide not to proceed with the separation at any time prior to the distribution
date. The process of completing the proposed separation has been and is expected to continue to be time-consuming and involves significant costs and
expenses.
The planned separation may not achieve some or all of the anticipated benefits and each separate company following the
separation may underperform relative to Exelon’s expectations.
By separating the Utility Registrants and Generation, Exelon is creating two publicly traded companies with the resources necessary to best serve customers
and sustain long-term investment and operating excellence. The separate companies are expected to create value by having the strategic flexibility to focus
on their unique customer, market and community priorities. However, the planned separation may not provide such results on the scope or scale that Exelon
anticipates, and Exelon and Generation may not realize the anticipated benefits of the planned separation. Failure to do so could have a material adverse
effect on the financial statements of each separate company and their respective common stock price.
Following the planned separation, the companies anticipate to maintain investment grade credit ratings. Ratings are based upon assessments of multiple
factors, including a company’s credit metrics as well as industry and macroeconomic changes and trends. If a rating agency were to downgrade the rating
below investment grade, the separate companies’ borrowing costs would increase and their funding sources could decrease, which could have a material
adverse effect on the financial statements of the affected company.
The common stock of the separately publicly traded companies following the separation may collectively trade at a value less than the price at which
Exelon’s common stock might have traded had the separation not occurred.
There could be significant liability if the planned spin-off is determined to be a taxable transaction.
Under the separation plan, Exelon shareholders will retain their current shares of Exelon stock and receive a pro-rata distribution of shares of the new
company’s stock in a transaction that is expected to be tax-free to Exelon and its shareholders under Sections 355 and 368 of the IRC. Exelon will seek a
private letter ruling from the IRS regarding the tax-free nature of the transaction. Exelon will also seek from its tax advisors an opinion with respect to certain
U.S. federal income tax consequences of the spin-off. If the planned spin-off ultimately is determined to be taxable, the spin-off could be treated as a taxable
dividend to Exelon’s shareholders for U.S. federal income tax purposes, and Exelon’s shareholders could incur significant U.S. federal income tax liabilities.
In addition, Exelon would recognize a taxable gain to the extent that the fair market value of the new company’s stock exceeds its tax basis in such stock on
the date of the planned separation. Exelon will enter into a Tax Matters Agreement with the new company to address how post-separation issues will be
managed between the companies, as well as which company is responsible for taxes imposed as a result of the planned separation, if any.
See Note 26 — Subsequent Events of the Combined Notes to Consolidated Financial Statements for additional information on the planned separation.
ITEM 1B.
UNRESOLVED STAFF COMMENTS
All Registrants
None.
46
Table of Contents
ITEM 2.
PROPERTIES
Generation
The following table presents Generation’s interests in net electric generating capacity by station at December 31, 2020:
Station
(a)
Location
No. of
Units
Percent
(b)
Owned
Primary
Fuel Type
Primary
Dispatch
Type
(c)
Net Generation
(d)
Capacity (MW)
Midwest
Braidwood
Byron
LaSalle
Dresden
Quad Cities
Clinton
Michigan Wind 2
Beebe
Michigan Wind 1
Harvest 2
Harvest
Beebe 1B
City Solar
Solar Ohio
Blue Breezes
CP Windfarm
Southeast Chicago
Clinton Battery Storage
Total Midwest
Mid-Atlantic
Limerick
Peach Bottom
Salem
Calvert Cliffs
Conowingo
Criterion
Fair Wind
Solar MC
Fourmile Ridge
Solar New Jersey 1
Solar New Jersey 2
Solar Horizons
Solar Maryland
Solar Maryland 2
Uranium
Uranium
Uranium
Uranium
Uranium
Uranium
Wind
Wind
Wind
Wind
Wind
Wind
Solar
Solar
Wind
Wind
Gas
Energy Storage
Uranium
Uranium
Uranium
Uranium
Hydroelectric
Wind
Wind
Solar
Wind
Solar
Solar
Solar
Solar
Solar
Base-load
Base-load
Base-load
Base-load
Base-load
Base-load
Intermittent
Intermittent
Intermittent
Intermittent
Intermittent
Intermittent
Intermittent
Intermittent
Intermittent
Intermittent
Peaking
Peaking
Base-load
Base-load
Base-load
Base-load
Base-load
Intermittent
Intermittent
Intermittent
Intermittent
Intermittent
Intermittent
Intermittent
Intermittent
Intermittent
2,386
2,347
2,320
1,845
1,403
1,080
46
42
35
30
27
26
9
4
3
2
296
10
11,911
2,317
1,324
995
895
572
36
30
44
20
18
11
16
8
8
(e)
(e)
(f)
(f)
(f)
(f)
(f)
(f)
(f)
(h)
(f)
(i)
(f)
(f)
(f)
(f)
(h)
(f)
(h)
(h)
(f)
(h)
(h)
Braidwood, IL
Byron, IL
Seneca, IL
Morris, IL
Cordova, IL
Clinton, IL
Sanilac Co., MI
Gratiot Co., MI
Huron Co., MI
Huron Co., MI
Huron Co., MI
Gratiot Co., MI
Chicago, IL
Toledo, OH
Faribault Co., MN
Faribault Co., MN
Chicago, IL
Blanchester, OH
Sanatoga, PA
Delta, PA
Lower Alloways
Creek Township, NJ
Lusby, MD
Darlington, MD
Oakland, MD
Garrett County, MD
Various, MD
Garrett County, MD
Various, NJ
Various, NJ
Emmitsburg, MD
Various, MD
Various, MD
2
2
2
2
2
1
50
34
46
33
32
21
1
2
2
2
8
1
2
2
2
2
11
28
12
44
16
5
2
1
11
3
75
51
51
51
51
51
51
(g)
(g)
(g)
(g)
(g)
(g)
51
(g)
50
42.59
50.01
(j)
51
(g)
51
(g)
51
(g)
47
Table of Contents
Station
(a)
Location
No. of
Units
Percent
(b)
Owned
Primary
Fuel Type
Primary
Dispatch
Type
(c)
Net Generation
(d)
Capacity (MW)
JBAB Solar
Gateway Solar
Constellation New Energy
Solar Federal
Solar New Jersey 3
Solar DC
Muddy Run
Eddystone 3, 4
Perryman
Croydon
Handsome Lake
Richmond
Philadelphia Road
Eddystone
Delaware
Southwark
Falls
Moser
Chester
Schuylkill
Salem
Total Mid-Atlantic
ERCOT
Whitetail
Sendero
Constellation Solar Texas
Colorado Bend II
Wolf Hollow II
Handley 3
Handley 4, 5
Total ERCOT
District of Columbia
Berlin, MD
Gaithersburg, MD
Trenton, NJ
Middle Township, NJ
District of Columbia
Drumore, PA
Eddystone, PA
Aberdeen, MD
West Bristol, PA
Kennerdell, PA
Philadelphia, PA
Baltimore, MD
Eddystone, PA
Philadelphia, PA
Philadelphia, PA
Morrisville, PA
Lower Pottsgrove Twp.,
PA
Chester, PA
Philadelphia, PA
Lower Alloways
Creek Township, NJ
Webb County, TX
Jim Hogg and Zapata
County, TX
Various, TX
Wharton, TX
Granbury, TX
Fort Worth, TX
Fort Worth, TX
4
1
2
1
5
1
8
2
5
8
5
2
4
4
4
4
3
3
3
2
1
57
39
11
3
3
1
2
51
(g)
42.59
51
(g)
51
(g)
48
Solar
Solar
Solar
Solar
Solar
Solar
Hydroelectric
Oil/Gas
Oil/Gas
Oil
Gas
Oil
Oil
Oil
Oil
Oil
Oil
Oil
Oil
Oil
Oil
Wind
Wind
Solar
Gas
Gas
Gas
Gas
Intermittent
Intermittent
Intermittent
Intermittent
Intermittent
Intermittent
Intermediate
Peaking
Peaking
Peaking
Peaking
Peaking
Peaking
Peaking
Peaking
Peaking
Peaking
Peaking
Peaking
Peaking
Peaking
(h)
(h)
(h)
(h)
(f)
(h)
7
7
6
5
2
1
1,070
760
404
391
268
98
61
60
56
52
51
51
39
30
16
(f)
9,729
Intermittent
47
(f)
Intermittent
Intermittent
Intermediate
Intermediate
Intermediate
Peaking
(f)
(h)
40
13
1,143
1,115
395
870
3,623
Table of Contents
Station
(a)
Location
No. of
Units
Percent
(b)
Owned
Primary
Fuel Type
Primary
Dispatch
Type
(c)
Net Generation
(d)
Capacity (MW)
New York
Nine Mile Point
FitzPatrick
Ginna
Solar New York
Total New York
Other
Antelope Valley
Bluestem
Shooting Star
Albany Green Energy
Solar Arizona
Bluegrass Ridge
California PV Energy 2
Conception
Cow Branch
Solar Arizona 2
California PV Energy
Mountain Home
High Mesa
Echo 1
Sacramento PV Energy
Cassia
Wildcat
Echo 2
Solar Georgia 2
Tuana Springs
Solar Georgia
Greensburg
Solar Massachusetts
Outback Solar
Echo 3
Holyoke Solar
Three Mile Canyon
Loess Hills
California PV Energy 3
Denver Airport Solar
Solar Net Metering
Solar Connecticut
Mystic 8, 9
Scriba, NY
Scriba, NY
Ontario, NY
Bethlehem, NY
Lancaster, CA
Beaver County, OK
Kiowa County, KS
Albany, GA
Various, AZ
King City, MO
Various, CA
Barnard, MO
Rock Port, MO
Various, AZ
Various, CA
Glenns Ferry, ID
Elmore Co., ID
Echo, OR
Sacramento, CA
Buhl, ID
Lovington, NM
Echo, OR
Various, GA
Hagerman, ID
Various, GA
Greensburg, KS
Various, MA
Christmas Valley, OR
Echo, OR
Various, MA
Boardman, OR
Rock Port, MO
Various, CA
Denver, CO
Uxbridge, MA
Various, CT
Charlestown, MA
2
1
1
1
1
60
65
1
127
27
89
24
24
56
53
20
19
21
4
14
13
10
8
8
10
10
10
1
6
2
6
4
31
1
1
1
6
50.01
(j)
50.01
(j)
51
51
99
(g)(k)
(g)
(l)
51
(g)
51
51
(g)
(g)
51
51
50.49
51
51
51
51
(g)
(g)
(g)
(g)
(g)
(g)
(g)
51
(g)
51
(g)
50.49
(g)
51
(g)
51
(g)
49
Uranium
Uranium
Uranium
Solar
Solar
Wind
Wind
Biomass
Solar
Wind
Solar
Wind
Wind
Solar
Solar
Wind
Wind
Wind
Solar
Wind
Wind
Wind
Solar
Wind
Solar
Wind
Solar
Solar
Wind
Solar
Wind
Wind
Solar
Solar
Solar
Solar
Gas
Base-load
Base-load
Base-load
Intermittent
Intermittent
Intermittent
Intermittent
Base-load
Intermittent
Intermittent
Intermittent
Intermittent
Intermittent
Intermittent
Intermittent
Intermittent
Intermittent
Intermittent
Intermittent
Intermittent
Intermittent
Intermittent
Intermittent
Intermittent
Intermittent
Intermittent
Intermittent
Intermittent
Intermittent
Intermittent
Intermittent
Intermittent
Intermittent
Intermittent
Intermittent
Intermittent
Intermediate
838
842
288
3
(f)
(f)
(h)
1,971
242
101
53
50
46
29
27
26
26
34
21
21
20
17
30
15
14
10
10
9
8
6
7
6
5
5
5
5
8
4
2
1
1,413
(f)
(f)
(f)
(h)
(f)
(h)
(f)
(f)
(h)
(h)
(f)
(f)
(f)
(f)
(f)
(f)
(f)
(h)
(f)
(h)
(f)
(h)
(h)
(f)
(h)
(f)
(h)
(f)
(h)
(h)
(e)
Table of Contents
Station
(a)
Hillabee
Mystic 7
Wyman 4
Grand Prairie
West Medway
West Medway II
Framingham
Mystic Jet
Total Other
Total
Location
Alexander City,
AL
Charlestown, MA
Yarmouth, ME
Alberta, Canada
West Medway, MA
West Medway, MA
Framingham, MA
Charlestown, MA
No. of
Units
Percent
(b)
Owned
Primary
Fuel Type
Primary
Dispatch
Type
(c)
Net Generation
(d)
Capacity (MW)
5.9
3
1
1
1
3
2
3
1
Gas
Oil/Gas
Oil
Gas
Oil
Oil/Gas
Oil
Intermediate
Intermediate
Intermediate
Peaking
Peaking
Peaking
Peaking
(m)
(f)
753
512
35
105
124
192
31
Oil
Peaking
(m)
9
4,037
31,271
__________
(a) All nuclear stations are boiling water reactors except Braidwood, Byron, Calvert Cliffs, Ginna, and Salem, which are pressurized water reactors.
(b) 100%, unless otherwise indicated.
(c) Base-load units are plants that normally operate to take all or part of the minimum continuous load of a system and, consequently, produce electricity at an essentially
constant rate. Intermittent units are plants with output controlled by the natural variability of the energy resource rather than dispatched based on system requirements.
Intermediate units are plants that normally operate to take load of a system during the daytime higher load hours and, consequently, produce electricity by cycling on and
off daily. Peaking units consist of lower-efficiency, quick response steam units, gas turbines and diesels normally used during the maximum load periods.
(d) For nuclear stations, capacity reflects the annual mean rating. Fossil stations and wind and solar facilities reflect a summer rating.
(e) Generation has announced it will permanently cease generation operations at Byron and Dresden nuclear facilities in 2021 and Mystic Unit 8 and 9 in 2024. See Note 7 —
Early Plant Retirements of the Combined Notes to the Consolidated Financial Statements for additional information.
(f) Net generation capacity is stated at proportionate ownership share.
(g) Reflects the prior sale of 49% of EGRP to a third party. See Note 23 — Variable Interest Entities of the Combined Notes to Consolidated Financial Statements for additional
information.
(h) On December 8, 2020, Generation entered into an agreement with an affiliate of Brookfield Renewable, for the sale of a significant portion of Generation's solar business.
The transaction is expected to be completed in the first half of 2021. See Note 2 — Mergers, Acquisitions, and Dispositions of the Combined Notes to the Consolidated
Financial Statements for additional information.
(i) Generation has deactivated the site and is evaluating for potential return of service or retirement beyond 2021.
(j) Reflects Generation’s interest in CENG, a joint venture with EDF. See ITEM 1. — BUSINESS — Exelon Generation Company, LLC — Nuclear Facilities for additional
information.
(k) EGRP owns 100% of the Class A membership interests and a tax equity investor owns 100% of the Class B membership interests of the entity that owns the Bluestem
generating assets.
(l) Generation directly owns a 50% interest in the Albany Green Energy station and an additional 49% through the consolidation of a Variable Interest Entity.
(m) Generation has plans to retire and cease plant operations in 2021.
The net generation capability available for operation at any time may be less due to regulatory restrictions, transmission congestion, fuel restrictions,
efficiency of cooling facilities, level of water supplies, or generating units being temporarily out of service for inspection, maintenance, refueling, repairs, or
modifications required by regulatory authorities.
Generation maintains property insurance against loss or damage to its principal plants and properties by fire or other perils, subject to certain exceptions. For
additional information regarding nuclear insurance of generating facilities, see ITEM 1. BUSINESS — Exelon Generation Company, LLC. For its insured
losses, Generation is self-insured to the extent that any losses are within the policy deductible or exceed the amount of insurance maintained. Any such
losses could have a material adverse effect in Generation’s consolidated financial condition or results of operations.
50
Table of Contents
The Utility Registrants
The Utility Registrants' electric substations and a portion of their transmission rights are located on property that they own. A significant portion of their
electric transmission and distribution facilities are located above or underneath highways, streets, other public places, or property that others own. The Utility
Registrants believe that they have satisfactory rights to use those places or property in the form of permits, grants, easements, licenses, and franchise rights;
however, they have not necessarily undertaken to examine the underlying title to the land upon which the rights rest.
Transmission and Distribution
The Utility Registrants’ high voltage electric transmission lines owned and in service at December 31, 2020 were as follows:
Voltage
(Volts)
765,000
(a)
500,000
345,000
230,000
138,000
115,000
69,000
ComEd
90
—
2,676
—
2,245
—
—
(a)
PECO
—
188
—
549
135
—
177
BGE
—
216
—
358
55
712
—
Circuit Miles
Pepco
—
109
—
770
61
25
—
(a)
DPL
—
16
—
472
586
—
567
(a)
ACE
—
—
—
274
214
—
667
___________
(a) In addition, PECO, DPL, and ACE have an ownership interest located in Delaware and New Jersey. See Note 9 - Jointly Owned Electric Utility Plant - for additional
information.
The Utility Registrants' electric distribution system includes the following number of circuit miles of overhead and underground lines:
Circuit Miles
Overhead
Underground
ComEd
35,379
32,349
PECO
12,967
9,463
BGE
9,179
17,650
Pepco
4,082
6,949
DPL
6,007
6,360
ACE
7,393
2,984
Gas
The following table presents PECO’s, BGE’s, and DPL’s natural gas pipeline miles at December 31, 2020:
Transmission
Distribution
Service piping
Total
PECO
9
6,946
6,449
13,404
BGE
152
7,443
6,383
13,978
(a)
DPL
8
2,142
1,461
3,611
___________
(a) DPL has a 10% undivided interest in approximately 8 miles of natural gas transmission mains located in Delaware which are used by DPL for its natural gas operations and
by 90% owner for distribution of natural gas to its electric generating facilities.
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Table of Contents
The following table presents PECO’s, BGE’s, and DPL’s natural gas facilities:
Registrant
Facility
Location
PECO
PECO
BGE
BGE
DPL
LNG Facility
Propane Air Plant
LNG Facility
Propane Air Plant
LNG Facility
West Conshohocken, PA
Chester, PA
Baltimore, MD
Baltimore, MD
Wilmington, DE
Storage Capacity
(mmcf)
Send-out or Peaking Capacity
(mmcf/day)
1,200
105
1,056
550
250
160
25
332
85
25
PECO, BGE, and DPL also own 30, 30, and 10 natural gas city gate stations and direct pipeline customer delivery points at various locations throughout
their gas service territory, respectively.
First Mortgage and Insurance
The principal properties of ComEd, PECO, PEPCO, DPL, and ACE are subject to the lien of their respective Mortgages under which their respective First
Mortgage Bonds are issued. See Note 17 — Debt and Credit Agreements of the Combined Notes to Consolidated Financial Statements for additional
information.
The Utility Registrants maintain property insurance against loss or damage to their properties by fire or other perils, subject to certain exceptions. For their
insured losses, the Utility Registrants are self-insured to the extent that any losses are within the policy deductible or exceed the amount of insurance
maintained. Any such losses could have a material adverse effect in the consolidated financial condition or results of operations of the Utility Registrants.
Exelon
Security Measures
The Registrants have initiated and work to maintain security measures. On a continuing basis, the Registrants evaluate enhanced security measures at
certain critical locations, enhanced response and recovery plans, long-term design changes, and redundancy measures. Additionally, the energy industry
has strategic relationships with governmental authorities to ensure that emergency plans are in place and critical infrastructure vulnerabilities are addressed
in order to maintain the reliability of the country’s energy systems.
ITEM 3.
LEGAL PROCEEDINGS
All Registrants
The Registrants are parties to various lawsuits and regulatory proceedings in the ordinary course of their respective businesses. For information regarding
material lawsuits and proceedings, see Note 3 — Regulatory Matters and Note 19 — Commitments and Contingencies of the Combined Notes to
Consolidated Financial Statements. Such descriptions are incorporated herein by these references.
52
Table of Contents
ITEM 4.
MINE SAFETY DISCLOSURES
All Registrants
Not Applicable to the Registrants.
53
Table of Contents
ITEM 5.
Exelon
PART II
(Dollars in millions except per share data, unless otherwise noted)
MARKET FOR REGISTRANT’S COMMON EQUITY, RELATED STOCKHOLDER MATTERS AND ISSUER PURCHASES OF EQUITY
SECURITIES
Exelon’s common stock is listed on the Nasdaq (trading symbol: EXC). As of January 31, 2021, there were 976,337,799 shares of common stock
outstanding and approximately 91,240 record holders of common stock.
Stock Performance Graph
The performance graph below illustrates a five-year comparison of cumulative total returns based on an initial investment of $100 in Exelon common stock,
as compared with the S&P 500 Stock Index and the S&P Utility Index, for the period 2016 through 2020.
This performance chart assumes:
•
•
$100 invested on December 31, 2015 in Exelon common stock, the S&P 500 Stock Index, and the S&P Utility Index; and
All dividends are reinvested.
54
Table of Contents
Exelon Corporation
S&P 500
S&P Utilities
Generation
2015
$100
$100
$100
Value of Investment at December 31,
2016
$132.81
$111.96
$116.29
2017
$152.79
$136.40
$130.36
2018
$180.80
$130.42
$135.72
2019
$188.53
$171.49
$171.48
2020
$181.20
$203.04
$172.31
As of January 31, 2021, Exelon indirectly held the entire membership interest in Generation.
ComEd
As of January 31, 2021, there were 127,021,370 outstanding shares of common stock, $12.50 par value, of ComEd, of which 127,002,904 shares were
indirectly held by Exelon. At January 31, 2021, in addition to Exelon, there were 286 record holders of ComEd common stock. There is no established
market for shares of the common stock of ComEd.
PECO
As of January 31, 2021, there were 170,478,507 outstanding shares of common stock, without par value, of PECO, all of which were indirectly held by
Exelon.
BGE
As of January 31, 2021, there were 1,000 outstanding shares of common stock, without par value, of BGE, all of which were indirectly held by Exelon.
PHI
As of January 31, 2021, Exelon indirectly held the entire membership interest in PHI.
Pepco
As of January 31, 2021, there were 100 outstanding shares of common stock, $0.01 par value, of Pepco, all of which were indirectly held by Exelon.
DPL
As of January 31, 2021, there were 1,000 outstanding shares of common stock, $2.25 par value, of DPL, all of which were indirectly held by Exelon.
ACE
As of January 31, 2021, there were 8,546,017 outstanding shares of common stock, $3.00 par value, of ACE, all of which were indirectly held by Exelon.
All Registrants
Dividends
Under applicable Federal law, Generation, ComEd, PECO, BGE, PHI, Pepco, DPL, and ACE can pay dividends only from retained, undistributed or current
earnings. A significant loss recorded at Generation, ComEd, PECO, BGE, PHI, Pepco, DPL, or ACE may limit the dividends that these companies can
distribute to Exelon.
ComEd has agreed in connection with a financing arranged through ComEd Financing III that ComEd will not declare dividends on any shares of its capital
stock in the event that: (1) it exercises its right to extend the interest payment periods on the subordinated debt securities issued to ComEd Financing III;
(2) it defaults on its
55
Table of Contents
guarantee of the payment of distributions on the preferred trust securities of ComEd Financing III; or (3) an event of default occurs under the Indenture under
which the subordinated debt securities are issued. No such event has occurred.
PECO has agreed in connection with financings arranged through PEC L.P. and PECO Trust IV that PECO will not declare dividends on any shares of its
capital stock in the event that: (1) it exercises its right to extend the interest payment periods on the subordinated debentures which were issued to PEC L.P.
or PECO Trust IV; (2) it defaults on its guarantee of the payment of distributions on the Series D Preferred Securities of PEC L.P. or the preferred trust
securities of PECO Trust IV; or (3) an event of default occurs under the Indenture under which the subordinated debentures are issued. No such event has
occurred.
BGE is subject to restrictions established by the MDPSC that prohibit BGE from paying a dividend on its common shares if (a) after the dividend payment,
BGE’s equity ratio would be below 48% as calculated pursuant to the MDPSC’s ratemaking precedents or (b) BGE’s senior unsecured credit rating is rated
by two of the three major credit rating agencies below investment grade. No such event has occurred.
Pepco is subject to certain dividend restrictions established by settlements approved in Maryland and the District of Columbia. Pepco is prohibited from
paying a dividend on its common shares if (a) after the dividend payment, Pepco's equity ratio would be below 48% as equity levels are calculated under the
ratemaking precedents of the MDPSC and DCPSC or (b) Pepco’s senior unsecured credit rating is rated by one of the three major credit rating agencies
below investment grade. No such event has occurred.
DPL is subject to certain dividend restrictions established by settlements approved in Delaware and Maryland. DPL is prohibited from paying a dividend on
its common shares if (a) after the dividend payment, DPL's equity ratio would be below 48% as equity levels are calculated under the ratemaking precedents
of the DPSC and MDPSC or (b) DPL’s senior unsecured credit rating is rated by one of the three major credit rating agencies below investment grade. No
such event has occurred.
ACE is subject to certain dividend restrictions established by settlements approved in New Jersey. ACE is prohibited from paying a dividend on its common
shares if (a) after the dividend payment, ACE's equity ratio would be below 48% as equity levels are calculated under the ratemaking precedents of the
NJBPU or (b) ACE's senior unsecured credit rating is rated by one of the three major credit rating agencies below investment grade. ACE is also subject to a
dividend restriction which requires ACE to obtain the prior approval of the NJBPU before dividends can be paid if its equity as a percent of its total
capitalization, excluding securitization debt, falls below 30%. No such events have occurred.
Exelon’s Board of Directors approved an updated dividend policy for 2021. The 2021 quarterly dividend will remain the same as the 2020 dividend of
$0.3825 per share.
At December 31, 2020, Exelon had retained earnings of $16,735 million, including Generation’s undistributed earnings of $2,805 million, ComEd’s retained
earnings of $1,456 million consisting of retained earnings appropriated for future dividends of $3,095 million, partially offset by $1,639 million of
unappropriated accumulated deficits, PECO’s retained earnings of $1,519 million, BGE’s retained earnings of $1,879 million, and PHI's undistributed losses
of $68 million.
The following table sets forth Exelon’s quarterly cash dividends per share paid during 2020 and 2019:
(per share)
Exelon
Fourth
Quarter
Third
Quarter
Second
Quarter
First
Quarter
Fourth
Quarter
Third
Quarter
Second
Quarter
First
Quarter
$
0.3825 $
0.3825 $
0.3825 $
0.3825 $
0.3625 $
0.3625 $
0.3625 $
0.3625
2020
2019
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The following table sets forth Generation's and PHI's quarterly distributions and ComEd’s, PECO’s, BGE's, Pepco's, DPL's, and ACE's quarterly common
dividend payments:
(in millions)
Generation
ComEd
PECO
BGE
PHI
Pepco
DPL
ACE
4th
Quarter
3rd
Quarter
2nd
Quarter
1st
Quarter
4th
Quarter
3rd
Quarter
2nd
Quarter
1st
Quarter
2020
2019
$
328 $
126
85
60
102
58
42
3
469 $
124
85
62
183
73
33
76
469 $
124
85
62
134
73
14
12
468 $
125
85
62
134
28
52
23
225 $
128
90
55
97
40
34
24
225 $
126
88
57
213
101
35
76
224 $
127
90
56
88
48
29
12
225
127
90
56
128
24
41
12
First Quarter 2021 Dividend
On February 21, 2021, Exelon's Board of Directors declared a regular quarterly dividend of $0.3825 per share on Exelon’s common stock for the first quarter
of 2021. The dividend is payable on Monday, March 15, 2021, to shareholders of record of Exelon as of 5 p.m. Eastern time on Monday, March 8, 2021.
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Item 7.
MANAGEMENT’S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS
Exelon
Executive Overview
Exelon is a utility services holding company engaged in the generation, delivery, and marketing of energy through Generation and the energy distribution and
transmission businesses through ComEd, PECO, BGE, Pepco, DPL, and ACE.
Exelon has eleven reportable segments consisting of Generation’s five reportable segments (Mid-Atlantic, Midwest, New York, ERCOT, and Other Power
Regions), ComEd, PECO, BGE, Pepco, DPL, and ACE. See Note 1 — Significant Accounting Policies and Note 5 — Segment Information of the Combined
Notes to Consolidated Financial Statements for additional information regarding Exelon's principal subsidiaries and reportable segments.
Exelon’s consolidated financial information includes the results of its eight separate operating subsidiary registrants, Generation, ComEd, PECO, BGE, PHI,
Pepco, DPL, and ACE, which, along with Exelon, are collectively referred to as the Registrants. The following combined Management’s Discussion and
Analysis of Financial Condition and Results of Operations summarizes results for the year ended December 31, 2020 compared to the year ended
December 31, 2019, and is separately filed by Exelon, Generation, ComEd, PECO, BGE, PHI, Pepco, DPL, and ACE. However, none of the Registrants
makes any representation as to information related solely to any of the other Registrants. For discussion of the year ended December 31, 2019 compared to
the year ended December 31, 2018, refer to ITEM 7. MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF
OPERATIONS in the 2019 Form 10-K, which was filed with the SEC on February 11, 2020.
COVID-19. The Registrants have taken steps to mitigate the potential risks posed by the global outbreak (pandemic) of COVID-19. The Registrants provide
a critical service to our customers which means that it is paramount that we keep our employees who operate our businesses safe and minimize
unnecessary risk of exposure to the virus. The Registrants have taken extra precautions for our employees who work in the field and for employees who
continue to work in our facilities. The Registrants have implemented work from home policies where appropriate, and imposed travel limitations on their
employees. In addition, the Registrants have updated existing business continuity plans in the context of this pandemic.
The Registrants continue to implement strong physical and cyber-security measures to ensure that our systems remain functional in order to both serve our
operational needs with a remote workforce and keep them running to ensure uninterrupted service to our customers.
There were no changes in internal control over financial reporting in 2020 as a result of COVID-19 that materially affected, or are reasonably likely to
materially affect, any of the Registrants’ internal control over financial reporting. See ITEM 9A. CONTROLS AND PROCEDURES for additional information.
Unfavorable economic conditions due to COVID-19 have impacted the demand for electricity and natural gas at Generation and the Utility Registrants, which
has resulted in a decrease in operating revenues.
As a result of COVID-19, Generation temporarily suspended interruption of service for all retail residential customers for non-payment and temporarily
ceased new late payment fees for all retail customers from March to May of 2020. Starting in March of 2020, the Utility Registrants also temporarily
suspended customer disconnections for non-payment and temporarily ceased new late payment fees for all customers and restored service to customers
upon request who were disconnected in the last twelve months. See Note 3 — Regulatory Matters of the Combined Notes to Consolidated Financial
Statements for additional information on such measures at the Utility Registrants. At Generation, such measures resulted in an increase in credit loss
expense. ComEd and ACE recorded regulatory assets for the incremental credit loss expense based on existing mechanisms. BGE, PECO, Pepco, and DPL
also recorded regulatory assets for substantially all the incremental credit loss expense incurred in 2020. See Note 3 — Regulatory Matters of the Combined
Notes to Consolidated Financial Statements for additional information.
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Generation and the Utility Registrants have also incurred direct costs related to COVID-19 consisting primarily of costs to acquire personal protective
equipment, costs for cleaning supplies and services, and costs to hire healthcare professionals to monitor the health of their employees. At Generation and
PECO, such costs are recorded as Operating and maintenance expense and are excluded from Adjusted (non-GAAP) Operating Earnings. At ComEd, BGE,
Pepco, DPL, and ACE, such costs are primarily recorded as regulatory assets. See Note 3 — Regulatory Matters of the Combined Notes to Consolidated
Financial Statements for additional information.
The estimated impact to Generation’s and the Utility Registrants’ Net income is approximately $170 million and $75 million for the year ended December 31,
2020, respectively.
To offset the unfavorable impacts from COVID-19, the Registrants identified approximately $250 million in cost savings across Generation and the Utility
Registrants in 2020. The cost savings achieved in 2020 were higher than originally anticipated.
The Registrants rely on the capital markets for publicly offered debt as well as the commercial paper markets to meet their financial commitments and short-
term liquidity needs. As a result of the disruptions in the commercial paper markets in March of 2020, Generation borrowed $1.5 billion on its revolving credit
facility to refinance commercial paper, which Generation repaid on April 3, 2020. Generation also entered into two short-term loan agreements in March of
2020 for an aggregate of $500 million. On April 8, 2020, Generation received approximately $500 million in cash after entering into an accounts receivable
financing arrangement. On April 24, 2020, Exelon Corporate entered into a credit agreement establishing a $550 million 364-day revolving credit facility to be
used as an additional source of short-term liquidity. In addition, the Registrants issued long-term debt of $5.3 billion and were able to successfully complete
their planned long-term debt issuances in 2020. See Liquidity and Capital Resources, Note 17 — Debt and Credit Agreements, and Note 6 — Accounts
Receivable of the Combined Notes to Consolidated Financial Statements for additional information.
The Registrants assessed long-lived assets, goodwill, and investments for recoverability and there were no material impairment charges recorded in 2020 as
a result of COVID-19. See Note 12 — Asset Impairments for additional information related to other impairment assessments in the third quarter of 2020.
Certain assumptions are highly sensitive to changes. Changes in significant assumptions could potentially result in future impairments, which could be
material.
This is an evolving situation that could lead to extended disruption of economic activity in our markets. The Registrants will continue to monitor developments
affecting their workforce, customers, and suppliers and will take additional precautions that they determine to be necessary in order to mitigate the impacts.
The extent to which COVID-19 may impact the Registrants’ ability to operate their generating and transmission and distribution assets, the ability to access
capital markets, and results of operations, including demand for electricity and natural gas, will depend on the spread and proliferation of COVID-19 around
the world and future developments, which are highly uncertain and cannot be predicted at this time.
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Financial Results of Operations
GAAP Results of Operations. The following table sets forth Exelon's GAAP consolidated Net Income attributable to common shareholders by Registrant for
the year ended December 31, 2020 compared to the same period in 2019. For additional information regarding the financial results for the years ended
December 31, 2020 and 2019 see the discussions of Results of Operations by Registrant.
Exelon
Generation
ComEd
PECO
BGE
PHI
Pepco
DPL
ACE
Other
(a)
2020
2019
(Unfavorable) Favorable
Variance
$
1,963 $
589
438
447
349
495
266
125
112
(355)
2,936 $
1,125
688
528
360
477
243
147
99
(242)
(973)
(536)
(250)
(81)
(11)
18
23
(22)
13
(113)
__________
(a) Primarily includes eliminating and consolidating adjustments, Exelon’s corporate operations, shared service entities, and other financing and investing activities.
Year Ended December 31, 2020 Compared to Year Ended December 31, 2019. Net income attributable to common shareholders decreased by $973
million and diluted earnings per average common share decreased to $2.01 in 2020 from $3.01 in 2019 primarily due to:
•
•
•
•
•
•
•
•
•
•
•
One-time charges and accelerated depreciation and amortization associated with Generation's decisions in the third quarter of 2020 to early
retire Byron and Dresden nuclear facilities in 2021 and Mystic Units 8 and 9 in 2024, partially offset by the absence of accelerated depreciation
and amortization due to the early retirement of TMI in September 2019;
Impairment of the New England asset group;
Payments that ComEd made under the Deferred Prosecution Agreement. See Note 19 — Commitments and Contingencies of the Combined
Notes to Consolidated Financial Statements for additional information;
Lower capacity revenue;
Reduction in load due to COVID-19 at Generation;
Lower realized energy prices;
Higher nuclear outage days;
Impact of Generation's annual update to the nuclear ARO for Non-Regulatory Agreement Units;
Lower net unrealized and realized gains on NDT funds;
COVID-19 direct costs;
Lower electric distribution earnings from lower allowed ROE due to a decrease in treasury rates, partially offset by higher rate base at ComEd;
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•
•
•
Higher storm costs related to the June 2020 and August 2020 storms at PECO, net of tax repairs, and related to the August 2020 storm at
DPL;
Unfavorable weather conditions at PECO, DPL Delaware, and ACE; and
A net increase in depreciation and amortization expense due to ongoing capital expenditures at PECO, BGE, Pepco, DPL, and ACE, partially
offset at Generation due to the impact of extending the operating license at Peach Bottom.
The decreases were partially offset by;
•
•
•
•
•
•
Higher mark-to-market gains;
Unrealized gains resulting from equity investments without readily determinable fair values that became publicly traded entities in the fourth
quarter and were fair valued based on quoted market prices of the stocks as of December 31, 2020;
Lower operating and maintenance expense at Generation primarily due to previous cost management programs, lower contracting costs, and
lower travel costs, partially offset by lower NEIL insurance distributions;
Lower nuclear fuel costs;
A tax benefit related to a settlement in the first quarter of 2020, partially offset by the absence of a tax benefit related to certain research and
development activities recorded in the fourth quarter of 2019 at Generation; and
Regulatory rate increases at BGE, DPL, and ACE.
Adjusted (non-GAAP) Operating Earnings. In addition to net income, Exelon evaluates its operating performance using the measure of Adjusted (non-
GAAP) operating earnings because management believes it represents earnings directly related to the ongoing operations of the business. Adjusted (non-
GAAP) operating earnings exclude certain costs, expenses, gains and losses, and other specified items. This information is intended to enhance an
investor’s overall understanding of year-to-year operating results and provide an indication of Exelon’s baseline operating performance excluding items that
are considered by management to be not directly related to the ongoing operations of the business. In addition, this information is among the primary
indicators management uses as a basis for evaluating performance, allocating resources, setting incentive compensation targets, and planning and
forecasting of future periods. Adjusted (non-GAAP) operating earnings is not a presentation defined under GAAP and may not be comparable to other
companies’ presentations or deemed more useful than the GAAP information provided elsewhere in this report.
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The following table provides a reconciliation between Net income attributable to common shareholders as determined in accordance with GAAP and
Adjusted (non-GAAP) operating earnings for the year ended December 31, 2020 as compared to 2019:
(All amounts in millions after tax)
Net Income Attributable to Common Shareholders
(a)
Mark-to-Market Impact of Economic Hedging Activities (net of taxes of $73 and $66,
respectively)
Unrealized (Gains) Losses Related to NDT Fund Investments (net of taxes of $278 and $269,
respectively)
Asset Impairments (net of taxes of $135 and $56, respectively)
Plant Retirements and Divestitures (net of taxes of $244 and $9, respectively)
Cost Management Program (net of taxes of $14 and $17, respectively)
Litigation Settlement Gain (net of taxes of $7)
Asset Retirement Obligation (net of taxes of $16 and $9, respectively)
Change in Environmental Liabilities (net of taxes of $6 and $8, respectively)
COVID-19 Direct Costs (net of taxes of $19)
Deferred Prosecution Agreement Payments (net of taxes of $0)
Acquisition Related Costs (net of taxes of $1)
(h)
(b)
(d)
(g)
(e)
(c)
(f)
ERP System Implementation Costs (net of taxes of $1)
Income Tax-Related Adjustments (entire amount represents tax expense)
(j)
(i)
Noncontrolling Interests (net of taxes of $19 and $26, respectively)
Adjusted (non-GAAP) Operating Earnings
(k)
For the Years Ended December 31,
2020
2019
Earnings per
Diluted Share
Earnings per
Diluted Share
$
1,963 $
2.01 $
2,936 $
3.01
(213)
(256)
396
718
45
—
48
18
50
200
4
3
71
103
(0.22)
(0.26)
0.41
0.74
0.05
—
0.05
0.02
0.05
0.20
—
—
0.07
0.11
197
(299)
123
118
51
(19)
(84)
20
—
—
—
—
5
90
$
3,149 $
3.22 $
3,139 $
0.20
(0.31)
0.13
0.12
0.05
(0.02)
(0.09)
0.02
—
—
—
—
0.01
0.09
3.22
__________
Note:
Amounts may not sum due to rounding.
Unless otherwise noted, the income tax impact of each reconciling item between GAAP Net Income and Adjusted (non-GAAP) Operating Earnings is based on the marginal
statutory federal and state income tax rates for each Registrant, taking into account whether the income or expense item is taxable or deductible, respectively, in whole or in
part. For all items except the unrealized gains and losses related to NDT funds, the marginal statutory income tax rates for 2020 and 2019 ranged from 26.0% to 29.0%. Under
IRS regulations, NDT fund investment returns are taxed at different rates for investments if they are in qualified or non-qualified funds. The effective tax rates for the unrealized
gains and losses related to NDT funds were 52.1% and 47.3% for the years ended December 31, 2020 and 2019, respectively.
(a) Reflects the impact of net unrealized gains and losses on Generation’s NDT fund investments for Non-Regulatory and Regulatory Agreement Units. The impacts of the
(b)
(c)
Regulatory Agreement Units, including the associated income taxes, are contractually eliminated, resulting in no earnings impact.
In 2020, reflects an impairment at ComEd in the second quarter of 2020 related to the acquisition of transmission assets and an impairment of the New England asset
group in the third quarter of 2020. In 2019, primarily reflects the impairment of equity method investments in certain distributed energy companies. The impact of such
impairment net of noncontrolling interest is $0.02.
In 2020, primarily reflects one-time charges and accelerated depreciation and amortization associated with Generation's decisions in the third quarter of 2020 to early retire
Byron and Dresden nuclear facilities in 2021 and Mystic Units 8 and 9 in 2024. In 2019, primarily reflects accelerated depreciation and amortization expenses associated
with the early retirement of the TMI nuclear facility and certain fossil sites and the loss on the sale of Oyster Creek to Holtec, partially offset by net realized gains related to
Oyster Creek's NDT fund investments, a net benefit associated with remeasurements of the TMI ARO, and a gain on the sale of certain wind assets.
(d) Primarily represents reorganization and severance costs related to cost management programs.
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(e) Reflects an adjustment to Generation's nuclear ARO for Non-Regulatory Agreement Units resulting from the annual update.
(f) Represents direct costs related to COVID-19 consisting primarily of costs to acquire personal protective equipment, costs for cleaning supplies and services, and costs to
hire healthcare professionals to monitor the health of employees.
(g) Reflects the payments made by ComEd under the Deferred Prosecution Agreement, which ComEd entered into on July 17, 2020 with the U.S. Attorney’s Office for the
Northern District of Illinois.
(h) Reflects costs related to the acquisition of EDF's interest in CENG.
(i) Reflects costs related to a multi-year ERP system implementation.
(j) Primarily reflects the adjustment to deferred income taxes due to changes in forecasted apportionment.
(k) Represents elimination from Generation’s results of the noncontrolling interests related to certain exclusion items. In 2020, primarily related to unrealized gains and losses
on NDT fund investments for CENG units. In 2019, primarily related to the impact of unrealized gains on NDT fund investments and the impact of the Generation's annual
nuclear ARO update for CENG units, partially offset by the impairment of certain equity investments in distributed energy companies.
Significant 2020 Transactions and Developments
Planned Separation
On February 21, 2021, Exelon’s Board of Directors approved a plan to separate the Utility Registrants and Generation, creating two publicly traded
companies with the resources necessary to best serve customers and sustain long-term investment and operating excellence. The separation gives each
company the financial and strategic independence to focus on its specific customer needs, while executing its core business strategy. See Note 26 —
Subsequent Events of the Combined Notes to Consolidated Financial Statements for additional information.
Impacts of February 2021 Weather Events and Texas-based Generating Assets Outages
Beginning on February 15, 2021, Generation’s Texas-based generating assets within the ERCOT market, specifically Colorado Bend II, Wolf Hollow II, and
Handley, experienced periodic outages as a result of historically severe cold weather conditions. In addition, those weather conditions drove increased
demand for service, limited the availability of natural gas to fuel power plants, and dramatically increased wholesale power and gas prices.
Exelon and Generation estimate the impact to their Net income for the first quarter of 2021 arising from these market and weather conditions to be
approximately $560 million to $710 million. The estimated impact includes favorable results in certain regions within Generation’s wholesale gas business.
The ultimate impact to Exelon’s and Generation’s consolidated financial statements may be affected by a number of factors, including final settlement data,
the impacts of customer and counterparty credit losses, any state sponsored solutions to address the financial challenges caused by the event, and litigation
and contract disputes which may result. Exelon expects to offset between $410 million and $490 million of this impact primarily at Generation through a
combination of enhanced revenue opportunities, deferral of selected non-essential maintenance, and primarily one-time cost savings.
See Note 26 — Subsequent Events of the Combined Notes to Consolidated Financial Statements for additional information.
Agreement for Sale of Generation’s Solar Business
On December 8, 2020, Generation entered into an agreement with an affiliate of Brookfield Renewable, for the sale of a significant portion of Generation’s
solar business, including 360 megawatts of generation in operation or under construction across more than 600 sites across the United States, for a
purchase price of $810 million. Completion of the transaction is expected to occur in the first half of 2021. Generation will retain certain solar assets not
included in this agreement, primarily Antelope Valley. See Note 2 — Mergers, Acquisitions, and Dispositions of the Combined Notes to Consolidated
Financial Statements for additional information.
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Early Retirement of Generation Facilities
In August 2020, Generation announced that it intends to retire the Byron Generating Station in September 2021, Dresden Generating Station in November
2021, and Mystic Units 8 and 9 at the expiration of the cost of service commitment in May 2024. As a result, in the third quarter of 2020, Exelon and
Generation recognized a $500 million impairment of its New England asset group and one-time non-cash charges for Byron, Dresden, and Mystic related to
materials and supplies inventory reserve adjustments, employee-related costs, and construction work-in-progress impairments, among other items. In
addition, there will be ongoing annual financial impacts stemming from shortening the expected economic useful lives of these facilities, primarily related to
accelerated depreciation of plant assets (including any ARC) and accelerated amortization of nuclear fuel. Such ongoing charges are excluded from
Adjusted (non-GAAP) Operating Earnings.
The following table summarizes the incremental expense recorded for the year ended December 31, 2020 and the estimated amounts of incremental
expense expected to be incurred through the retirement dates.
Income statement expense (pre-tax)
Actual
2020
2021
2022
2023
2024
Projected
(a)
Depreciation and amortization
(b)
Accelerated depreciation
Accelerated nuclear fuel amortization
Operating and maintenance
One-time charges
Other charges
Contractual offset
(d)
(c)
Total
$
$
921 $
60
277
35
(364)
929 $
2,070 $
170
30
10
(475)
1,805 $
110 $
—
10
10
—
130 $
120 $
—
—
10
—
130 $
50
—
20
5
—
75
_________
(a) Actual results may differ based on incremental future capital additions, actual units of production for nuclear fuel amortization, future revised ARO assumptions, etc.
(b) Reflects incremental accelerated depreciation of plant assets, including any ARC.
(c) Reflects primarily the net impacts associated with the remeasurement of the ARO for Dresden. See Note 10 – Asset Retirement Obligations of the Combined Notes to
Consolidated Financial Statements for additional information.
(d) Reflects contractual offset for ARO accretion, ARC depreciation, and net impacts associated with the remeasurement of the ARO for Byron and Dresden. Based on the
regulatory agreement with the ICC, decommissioning-related activities are offset within Exelon's and Generation's Consolidated Statements of Operations and
Comprehensive Income as long as the net cumulative decommissioning-related activities result in a regulatory liability at ComEd. Recognition of a regulatory asset for
nuclear decommissioning-related activities at ComEd is not permissible. The offset results in an equal adjustment to the noncurrent payables to ComEd at Generation and
an adjustment to the regulatory liabilities at ComEd. See Note 10 – Asset Retirement Obligations of the Combined Notes to Consolidated Financial Statements for
additional information.
Deferred Prosecution Agreement
On July 17, 2020, ComEd entered into a Deferred Prosecution Agreement (DPA) with the U.S. Attorney’s Office for the Northern District of Illinois (USAO) to
resolve the USAO’s investigation into ComEd’s lobbying activities in the State of Illinois. Under the DPA, the USAO filed a single charge alleging that ComEd
improperly gave and offered to give jobs, vendor subcontracts, and payments associated with those jobs and subcontracts for the benefit of the Speaker of
the Illinois House of Representatives and the Speaker’s associates, with the intent to influence the Speaker’s action regarding legislation affecting ComEd’s
interests. The DPA provides that the USAO will defer any prosecution of such charge and any other criminal or civil case against ComEd in connection with
the matters identified therein for a three-year period subject to certain obligations of ComEd, including payment to the United States Treasury of $200 million,
with $100 million payable within thirty days of the filing of the DPA with the United States District Court for the Northern District of Illinois and an additional
$100 million within ninety days of such filing date. The payments will not be recovered in rates or charged to customers, and ComEd will not seek or accept
reimbursement or indemnification from any source other than Exelon. See Note 19 — Commitments and Contingencies for additional information.
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Utility Distribution Base Rate Case Proceedings
The Utility Registrants file base rate cases with their regulatory commissions seeking increases or decreases to their electric transmission and distribution,
and gas distribution rates to recover their costs and earn a fair return on their investments. The outcomes of these regulatory proceedings impact the Utility
Registrants’ current and future financial statements.
The following tables show the Utility Registrants’ completed and pending distribution base rate case proceedings in 2020. See Note 3 — Regulatory Matters
of the Combined Notes to Consolidated Financial Statements for additional information on these and other regulatory proceedings.
Completed Distribution Base Rate Case Proceedings
Registrant/Jurisdiction
Filing Date
Service
Requested
Revenue
Requirement
(Decrease)
Increase
Approved Revenue
Requirement
(Decrease) Increase
ComEd - Illinois
April 8, 2019
Electric
$
(6) $
ComEd - Illinois
April 16, 2020
Electric
BGE - Maryland
DPL - Maryland
DPL - Delaware
May 15, 2020
(amended September
11, 2020)
Electric
Natural Gas
December 5, 2019
(amended April 23,
2020)
February 21, 2020
(amended October 9,
2020)
Electric
Natural Gas
(11)
137
91
17
7
65
(17)
(14)
81
21
12
2
Approved ROE
Approval Date
Rate Effective Date
8.91 %
8.38 %
9.50 %
9.65 %
December 4,
2019
December 9,
2020
January 1, 2020
January 1, 2021
December 16,
2020
January 1, 2021
9.60 % July 14, 2020
July 16, 2020
9.60 % January 6, 2021
September 21,
2020
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Pending Distribution Base Rate Case Proceedings
Registrant/Jurisdiction
Filing Date
Service
Requested Revenue
Requirement Increase
PECO - Pennsylvania
Pepco - District of Columbia
Pepco - Maryland
DPL - Delaware
ACE - New Jersey
September 30, 2020
May 30, 2019 (amended
June 1, 2020)
October 26, 2020
March 6, 2020 (amended
February 2, 2021)
December 9, 2020
Natural Gas
$
Electric
Electric
Electric
Electric
Transmission Formula Rates
69
136
110
23
67
Requested ROE
Expected Approval Timing
10.95 %
Second quarter of 2021
9.7 %
Second quarter of 2021
10.2 %
10.3 %
10.3 %
Second quarter of 2021
Third quarter of 2021
Fourth quarter of 2021
The following total increases/(decreases) were included in the Utility Registrants' 2020 annual electric transmission formula rate updates. See Note 3 —
Regulatory Matters of the Combined Notes to Consolidated Financial Statements for additional information.
Registrant
Initial Revenue
Requirement
Increase/(Decrease)
Annual Reconciliation
Decrease
Total Revenue
Requirement
Increase/(Decrease)
Allowed Return on
Rate Base
Allowed ROE
ComEd
PECO
BGE
Pepco
DPL
ACE
$
18 $
5
16
2
(4)
5
(4) $
(28)
(3)
(46)
(40)
(25)
14
(23)
4
(44)
(44)
(20)
8.17 %
7.47 %
7.26 %
7.81 %
7.20 %
7.40 %
11.50 %
10.35 %
10.50 %
10.50 %
10.50 %
10.50 %
Sales of Customer Accounts Receivable
On April 8, 2020, NER, a bankruptcy remote, special purpose entity, which is wholly owned by Generation, entered into an accounts receivable financing
facility with a number of financial institutions and a commercial paper conduit to sell certain customer accounts receivables. Generation received
approximately $500 million of cash in accordance with the initial sale of approximately $1.2 billion receivables. See Note 6 — Accounts Receivable of the
Combined Notes to Consolidated Financial Statements for additional information.
Exelon’s Strategy and Outlook
On February 21, 2021, Exelon’s Board of Directors approved a plan to separate the Utility Registrants and Generation, creating two publicly traded
companies with the resources necessary to best serve customers and sustain long-term investment and operating excellence. The separation gives each
company the financial and strategic independence to focus on its specific customer needs, while executing its core business strategy. See Note 26 —
Subsequent Events of the Combined Notes to Consolidated Financial Statements for additional information.
In 2021, the businesses remain focused on maintaining industry leading operational excellence, meeting or exceeding their financial commitments, ensuring
timely recovery on investments to enable customer benefits, supporting enactment of clean energy policies, and continued commitment to corporate
responsibility.
Exelon’s utility strategy is to improve reliability and operations and enhance the customer experience, while ensuring ratemaking mechanisms provide the
utilities fair financial returns. The Utility Registrants only invest in rate base where it provides a benefit to customers and the community by improving
reliability and the service experience or otherwise meeting customer needs. The Utility Registrants make these investments at the lowest
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reasonable cost to customers. Exelon seeks to leverage its scale and expertise across the utilities platform through enhanced standardization and sharing of
resources and best practices to achieve improved operational and financial results. Additionally, the Utility Registrants anticipate making significant future
investments in smart grid technology, transmission projects, gas infrastructure, and electric system improvement projects, providing greater reliability and
improved service for our customers and a stable return for the company.
Generation’s competitive businesses create value for customers by providing innovative energy solutions and reliable, clean, and affordable energy.
Generation’s electricity generation strategy is to pursue opportunities that provide stable revenues and match supply to customers. Generation leverages its
energy generation portfolio to deliver energy to both wholesale and retail customers. Generation’s customer-facing activities foster development and delivery
of other innovative energy-related products and services for its customers. Generation operates in well-developed energy markets and employs an
integrated hedging strategy to manage commodity price volatility. Its generation fleet, including its nuclear plants which consistently operate at high capacity
factors, also provide geographic and supply source diversity. These factors help Generation mitigate the current challenging conditions in competitive energy
markets.
Various market, financial, regulatory, legislative and operational factors could affect the Registrants' success in pursuing their strategies. Exelon continues to
assess infrastructure, operational, commercial, policy, and legal solutions to these issues. One key issue is ensuring the ability to properly value nuclear
generation assets in the market, solutions to which Exelon is actively pursuing in a variety of jurisdictions and venues. See ITEM 1A. RISK FACTORS for
additional information regarding market and financial factors.
Growth Opportunities
Management continually evaluates growth opportunities aligned with Exelon’s businesses, assets and markets, leveraging Exelon’s expertise in those areas
and offering sustainable returns.
Regulated Energy Businesses. The Utility Registrants anticipate investing approximately $27 billion over the next four years in electric and natural gas
infrastructure improvements and modernization projects, including smart grid technology, storm hardening, advanced reliability technologies, and
transmission projects, which is projected to result in an increase to current rate base of approximately $15 billion by the end of 2024. The Utility Registrants
invest in rate base where beneficial to customers and the community by increasing reliability and the service experience or otherwise meeting customer
needs. These investments are made at the lowest reasonable cost to customers.
Competitive Energy Businesses. Generation continually assesses the optimal structure and composition of its generation assets as well as explores
wholesale and retail opportunities within the power and gas sectors. Generation’s strategy is to ensure appropriate valuation of its generation assets, in part
through public policy efforts, identify and capitalize on opportunities that match supply to customers as a means to provide stable earnings, and identify
emerging technologies where strategic investments provide the option for significant future growth or influence in market development.
Other Key Business Drivers and Management Strategies
Utility Rates and Rate Proceedings
The Utility Registrants file rate cases with their regulatory commissions seeking increases or decreases to their electric transmission and distribution, and
gas distribution rates to recover their costs and earn a fair return on their investments. The outcomes of these regulatory proceedings impact the Utility
Registrants’ current and future results of operations, cash flows, and financial positions. See Note 3 — Regulatory Matters of the Combined Notes to
Consolidated Financial Statements for additional information on these regulatory proceedings.
Power Markets
Price of Fuels
The use of new technologies to recover natural gas from shale deposits is increasing natural gas supply and reserves, which places downward pressure on
natural gas prices and, therefore, on wholesale and retail power prices, which results in a reduction in Exelon’s revenues. Forward natural gas prices have
declined significantly
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over the last several years; in part reflecting an increase in supply due to strong natural gas production (due to shale gas development).
Section 232 Uranium Petition
On January 16, 2018, two Canadian-owned uranium mining companies with operations in the U.S. jointly submitted a petition to the U.S. Department of
Commerce ("DOC") seeking relief under Section 232 of the Trade Expansion Act of 1962 from imports of uranium products, alleging that these imports
threaten national security.
The United States Nuclear Fuel Working Group ("Working Group") report was made public on April 23, 2020. The Working Group report states that nuclear
power is intrinsically tied to national security, and promises that the U.S. government will take bold actions to strengthen all parts of the nuclear fuel industry
in the U.S. It recommends the Agreement Suspending the Antidumping Investigation on Uranium from the Russian Federation (the “Russian Suspension
Agreement” or "RSA") be extended and to consider reducing the amount of Russian imports of nuclear fuel. The Russian Suspension Agreement is the
historical resolution of a 1991 DOC investigation that found that the Russians had been selling or “dumping” cheap uranium products into the U.S. The RSA
has been amended several times in the intervening years to allow Russia to supply limited amounts of uranium products into the U.S. It was set to expire at
the end of 2020, but was amended on October 5, 2020 to extend for another 20 years.
The Working Group report should be viewed as policy recommendations that may be implemented by executive agencies, congress, and or regulatory
bodies. Exelon and Generation cannot currently predict the outcome of all of the policy changes recommended by the Working Group.
Complaint at FERC Seeking to Alter Capacity Market Default Offer Caps
On February 21, 2019, PJM's Independent Market Monitor (IMM) filed a complaint alleging that the number of performance assessment intervals used to
calculate the default offer cap for bids to supply capacity in PJM is too high, resulting in an overstated default offer cap that obviates the need for most
sellers to seek unit-specific approval of their offers. The IMM claims that this allows for the exercise of market power. The IMM asks FERC to require PJM to
reduce the number of performance assessment intervals used to calculate the opportunity costs of a capacity supplier assuming a capacity obligation. This
would, in turn, lower the default offer cap and allow the IMM to review more offers on a unit-specific basis. It is too early to predict the final outcome of this
proceeding or its potential financial impact, if any, on Exelon or Generation.
Energy Demand
Load growth at the Utility Registrants is driven by recovery from COVID-19 impacts. ComEd and PECO are projecting modest growth in load of 2.5% and
1.8%, respectively, in 2021 as compared to reduced load in 2020. BGE, Pepco, DPL, and ACE are projecting slower growth as prolonged COVID-19 impacts
decrease load by (2.0)%, (0.8)%, (0.9)%, and (2.4)%, respectively, in 2021 compared to 2020.
Retail Competition
Generation’s retail operations compete for customers in a competitive environment, which affect the margins that Generation can earn and the volumes that
it is able to serve. Forward natural gas and power prices are expected to remain low and thus we expect retail competitors to stay aggressive in their pursuit
of market share, and that wholesale generators (including Generation) will continue to use their retail operations to hedge generation output.
Hedging Strategy
Exelon’s policy to hedge commodity risk on a ratable basis over three-year periods is intended to reduce the financial impact of market price volatility.
Generation is exposed to commodity price risk associated with the unhedged portion of its electricity portfolio. Generation enters into non-derivative and
derivative contracts, including financially-settled swaps, futures contracts and swap options, and physical options and physical forward contracts, all with
credit-approved counterparties, to hedge this anticipated exposure. As of December 31, 2020, the percentage of expected generation hedged for the Mid-
Atlantic, Midwest, New York, and ERCOT reportable segments is 94%-97% for 2021. Generation has been and will continue to be proactive in using hedging
strategies to mitigate commodity price risk.
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Generation procures natural gas through long-term and short-term contracts and spot-market purchases. Nuclear fuel assemblies are obtained
predominantly through long-term uranium concentrate supply contracts, contracted conversion services, contracted enrichment services, or a combination
thereof, and contracted fuel fabrication services. The supply markets for uranium concentrates and certain nuclear fuel services are subject to price
fluctuations and availability restrictions. Approximately 60% of Generation’s uranium concentrate requirements from 2021 through 2025 are supplied by three
suppliers. In the event of non-performance by these or other suppliers, Generation believes that replacement uranium concentrate can be obtained, although
at prices that may be unfavorable when compared to the prices under the current supply agreements. Non-performance by these counterparties could have
a material adverse impact on Exelon’s and Generation’s consolidated financial statements.
See Note 16 — Derivative Financial Instruments of the Combined Notes to Consolidated Financial Statements and ITEM 7A. QUANTITATIVE AND
QUALITATIVE DISCLOSURES ABOUT MARKET RISK for additional information.
The Utility Registrants mitigate commodity price risk through regulatory mechanisms that allow them to recover procurement costs from retail customers.
Other Legislative and Regulatory Developments
Illinois Clean Energy Progress Act
On March 14, 2019, the Clean Energy Progress Act was introduced in the Illinois General Assembly to preserve Illinois’ clean energy choices arising from
FEJA and empower the IPA to conduct capacity procurements outside of PJM’s base residual auction process, while utilizing the FRR provisions in PJM's
tariffs which are still subject to penalties and other obligations under the PJM tariffs. The most significant provisions of the proposed legislation are as
follows: (1) it allows the IPA to procure capacity directly from clean energy resources that have previously sold ZECs or RECs, including certain of
Generation’s nuclear plants in Illinois, or from new clean energy resources, (2) it establishes a goal of achieving 100% carbon-free power in the ComEd
service territory by 2032, and (3) it implements reforms to enhance consumer protections in the state’s competitive retail electricity and natural gas markets,
including Generation’s retail customers. Energy legislation has also been proposed by other stakeholders in 2019 and 2020, including renewable resource
developers, environmental advocates, and coal-fueled generators. Lawmakers focused their efforts on understanding all of the various legislative proposals
with the goal of developing a single comprehensive energy package for ultimate consideration by the General Assembly and Governor Pritzker. Due to the
COVID-19 pandemic, the legislative calendar during 2020 was severely curtailed stalling progress on comprehensive energy legislation. The fall 2020 veto
session was cancelled. The next opportunity for the General Assembly to consider development of comprehensive energy legislation appears to come
during the 2021 spring legislative session. Exelon and Generation will work with legislators and stakeholders and cannot predict the outcome or the potential
financial impact, if any, on Exelon or Generation.
Nuclear Powers Act of 2019
On April 12, 2019, the Nuclear Powers America Act of 2019 was introduced to the United States Congress, which expands the current investment tax credit
to existing nuclear power plants. The proposed legislation would provide a credit equal to 30% of continued capital investment in certain nuclear energy-
related expenditures, including capital expenses and nuclear fuel, starting from tax years 2019 through 2023. Thereafter, the credit rate would be reduced to
26% in 2024, 22% in 2025, and 10% in 2026 and beyond. To qualify for the credit, the plant must be currently operational and must have applied for an
operating license renewal before 2026. Exelon and Generation are working with legislators and stakeholders and cannot predict the outcome or the
potential financial impact, if any, on Exelon or Generation.
Critical Accounting Policies and Estimates
The preparation of financial statements in conformity with GAAP requires that management apply accounting policies and make estimates and assumptions
that affect results of operations and the amounts of assets and liabilities reported in the financial statements. Management believes that the accounting
policies described below require significant judgment in their application, or incorporate estimates and assumptions that are inherently
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uncertain and that may change in subsequent periods. Additional information of the application of these accounting policies can be found in the Combined
Notes to Consolidated Financial Statements.
Nuclear Decommissioning Asset Retirement Obligations (Exelon and Generation)
Generation’s ARO associated with decommissioning its nuclear units was $11.9 billion at December 31, 2020. The authoritative guidance requires that
Generation estimate its obligation for the future decommissioning of its nuclear generating plants. To estimate that liability, Generation uses an internally-
developed, probability-weighted, discounted cash flow model which, on a unit-by-unit basis, considers multiple decommissioning outcome scenarios.
As a result of recent nuclear plant retirements in the industry, nuclear operators and third-party service providers are obtaining more information about costs
associated with decommissioning activities. At the same time, regulators are gaining more information about decommissioning activities which could result in
changes to existing decommissioning requirements. In addition, as more nuclear plants are retired, it is possible that technological advances will be identified
that could create efficiencies and lead to a reduction in decommissioning costs. The availability of NDT funds could impact the timing of the
decommissioning activities. Additionally, certain factors such as changes in regulatory requirements during plant operations or the profitability of a nuclear
plant could impact the timing of plant retirements. These factors could result in material changes to Generation’s current estimates as more information
becomes available and could change the timing of plant retirements and the probability assigned to the decommissioning outcome scenarios.
The nuclear decommissioning obligation is adjusted on a regular basis due to the passage of time and revisions to the key assumptions for the expected
timing and/or estimated amounts of the future undiscounted cash flows required to decommission the nuclear plants, based upon the following
methodologies and significant estimates and assumptions:
Decommissioning Cost Studies. Generation uses unit-by-unit decommissioning cost studies to provide a marketplace assessment of the expected costs
(in current year dollars) and timing of decommissioning activities, which are validated by comparison to current decommissioning projects within the industry
and other estimates. Decommissioning cost studies are updated, on a rotational basis, for each of Generation’s nuclear units at least every five years, unless
circumstances warrant more frequent updates. As part of the annual cost study update process, Generation evaluates newly assumed costs or substantive
changes in previously assumed costs to determine if the cost estimate impacts are sufficiently material to warrant application of the updated estimates to the
AROs across the nuclear fleet outside of the normal five-year rotating cost study update cycle.
Cost Escalation Factors. Generation uses cost escalation factors to escalate the decommissioning costs from the decommissioning cost studies discussed
above through the assumed decommissioning period for each of the units. Cost escalation studies, updated on an annual basis, are used to determine
escalation factors, and are based on inflation indices for labor, equipment and materials, energy, LLRW disposal, and other costs. All of the nuclear AROs
are adjusted each year for the updated cost escalation factors.
Probabilistic Cash Flow Models. Generation’s probabilistic cash flow models include the assignment of probabilities to various scenarios for
decommissioning cost levels, decommissioning approaches, and timing of plant shutdown on a unit-by-unit basis. Probabilities assigned to cost levels
include an assessment of the likelihood of costs 20% higher (high-cost scenario) or 15% lower (low-cost scenario) than the base cost scenario. The
assumed decommissioning scenarios include the following three alternatives: (1) DECON which assumes decommissioning activities begin shortly after the
cessation of operation, (2) Shortened SAFSTOR generally has a 30-year delay prior to onset of decommissioning activities, and (3) SAFSTOR which
assumes the nuclear facility is placed and maintained in such condition that the nuclear facility can be safely stored and subsequently decontaminated
generally within 60 years after cessation of operations. In each decommissioning scenario, spent fuel is transferred to dry cask storage as soon as possible
until DOE acceptance for disposal.
The actual decommissioning approach selected once a nuclear facility is shutdown will be determined by Generation at the time of shutdown and may be
influenced by multiple factors including the funding status of the NDT fund at the time of shutdown.
The assumed plant shutdown timing scenarios include the following four alternatives: (1) the probability of operating through the original 40-year nuclear
license term, (2) the probability of operating through an extended
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60-year nuclear license term (regardless of whether such 20-year license extension has been received for each unit), (3) the probability of a second, 20-year
license renewal for some nuclear units, and (4) the probability of early plant retirement for certain sites due to changing market conditions and regulatory
environments. As power market and regulatory environment developments occur, Generation evaluates and incorporates, as necessary, the impacts of such
developments into its nuclear ARO assumptions and estimates.
Generation’s probabilistic cash flow models also include an assessment of the timing of DOE acceptance of SNF for disposal. Generation currently assumes
DOE will begin accepting SNF in 2035. The SNF acceptance date assumption is based on management’s estimates of the amount of time required for DOE
to select a site location and develop the necessary infrastructure for long-term SNF storage. For additional information regarding the estimated date when
DOE will begin accepting SNF, see Note 19 — Commitments and Contingencies of the Combined Notes to Consolidated Financial Statements.
Discount Rates. The probability-weighted estimated future cash flows for the various assumed scenarios are discounted using credit-adjusted, risk-free
rates (CARFR) applicable to the various businesses in which each of the nuclear units originally operated. Generation initially recognizes an ARO at fair
value and subsequently adjusts it for changes to estimated costs, timing of future cash flows and modifications to decommissioning assumptions. The ARO
is not required or permitted to be re-measured for changes in the CARFR that occur in isolation. Increases in the ARO as a result of upward revisions in
estimated undiscounted cash flows are considered new obligations and are measured using a current CARFR as the increase creates a new cost layer
within the ARO. Any decrease in the estimated undiscounted future cash flows relating to the ARO are treated as a modification of an existing ARO cost
layer and, therefore, is measured using the average historical CARFR rates used in creating the initial ARO cost layers. If Generation’s future nominal cash
flows associated with the ARO were to be discounted at current prevailing CARFR, the obligation would increase from approximately $11.9 billion to
approximately $15.0 billion.
The following table illustrates the significant impact that changes in the CARFR, when combined with changes in projected amounts and expected timing of
cash flows, can have on the valuation of the ARO (dollars in millions):
Change in the CARFR applied to the annual ARO update
2019 CARFR rather than the 2020 CARFR
2020 CARFR increased by 50 basis points
2020 CARFR decreased by 50 basis points
(Decrease) Increase to ARO at
December 31, 2020
$
(370)
(390)
490
ARO Sensitivities. Changes in the assumptions underlying the ARO could materially affect the decommissioning obligation. The impact to the ARO of a
change in any one of these assumptions is highly dependent on how the other assumptions may correspondingly change.
The following table illustrates the effects of changing certain ARO assumptions while holding all other assumptions constant (dollars in millions):
Change in ARO Assumption
Increase to ARO at December 31, 2020
Cost escalation studies
Uniform increase in escalation rates of 50 basis points
Probabilistic cash flow models
Increase the estimated costs to decommission the nuclear plants by 10 percent
Increase the likelihood of the DECON scenario by 10 percent and decrease the likelihood of the SAFSTOR scenario by 10
percent
Shorten each unit's probability weighted operating life assumption by 10 percent
Extend the estimated date for DOE acceptance of SNF to 2040
(a)
(b)
$
2,560
1,050
610
1,690
280
__________
(a) Excludes any sites in which management has committed to a specific decommissioning approach.
(b) Excludes any retired sites.
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See Note 1 — Significant Accounting Policies, Note 7 — Early Plant Retirements and Note 10 — Asset Retirement Obligations of the Combined Notes to
Consolidated Financial Statements for additional information regarding accounting for nuclear AROs.
Goodwill (Exelon, ComEd, and PHI)
As of December 31, 2020, Exelon’s $6.7 billion carrying amount of goodwill consists primarily of $2.6 billion at ComEd and $4 billion at PHI. These entities
are required to perform an assessment for possible impairment of their goodwill at least annually or more frequently if an event occurs or circumstances
change that would more likely than not reduce the fair value of the reporting units below their carrying amount. A reporting unit is an operating segment or
one level below an operating segment (known as a component) and is the level at which goodwill is assessed for impairment. ComEd has a single operating
segment and reporting unit. PHI’s operating segments and reporting units are Pepco, DPL, and ACE. See Note 5 — Segment Information of the Combined
Notes to Consolidated Financial Statements for additional information. Exelon's and ComEd’s goodwill has been assigned entirely to the ComEd reporting
unit. Exelon's and PHI’s goodwill has been assigned to the Pepco, DPL, and ACE reporting units in the amounts of $2.1 billion, $1.4 billion, and $0.5 billion,
respectively. See Note 13 — Intangible Assets of the Combined Notes to Consolidated Financial Statements for additional information.
Entities assessing goodwill for impairment have the option of first performing a qualitative assessment to determine whether a quantitative assessment is
necessary. As part of the qualitative assessments, Exelon, ComEd, and PHI evaluate, among other things, management's best estimate of projected
operating and capital cash flows for their businesses, outcomes of recent regulatory proceedings, changes in certain market conditions, including the
discount rate and regulated utility peer EBITDA multiples, and the passing margin from their last quantitative assessments performed.
Application of the goodwill impairment assessment requires management judgment, including the identification of reporting units and determining the fair
value of the reporting unit, which management estimates using a weighted combination of a discounted cash flow analysis and a market multiples analysis.
Significant assumptions used in these fair value analyses include discount and growth rates, utility sector market performance and transactions, and
projected operating and capital cash flows for ComEd’s, Pepco's, DPL's, and ACE's businesses and the fair value of debt.
While the 2020 annual assessments indicated no impairments, certain assumptions used in the assessment are highly sensitive to changes. Adverse
regulatory actions or changes in significant assumptions could potentially result in future impairments of Exelon’s, ComEd's, or PHI’s goodwill, which could
be material.
See Note 1 — Significant Accounting Policies and Note 13 — Intangible Assets of the Combined Notes to Consolidated Financial Statements for additional
information.
Unamortized Energy Contract Assets and Liabilities (Exelon, Generation, and PHI)
Unamortized energy contract assets and liabilities represent the remaining unamortized balances of non-derivative energy contracts that Generation has
acquired and the electricity contracts Exelon acquired as part of the PHI merger. The initial amount recorded represents the fair value of the contracts at the
time of acquisition. At Exelon and PHI, offsetting regulatory assets or liabilities were also recorded for those energy contract costs that are probable of
recovery or refund through customer rates. The unamortized energy contract assets and liabilities and any corresponding regulatory assets or liabilities,
respectively, are amortized over the life of the contract in relation to the expected realization of the underlying cash flows. Amortization of the unamortized
energy contract assets and liabilities is recorded through purchased power and fuel expense or operating revenues, depending on the nature of the
underlying contract. See Note 3 — Regulatory Matters and Note 13 — Intangible Assets of the Combined Notes to Consolidated Financial Statements for
additional information.
Impairment of Long-Lived Assets (All Registrants)
All Registrants regularly monitor and evaluate the carrying value of long-lived assets and asset groups for recoverability whenever events or changes in
circumstances indicate that the carrying value of those assets may not be recoverable. Indicators of potential impairment may include a deteriorating
business climate, including, but not limited to, declines in energy prices, condition of the asset, an asset remaining idle for more than a short period of time,
specific regulatory disallowance, advances in technology, plans to dispose of a long-lived asset
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significantly before the end of its useful life, and financial distress of a third party for assets contracted with them on a long-term basis, among others.
The review of long-lived assets and asset groups for impairment utilizes significant assumptions about operating strategies and estimates of future cash
flows, which require assessments of current and projected market conditions. For the generation business, forecasting future cash flows requires
assumptions regarding forecasted commodity prices for the sale of power and purchases of fuel and the expected operations of assets. A variation in the
assumptions used could lead to a different conclusion regarding the recoverability of an asset or asset group and, thus, could potentially result in material
future impairments. An impairment evaluation is based on an undiscounted cash flow analysis at the lowest level at which cash flows of the long-lived assets
or asset groups are largely independent of the cash flows of other assets and liabilities. For the generation business, the lowest level of independent cash
flows is determined by the evaluation of several factors, including the geographic dispatch of the generation units and the hedging strategies related to those
units as well as the associated intangible assets or liabilities recorded on the balance sheet. The cash flows from the generating units are generally
evaluated at a regional portfolio level with cash flows generated from the customer supply and risk management activities, including cash flows from related
intangible assets and liabilities on the balance sheet. In certain cases, generating assets may be evaluated on an individual basis where those assets are
contracted on a long-term basis with a third party and operations are independent of other generating assets (typically contracted renewables). For such
assets the financial viability of the third party, including the impact of bankruptcy on the contract, may be a significant assumption in the assessment.
On a quarterly basis, Generation assesses its long-lived assets or asset groups for indicators of impairment. If indicators are present for a long-lived asset or
asset group, a comparison of the undiscounted expected future cash flows to the carrying value is performed. When the undiscounted cash flow analysis
indicates the carrying value of a long-lived asset or asset group is not recoverable, the amount of the impairment loss is determined by measuring the
excess of the carrying amount of the long-lived asset or asset group over its fair value. The fair value of the long-lived asset or asset group is dependent
upon a market participant’s view of the exit price of the assets. This includes significant assumptions of the estimated future cash flows generated by the
assets and market discount rates. Events and circumstances often do not occur as expected resulting in differences between prospective financial
information and actual results, which may be material. The determination of fair value is driven by both internal assumptions that include significant
unobservable inputs (Level 3) such as revenue and generation forecasts, projected capital, and maintenance expenditures and discount rates, as well as
information from various public, financial and industry sources.
See Note 12 — Asset Impairments of the Combined Notes to Consolidated Financial Statements for a discussion of asset impairment assessments.
Depreciable Lives of Property, Plant, and Equipment (All Registrants)
The Registrants have significant investments in electric generation assets and electric and natural gas transmission and distribution assets. These assets
are generally depreciated on a straight-line basis, using the group, composite, or unitary methods of depreciation. The group approach is typically for groups
of similar assets that have approximately the same useful lives and the composite approach is used for heterogeneous assets that have different lives.
Under both methods, a reporting entity depreciates the assets over the average life of the assets in the group. The estimation of asset useful lives requires
management judgment, supported by formal depreciation studies of historical asset retirement experience. Depreciation studies are generally completed
every five years, or more frequently if required by a rate regulator or if an event, regulatory action, or change in retirement patterns indicate an update is
necessary.
For the Utility Registrants, depreciation studies generally serve as the basis for amounts allowed in customer rates for recovery of depreciation costs.
Generally, the Utility Registrants adjust their depreciation rates for financial reporting purposes concurrent with adjustments to depreciation rates reflected in
customer rates, unless the depreciation rates reflected in customer rates do not align with management’s judgment as to an appropriate estimated useful life
or have not been updated on a timely basis. Depreciation expense and customer rates for ComEd, BGE, Pepco, DPL, and ACE include an estimate of the
future costs of dismantling and removing plant from service upon retirement. See Note 3 — Regulatory Matters of the Combined Notes to the Consolidated
Financial Statements for information regarding regulatory liabilities and assets recorded by ComEd, BGE, Pepco, DPL, and ACE related to removal costs.
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PECO’s removal costs are capitalized to accumulated depreciation when incurred, and recorded to depreciation expense over the life of the new asset
constructed consistent with PECO’s regulatory recovery method. Estimates for such removal costs are also evaluated in the periodic depreciation studies.
At Generation, along with depreciation study results, management considers expected future energy market conditions and generation plant operating costs
and capital investment requirements in determining the estimated service lives of its generating facilities and reassesses the reasonableness of estimated
useful lives whenever events or changes in circumstances warrant. When a determination has been made that an asset will be retired before the end of its
current estimated useful life, depreciation provisions will be accelerated to reflect the shortened estimated useful life, which could have a material
unfavorable impact on Exelon’s and Generation’s future results of operations. See Note 7 — Early Plant Retirements of the Combined Notes to the
Consolidated Financial Statements for additional information.
Changes in estimated useful lives of electric generation assets and of electric and natural gas transmission and distribution assets could have a significant
impact on the Registrants’ future results of operations. See Note 1 — Significant Accounting Policies of the Combined Notes to Consolidated Financial
Statements for information regarding depreciation and estimated service lives of the property, plant, and equipment of the Registrants.
Defined Benefit Pension and Other Postretirement Employee Benefits (All Registrants)
Exelon sponsors defined benefit pension plans and OPEB plans for substantially all current employees. The measurement of the plan obligations and costs
of providing benefits involves various factors, including the development of valuation assumptions and inputs and accounting policy elections. When
developing the required assumptions, Exelon considers historical information as well as future expectations. The measurement of benefit obligations and
costs is affected by several assumptions including the discount rate, the long-term expected rate of return on plan assets, the anticipated rate of increase of
health care costs, Exelon's contributions, the rate of compensation increases, and the long-term expected investment rate credited to employees of certain
plans, among others. The assumptions are updated annually and upon any interim remeasurement of the plan obligations.
Pension and OPEB plan assets include equity securities, including U.S. and international securities, and fixed income securities, as well as certain
alternative investment classes such as real estate, private equity, and hedge funds.
Expected Rate of Return on Plan Assets. In determining the EROA, Exelon considers historical economic indicators (including inflation and GDP growth)
that impact asset returns, as well as expectation regarding future long-term capital market performance, weighted by Exelon’s target asset class allocations.
Exelon calculates the amount of expected return on pension and OPEB plan assets by multiplying the EROA by the MRV of plan assets at the beginning of
the year, taking into consideration anticipated contributions and benefit payments to be made during the year. In determining MRV, the authoritative guidance
for pensions and postretirement benefits allows the use of either fair value or a calculated value that recognizes changes in fair value in a systematic and
rational manner over not more than five years. For the majority of pension plan assets, Exelon uses a calculated value that adjusts for 20% of the difference
between fair value and expected MRV of plan assets. Use of this calculated value approach enables less volatile expected asset returns to be recognized as
a component of pension cost from year to year. For OPEB plan assets and certain pension plan assets, Exelon uses fair value to calculate the MRV.
Discount Rate. The discount rates are determined by developing a spot rate curve based on the yield to maturity of a universe of high-quality non-callable
(or callable with make whole provisions) bonds with similar maturities to the related pension and OPEB obligations. The spot rates are used to discount the
estimated future benefit distribution amounts under the pension and OPEB plans. The discount rate is the single level rate that produces the same result as
the spot rate curve. Exelon utilizes an analytical tool developed by its actuaries to determine the discount rates.
Mortality. The mortality assumption is composed of a base table that represents the current expectation of life expectancy of the population adjusted by an
improvement scale that attempts to anticipate future improvements in life expectancy. Exelon’s mortality assumption utilizes the SOA 2019 base table (Pri-
2012) and MP-2020 improvement scale adjusted to use Proxy SSA ultimate improvement rates.
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Sensitivity to Changes in Key Assumptions. The following tables illustrate the effects of changing certain of the actuarial assumptions discussed above,
while holding all other assumptions constant (dollars in millions):
Actuarial Assumption
Change in 2020 cost:
Discount rate
(a)
EROA
Change in benefit obligation at December 31,
2020:
Discount rate
(a)
Actual Assumption
Pension
OPEB
Change in
Assumption
3.34%
3.34%
7.00%
7.00%
2.58%
2.58%
3.31%
3.31%
6.69%
6.69%
2.51%
2.51%
0.5%
(0.5)%
0.5%
(0.5)%
0.5%
(0.5)%
Pension
OPEB
Total
$
(52) $
70
(91)
91
(14) $
15
(12)
12
(66)
85
(103)
103
(1,410)
1,631
(268)
309
(1,678)
1,940
__________
(a)
In general, the discount rate will have a larger impact on the pension and OPEB cost and obligation as the rate moves closer to 0%. Therefore, the discount rate
sensitivities above cannot necessarily be extrapolated for larger increases or decreases in the discount rate. Additionally, Exelon utilizes a liability-driven investment
strategy for its pension asset portfolio. The sensitivities shown above do not reflect the offsetting impact that changes in discount rates may have on pension asset returns.
See Note 1 — Significant Accounting Policies and Note 15 — Retirement Benefits of the Combined Notes to Consolidated Financial Statements for
additional information regarding the accounting for the defined benefit pension plans and OPEB plans.
Regulatory Accounting (Exelon and Utility Registrants)
For their regulated electric and gas operations, Exelon and the Utility Registrants reflect the effects of cost-based rate regulation in their financial statements,
which is required for entities with regulated operations that meet the following criteria: (1) rates are established or approved by a third-party regulator;
(2) rates are designed to recover the entities’ cost of providing services or products; and (3) a reasonable expectation that rates designed to recover costs
can be charged to and collected from customers. Regulatory assets represent incurred costs that have been deferred because of their probable future
recovery from customers through regulated rates. Regulatory liabilities represent (1) revenue or gains that have been deferred because it is probable such
amounts will be returned to customers through future regulated rates; or (2) billings in advance of expenditures for approved regulatory programs. If it is
concluded in a future period that a separable portion of operations no longer meets the criteria discussed above, Exelon and the Utility Registrants would be
required to eliminate any associated regulatory assets and liabilities and the impact, which could be material, would be recognized in the Consolidated
Statements of Operations and Comprehensive Income.
The following table illustrates the gains (losses) that could result from the elimination of regulatory assets and liabilities and charges against OCI (dollars in
millions before taxes) related to deferred costs associated with Exelon's pension and OPEB plans that are recorded as regulatory assets in Exelon's
Consolidated Balance Sheets:
December 31, 2020
Exelon
ComEd
PECO
BGE
PHI
Pepco
DPL
ACE
Gain (loss)
Charge against OCI
(a)
$
$
79
3,984
$
$
4,664 $
(177) $
— $
— $
490 $
— $
(798) $
— $
(94) $
— $
260 $
— $
(152)
—
___________
(a) Exelon's charge against OCI (before taxes) consists of up to $2.7 billion, $481 million, $193 million, $387 million, $188 million, and $91 million related to ComEd's, BGE's,
PHI's, Pepco's, DPL's, and ACE's respective portions of the deferred costs associated with Exelon's pension and OPEB plans. Exelon also has a net regulatory liability of
$(36) million (before taxes) related to PECO’s portion of the deferred costs associated with Exelon’s OPEB plans that would result in an increase in OCI if reversed.
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See Note 3 — Regulatory Matters of the Combined Notes to Consolidated Financial Statements for additional information regarding regulatory matters,
including the regulatory assets and liabilities tables of Exelon and the Utility Registrants.
For each regulatory jurisdiction in which they conduct business, Exelon and the Utility Registrants assess whether the regulatory assets and liabilities
continue to meet the criteria for probable future recovery or refund at each balance sheet date and when regulatory events occur. This assessment includes
consideration of recent rate orders, historical regulatory treatment for similar costs in each Registrant's jurisdictions, and factors such as changes in
applicable regulatory and political environments. If the assessments and estimates made by Exelon and the Utility Registrants for regulatory assets and
regulatory liabilities are ultimately different than actual regulatory outcomes, the impact in their consolidated financial statements could be material.
Refer to the revenue recognition discussion below for additional information on the annual revenue reconciliations associated with ICC-approved electric
distribution and energy efficiency formula rates for ComEd, and FERC transmission formula rate tariffs for the Utility Registrants.
Accounting for Derivative Instruments (All Registrants)
The Registrants use derivative instruments to manage commodity price risk, foreign currency exchange risk, and interest rate risk related to ongoing
business operations. The Registrants’ derivative activities are in accordance with Exelon’s Risk Management Policy (RMP). See Note 16 — Derivative
Financial Instruments of the Combined Notes to Consolidated Financial Statements for additional information.
The Registrants account for derivative financial instruments under the applicable authoritative guidance. Determining whether a contract qualifies as a
derivative requires that management exercise significant judgment, including assessing market liquidity as well as determining whether a contract has one or
more underlyings and one or more notional quantities. Changes in management’s assessment of contracts and the liquidity of their markets, and changes in
authoritative guidance, could result in previously excluded contracts becoming in scope of new authoritative guidance.
All derivatives are recognized on the balance sheet at their fair value, except for certain derivatives that qualify for, and are elected under, NPNS. Derivatives
entered into for economic hedging and for proprietary trading purposes are recorded at fair value through earnings. For economic hedges that are not
designated for hedge accounting for the Utility Registrants, changes in the fair value each period are generally recorded with a corresponding offsetting
regulatory asset or liability given likelihood of recovering the associated costs through customer rates.
NPNS. As part of Generation’s energy marketing business, Generation enters into contracts to buy and sell energy to meet the requirements of its
customers. These contracts include short-term and long-term commitments to purchase and sell energy and energy-related products in the retail and
wholesale markets with the intent and ability to deliver or take delivery. While some of these contracts are considered derivative financial instruments under
the authoritative guidance, certain of these qualifying transactions have been designated by Generation as NPNS transactions, which are thus not required
to be recorded at fair value, but rather on an accrual basis of accounting. Determining whether a contract qualifies for the NPNS requires judgment on
whether the contract will physically deliver and requires that management ensure compliance with all of the associated qualification and documentation
requirements. Revenues and expenses on contracts that qualify as NPNS are recognized when the underlying physical transaction is completed. Contracts
that qualify for the NPNS are those for which physical delivery is probable, quantities are expected to be used or sold in the normal course of business over
a reasonable period of time, and the contract is not financially settled on a net basis. The contracts that ComEd has entered into with suppliers as part of
ComEd’s energy procurement process, PECO’s full requirement contracts under the PAPUC-approved DSP program, most of PECO’s natural gas supply
agreements, all of BGE’s full requirement contracts and natural gas supply agreements that are derivatives, and certain Pepco, DPL, and ACE full
requirement contracts qualify for and are accounted for under the NPNS.
Commodity Contracts. Identification of a commodity contract as an economic hedge requires Generation to determine that the contract is in accordance
with the RMP. Generation reassesses its economic hedges on a regular basis to determine if they continue to be within the guidelines of the RMP.
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As a part of the authoritative guidance, the Registrants make estimates and assumptions concerning future commodity prices, load requirements, interest
rates, the timing of future transactions and their probable cash flows, the fair value of contracts and the expected changes in the fair value in deciding
whether or not to enter into derivative transactions, and in determining the initial accounting treatment for derivative transactions. Under the authoritative
guidance for fair value measurements, the Registrants categorize these derivatives under a fair value hierarchy that prioritizes the inputs to valuation
techniques used to measure fair value.
Derivative contracts are traded in both exchange-based and non-exchange-based markets. Exchange-based derivatives that are valued using unadjusted
quoted prices in active markets are generally categorized in Level 1 in the fair value hierarchy.
Certain derivatives’ pricing is verified using indicative price quotations available through brokers or over-the-counter, on-line exchanges. The price quotations
reflect the average of the bid-ask mid-point from markets that the Registrants believe provide the most liquid market for the commodity. The price quotations
are reviewed and corroborated to ensure the prices are observable and representative of an orderly transaction between market participants. The
Registrant’s derivatives are traded predominately at liquid trading points. The remaining derivative contracts are valued using models that consider inputs
such as contract terms, including maturity, and market parameters, and assumptions of the future prices of energy, interest rates, volatility, credit worthiness,
and credit spread. For derivatives that trade in liquid markets, such as generic forwards, swaps, and options, the model inputs are generally observable.
Such instruments are categorized in Level 2.
For derivatives that trade in less liquid markets with limited pricing information, the model inputs generally would include both observable and unobservable
inputs and are categorized in Level 3.
The Registrants consider nonperformance risk, including credit risk in the valuation of derivative contracts, including both historical and current market data
in its assessment of nonperformance risk, including credit risk. The impacts of nonperformance and credit risk to date have generally not been material to the
financial statements.
See ITEM 7A. QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK and Note 18 — Fair Value of Financial Assets and Liabilities
and Note 16 — Derivative Financial Instruments of the Combined Notes to Consolidated Financial Statements for additional information regarding the
Registrants’ derivative instruments.
Taxation (All Registrants)
Significant management judgment is required in determining the Registrants’ provisions for income taxes, primarily due to the uncertainty related to tax
positions taken, as well as deferred tax assets and liabilities and valuation allowances. The Registrants account for uncertain income tax positions using a
benefit recognition model with a two-step approach including a more-likely-than-not recognition threshold and a measurement approach based on the largest
amount of tax benefit that is greater than 50% likely of being realized upon ultimate settlement. Management evaluates each position based solely on the
technical merits and facts and circumstances of the position, assuming the position will be examined by a taxing authority having full knowledge of all
relevant information. Significant judgment is required to determine whether the recognition threshold has been met and, if so, the appropriate amount of tax
benefits to be recorded in the Registrants’ consolidated financial statements.
The Registrants evaluate quarterly the probability of realizing deferred tax assets by reviewing a forecast of future taxable income and their intent and ability
to implement tax planning strategies, if necessary, to realize deferred tax assets. The Registrants also assess negative evidence, such as the expiration of
historical operating loss or tax credit carryforwards, that could indicate the Registrant's inability to realize its deferred tax assets. Based on the combined
assessment, the Registrants record valuation allowances for deferred tax assets when it is more-likely-than-not such benefit will not be realized in future
periods.
Actual income taxes could vary from estimated amounts due to the future impacts of various items, including future changes in income tax laws, the
Registrants’ forecasted financial condition and results of operations, failure to successfully implement tax planning strategies, as well as results of audits and
examinations of filed tax returns by taxing authorities. See Note 14 — Income Taxes of the Combined Notes to Consolidated Financial Statements for
additional information.
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Accounting for Loss Contingencies (All Registrants)
In the preparation of their financial statements, the Registrants make judgments regarding the future outcome of contingent events and record liabilities for
loss contingencies that are probable and can be reasonably estimated based upon available information. The amount recorded may differ from the actual
expense incurred when the uncertainty is resolved. Such difference could have a significant impact in the Registrants' consolidated financial statements.
Environmental Costs. Environmental investigation and remediation liabilities are based upon estimates with respect to the number of sites for which the
Registrants will be responsible, the scope and cost of work to be performed at each site, the portion of costs that will be shared with other parties, the timing
of the remediation work and changes in technology, regulations, and the requirements of local governmental authorities. Annual studies and/or reviews are
conducted at ComEd, PECO, BGE, and DPL to determine future remediation requirements for MGP sites and estimates are adjusted accordingly. In
addition, periodic reviews are performed at each of the Registrants to assess the adequacy of other environmental reserves. These matters, if resolved in a
manner different from the estimate, could have a significant impact in the Registrants’ consolidated financial statements. See Note 19 — Commitments and
Contingencies of the Combined Notes to Consolidated Financial Statements for additional information.
Other, Including Personal Injury Claims. The Registrants are self-insured for general liability, automotive liability, workers’ compensation, and personal
injury claims to the extent that losses are within policy deductibles or exceed the amount of insurance maintained. The Registrants have reserves for both
open claims asserted and an estimate of claims incurred but not reported (IBNR). The IBNR reserve is estimated based on actuarial assumptions and
analysis and is updated annually. Future events, such as the number of new claims to be filed each year, the average cost of disposing of claims, as well as
the numerous uncertainties surrounding litigation and possible state and national legislative measures could cause the actual costs to be higher or lower
than estimated. Accordingly, these claims, if resolved in a manner different from the estimate, could have a material impact in the Registrants’ consolidated
financial statements.
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Revenue Recognition (All Registrants)
Sources of Revenue and Determination of Accounting Treatment. The Registrants earn revenues from various business activities including: the sale of
power and energy-related products, such as natural gas, capacity, and other commodities in non-regulated markets (wholesale and retail); the sale and
delivery of power and natural gas in regulated markets; and the provision of other energy-related non-regulated products and services.
The accounting treatment for revenue recognition is based on the nature of the underlying transaction and applicable authoritative guidance. The Registrants
primarily apply the Revenue from Contracts with Customers, Derivative and ARP guidance to recognize revenue as discussed in more detail below.
Revenue from Contracts with Customers. The Registrants recognize revenues in the period in which the performance obligations within contracts with
customers are satisfied, which generally occurs when power, natural gas, and other energy-related commodities are physically delivered to the customer.
Transactions of the Registrants within the scope of Revenue from Contracts with Customers generally include non-derivative agreements, contracts that are
designated as NPNS, sales to utility customers under regulated service tariffs, and spot-market energy commodity sales, including settlements with ISOs.
The determination of Generation’s and the Utility Registrants' retail power and natural gas sales to individual customers is based on systematic readings of
customer meters, generally on a monthly basis. At the end of each month, amounts of energy delivered to customers since the date of the last meter reading
are estimated, and corresponding unbilled revenue is recorded. The measurement of unbilled revenue is affected by the following factors: daily customer
usage measured by generation or gas throughput volume, customer usage by class, losses of energy during delivery to customers and applicable customer
rates. Increases or decreases in volumes delivered to the utilities’ customers and favorable or unfavorable rate mix due to changes in usage patterns in
customer classes in the period could be significant to the calculation of unbilled revenue. In addition, revenues may fluctuate monthly as a result of
customers electing to use an alternate supplier, since unbilled commodity revenues are not recorded for these customers. Changes in the timing of meter
reading schedules and the number and type of customers scheduled for each meter reading date also impact the measurement of unbilled revenue;
however, total operating revenues would remain materially unchanged. See Note 1 — Significant Accounting Policies of the Combined Notes to
Consolidated Financial Statements for additional information.
Derivative Revenues. The Registrants record revenues and expenses using the mark-to-market method of accounting for transactions that are accounted
for as derivatives. These derivative transactions primarily relate to commodity price risk management activities. Mark-to-market revenues and expenses
include: inception gains or losses on new transactions where the fair value is observable, unrealized gains and losses from changes in the fair value of open
contracts, and realized gains and losses.
Alternative Revenue Program Accounting. Certain of the Utility Registrants’ ratemaking mechanisms qualify as ARPs if they (i) are established by a
regulatory order and allow for automatic adjustment to future rates, (ii) provide for additional revenues (above those amounts currently reflected in the price
of utility service) that are objectively determinable and probable of recovery, and (iii) allow for the collection of those additional revenues within 24 months
following the end of the period in which they were recognized. For mechanisms that meet these criteria, which include the Utility Registrants’ formula rate
mechanisms and revenue decoupling mechanisms, the Utility Registrants adjust revenue and record an offsetting regulatory asset or liability once the
condition or event allowing additional billing or refund has occurred. The ARP revenues presented in the Utility Registrants’ Consolidated Statements of
Operations and Comprehensive Income include both: (i) the recognition of “originating” ARP revenues (when the regulator-specified condition or event
allowing for additional billing or refund has occurred) and (ii) an equal and offsetting reversal of the “originating” ARP revenues as those amounts are
reflected in the price of utility service and recognized as Revenue from Contracts with Customers.
ComEd records ARP revenue for its best estimate of the electric distribution, energy efficiency, distributed generation rebates, and transmission revenue
impacts resulting from future changes in rates that ComEd believes are probable of approval by the ICC and FERC in accordance with its formula rate
mechanisms. BGE, Pepco, and DPL record ARP revenue for their best estimate of the electric and natural gas distribution revenue impacts resulting from
future changes in rates that they believe are probable of approval by the MDPSC and/or DCPSC in accordance with their revenue decoupling mechanisms.
PECO, BGE, Pepco, DPL, and ACE record ARP revenue for their best estimate of the transmission revenue impacts resulting from future changes in rates
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that they believe are probable of approval by FERC in accordance with their formula rate mechanisms. Estimates of the current year revenue requirement
are based on actual and/or forecasted costs and investments in rate base for the period and the rates of return on common equity and associated regulatory
capital structure allowed under the applicable tariff. The estimated reconciliation can be affected by, among other things, variances in costs incurred,
investments made, allowed ROE, and actions by regulators or courts.
See Note 3 — Regulatory Matters of the Combined Notes to Consolidated Financial Statements for additional information.
Allowance for Credit Losses on Customer Accounts Receivable (Utility Registrants)
Utility Registrants estimate the allowance for credit losses on customer receivables by applying loss rates developed specifically for each company based on
historical loss experience, current conditions, and forward-looking risk factors to the outstanding receivable balance by customer risk segment. Risk
segments represent a group of customers with similar forward-looking credit quality indicators and risk factors that are comprised based on various
attributes, including delinquency of their balances and payment history and represent expected, future customer behavior. Loss rates applied to the accounts
receivable balances are based on a historical average of charge-offs as a percentage of accounts receivable in each risk segment. The Utility Registrants'
customer accounts are generally considered delinquent if the amount billed is not received by the time the next bill is issued, which normally occurs on a
monthly basis. Utility Registrants' customer accounts are written off consistent with approved regulatory requirements. Utility Registrants' allowances for
credit losses will continue to be affected by changes in volume, prices, and economic conditions as well as changes in ICC, PAPUC, MDPSC, DCPSC,
DPSC, and NJBPU regulations.
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Generation
Results of Operations by Registrant
Results of Operations—Generation
Generation’s Results of Operations includes discussion of RNF, which is a financial measure not defined under GAAP and may not be comparable to other
companies' presentations or deemed more useful than the GAAP information provided elsewhere in this report. The CODMs for Exelon and Generation
evaluate the performance of Generation's electric business activities and allocate resources based on RNF. Generation believes that RNF is a useful
measure because it provides information that can be used to evaluate its operational performance.
Operating revenues
Purchased power and fuel expense
Revenues net of purchased power
and fuel expense
Other operating expenses
Operating and maintenance
Depreciation and amortization
Taxes other than income taxes
Total other operating expenses
Gain on sales of assets and businesses
Operating income
Other income and (deductions)
Interest expense
Other, net
Total other income and (deductions)
Income before income taxes
Income taxes
Equity in losses of unconsolidated affiliates
Net income
Net (loss) income attributable to noncontrolling interests
Net income attributable to membership interest
2020
2019
$
17,603 $
9,585
8,018
5,168
2,123
482
7,773
11
256
(357)
937
580
836
249
(8)
579
(10)
18,924 $
10,856
8,068
4,718
1,535
519
6,772
27
1,323
(429)
1,023
594
1,917
516
(184)
1,217
92
$
589 $
1,125 $
(Unfavorable)
Favorable Variance
(1,321)
1,271
(50)
(450)
(588)
37
(1,001)
(16)
(1,067)
72
(86)
(14)
(1,081)
267
176
(638)
(102)
(536)
Year Ended December 31, 2020 Compared to Year Ended December 31, 2019. Net income attributable to membership interest decreased by $536
million primarily due to:
•
•
•
•
One-time charges and accelerated depreciation and amortization associated with Generation's decisions in the third quarter of 2020 to early
retire Byron and Dresden nuclear facilities in 2021 and Mystic Units 8 and 9 in 2024, partially offset by the absence of accelerated depreciation
and amortization due to the early retirement of TMI in September 2019;
Impairment of the New England asset group;
Lower capacity revenue;
Reduction in load due to COVID-19;
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Generation
•
•
•
•
•
Lower realized energy prices;
Higher nuclear outage days;
Impact of Generation's annual update to the nuclear ARO for Non-regulatory Agreement Units;
Lower net unrealized and realized gains on NDT funds;
COVID-19 direct costs; and
The decreases were partially offset by:
•
•
•
•
•
•
Higher mark-to-market gains;
Unrealized gains resulting from equity investments without readily determinable fair values that became publicly traded entities in the fourth
quarter of 2020 and were fair valued based on quoted market prices of the stocks as of December 31, 2020;
Lower operating and maintenance expense primarily due to previous cost management programs, lower contracting costs, and lower travel
costs partially offset by lower NEIL insurance distributions;
Lower nuclear fuel costs;
Lower depreciation and amortization expense due to the impact of extending the operating license at Peach Bottom;
A tax benefit related to a settlement in the first quarter of 2020, partially offset by the absence of a tax benefit related to certain research and
development activities recorded in the fourth quarter of 2019.
Revenues Net of Purchased Power and Fuel Expense. The basis for Generation's reportable segments is the integrated management of its electricity
business that is located in different geographic regions, and largely representative of the footprints of ISO/RTO and/or NERC regions, which utilize multiple
supply sources to provide electricity through various distribution channels (wholesale and retail). Generation's hedging strategies and risk metrics are also
aligned with these same geographic regions. Generation's five reportable segments are Mid-Atlantic, Midwest, New York, ERCOT, and Other Power
Regions. See Note 5 — 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; 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.
For the years ended December 31, 2020 compared to 2019, RNF by region were as follows. See Note 5 - Segment Information of the Combined Notes to
the Consolidated Financial Statements for additional information on Purchase power and fuel expense for Generation’s reportable segments.
2020
2019
Variance
% Change
2020 vs. 2019
Mid-Atlantic
(a)
(b)
Midwest
New York
ERCOT
Other Power Regions
Total electric revenues net of purchased power and fuel expense
Mark-to-market gains (losses)
Other
$
2,204 $
2,902
2,655 $
2,962
997
426
665
7,194
295
529
1,094
308
620
7,639
(215)
644
Total revenue net of purchased power and fuel expense
$
8,018 $
8,068 $
(451)
(60)
(97)
118
45
(445)
510
(115)
(50)
(17.0)%
(2.0)%
(8.9)%
38.3 %
7.3 %
(5.8)%
237.2 %
(17.9)%
(0.6)%
__________
(a)
(b)
Includes results of transactions with PECO, BGE, Pepco, DPL, and ACE.
Includes results of transactions with ComEd.
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Generation
Generation’s supply sources by region are summarized below:
Supply Source (GWhs)
Nuclear Generation
Mid-Atlantic
(a)
Midwest
New York
Total Nuclear Generation
Fossil and Renewables
Mid-Atlantic
Midwest
New York
ERCOT
Other Power Regions
Total Fossil and Renewables
Purchased Power
Mid-Atlantic
Midwest
ERCOT
Other Power Regions
Total Purchased Power
Total Supply/Sales by Region
(c)
Mid-Atlantic
(b)
Midwest
(b)
New York
ERCOT
Other Power Regions
Total Supply/Sales by Region
2020
2019
Variance
% Change
2020 vs. 2019
52,202
96,322
26,561
58,347
94,890
28,088
175,085
181,325
2,206
1,240
4
11,982
11,121
26,553
22,487
770
5,636
51,079
79,972
76,895
98,332
26,565
17,618
62,200
2,884
1,374
5
13,572
11,476
29,311
14,790
1,424
4,821
48,673
69,708
76,021
97,688
28,093
18,393
60,149
281,610
280,344
(6,145)
1,432
(1,527)
(6,240)
(678)
(134)
(1)
(1,590)
(355)
(2,758)
7,697
(654)
815
2,406
10,264
874
644
(1,528)
(775)
2,051
1,266
(10.5)%
1.5 %
(5.4)%
(3.4)%
(23.5)%
(9.8)%
(20.0)%
(11.7)%
(3.1)%
(9.4)%
52.0 %
(45.9)%
16.9 %
4.9 %
14.7 %
1.1 %
0.7 %
(5.4)%
(4.2)%
3.4 %
0.5 %
__________
(a)
Includes the proportionate share of output where Generation has an undivided ownership interest in jointly-owned generating plants and includes the total output of plants
that are fully consolidated (e.g. CENG).
Includes affiliate sales to PECO, BGE, Pepco, DPL, and ACE in the Mid-Atlantic region and affiliate sales to ComEd in the Midwest region.
(b)
(c) Reflects a decrease in load due to COVID-19.
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For the years ended December 31, 2020 compared to 2019 changes in RNF by region were as follows:
Mid-Atlantic
(Decrease)/Increase
$
(451)
Midwest
New York
ERCOT
Other Power Regions
Mark-to-market
(a)
Other
Total
(60)
(97)
118
45
510
(115)
$
(50)
2020 vs. 2019
Description
• decreased revenue due to the permanent cease of generation operations at
TMI in the third quarter of 2019
• decreased capacity revenues
• lower realized energy prices, partially offset by
• increase in newly contracted load offset by impacts of COVID-19
• increased ZEC revenues due to the approval of the NJ ZEC program in the
second quarter of 2019
• decreased capacity revenues
• lower realized energy prices
• decreased load due to COVID-19 offset by an increase in total ISO sales,
partially offset by
• decreased nuclear outage days
• increased nuclear outage days
• decreased ZEC revenues due to increased outage days
• lower realized energy prices
• decreased load due to COVID-19 offset by newly contracted load, partially
offset by
• increased capacity revenues
• lower procurement costs for owned and contracted assets
• higher portfolio optimization, partially offset by
• lower realized energy prices
• higher portfolio optimization
• increase in newly contracted load offset by impacts of COVID-19, partially
offset by
• decreased capacity revenues
• lower realized energy prices
• gains on economic hedging activities of $295 million in 2020 compared to
losses of $215 million in 2019
increase
in accelerated nuclear
•
fuel amortization associated with
announced early plant retirements • decreased revenue related to the energy
efficiency business
__________
(a) See Note 16 — Derivative Financial Instruments of the Combined Notes to Consolidated Financial Statements for additional information on mark-to-market gains and
losses.
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Generation
Nuclear Fleet Capacity Factor. The following table presents nuclear fleet operating data for the Generation-operated plants, which reflects ownership
percentage of stations operated by Exelon, excluding Salem, which is operated by PSEG. The nuclear fleet capacity factor presented in the table is defined
as the ratio of the actual output of a plant over a period of time to its output if the plant had operated at full average annual mean capacity for that time
period. Generation considers capacity factor to be a useful measure to analyze the nuclear fleet performance between periods. Generation has included the
analysis below as a complement to the financial information provided in accordance with GAAP. However, these measures are not a presentation defined
under GAAP and may not be comparable to other companies’ presentations or be more useful than the GAAP information provided elsewhere in this report.
Nuclear fleet capacity factor
Refueling outage days
Non-refueling outage days
The changes in Operating and maintenance expense, consisted of the following:
Asset Impairments
ARO update
Nuclear refueling outage costs, including the co-owned Salem plants
Insurance
COVID-19 direct costs
Litigation settlements
Change in environmental liabilities
Credit loss expense
(a)
Accretion expense
Plant retirements and divestitures
Pension and non-pension postretirement benefits expense
Corporate allocations
Travel costs
Other
Labor, other benefits, contracting, and materials
Total increase
(b)
2020
2019
95.4 %
260
19
95.7 %
209
51
2020 vs. 2019
Increase (Decrease)
$
$
499
125
60
52
46
26
18
16
14
(8)
(19)
(35)
(38)
(71)
(235)
450
__________
(a)
(b) Primarily reflects decreased costs related to the permanent cease of generation operations at TMI, lower labor costs resulting from previous cost management programs,
Increased credit loss expense including impacts from COVID-19.
and decreased contracting costs.
Depreciation and amortization expense for the year ended December 31, 2020 compared to the same period in 2019 increased primarily due to the
accelerated depreciation and amortization associated with Generation's decision to early retire the Byron and Dresden nuclear facilities, partially offset by the
permanent cease of generation operations at TMI.
Taxes other than income taxes for the year ended December 31, 2020 compared to the same period in 2019 decreased primarily due to decreased sales
and power usage.
Gain on sales of assets and businesses for the year ended December 31, 2020 compared to the same period in 2019 decreased primarily due to
Generation's gain on sale of certain wind assets in 2019 partially offset by the loss on sale of Oyster Creek.
Other, net for the year ended December 31, 2020 compared to the same period in 2019 decreased due to activity associated with NDT funds as described
in the table below.
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Generation
Net unrealized gains on NDT funds
(a)
Net realized gains on sale of NDT funds
Interest and dividend income on NDT funds
(a)
(a)
Contractual elimination of income tax expense
Unrealized gains from equity investments
(c)
(b)
Other
Total other, net
$
$
2020
2019
391 $
70
90
180
186
20
411
253
110
216
—
33
937 $
1,023
__________
(a) Unrealized gains, realized gains, and interest and dividend income on the NDT funds are associated with the Non-Regulatory Agreement Units.
(b) Contractual elimination of income tax expense is associated with the income taxes on the NDT funds of the Regulatory Agreement Units.
(c) Unrealized gains resulting from equity investments without readily determinable fair values that became publicly traded entities in the fourth quarter of 2020 and were fair
valued based on quoted market prices of the stocks as of December 31, 2020.
Interest Expense for the year ended December 31, 2020 compared to the same period in 2019 decreased primarily due to the redemption of long-term debt
in 2020.
Effective income tax rates were 29.8% and 26.9% for the years ended December 31, 2020 and 2019, respectively. The change in 2020 is primarily related
to one-time income tax settlements partially offset by the absence of research and development refund claims. See Note 14 — Income Taxes of the
Combined Notes to Consolidated Financial Statements for additional information.
Equity in losses of unconsolidated affiliates for the year ended December 31, 2020 compared to the same period in 2019 increased primarily due to the
impairment of equity method investments in certain distributed energy companies in the third quarter of 2019.
Net income attributable to noncontrolling interests for the year ended December 31, 2020 compared to the same period in 2019 decreased primarily due
to lower unrealized losses on NDT fund investments for CENG.
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ComEd
Results of Operations—ComEd
Operating revenues
Operating expenses
Purchased power expense
Operating and maintenance
Depreciation and amortization
Taxes other than income taxes
Total operating expenses
Gain on sales of assets
Operating income
Other income and (deductions)
Interest expense, net
Other, net
Total other income and (deductions)
Income before income taxes
Income taxes
Net income
2020
2019
Favorable
(Unfavorable) Variance
$
5,904 $
5,747 $
1,998
1,520
1,133
299
4,950
—
954
(382)
43
(339)
615
177
1,941
1,305
1,033
301
4,580
4
1,171
(359)
39
(320)
851
163
$
438 $
688 $
157
(57)
(215)
(100)
2
(370)
(4)
(217)
(23)
4
(19)
(236)
(14)
(250)
Year Ended December 31, 2020 Compared to Year Ended December 31, 2019. Net income decreased by $250 million primarily due to payments that
ComEd made under the Deferred Prosecution Agreement, an impairment charge resulting from acquisition of transmission assets, and lower allowed electric
distribution ROE due to a decrease in treasury rates, partially offset by higher electric distribution formula rate earnings (reflecting the impacts of higher rate
base). See Note 19 — Commitments and Contingencies of the Combined Notes to Consolidated Financial Statements for additional information related to
the Deferred Prosecution Agreement.
The changes in Operating revenues consisted of the following:
Energy efficiency
Electric distribution
Transmission
Other
Regulatory required programs
Total increase
2020 vs. 2019
Increase
37
36
2
29
104
53
157
$
$
Revenue Decoupling. The demand for electricity is affected by weather and customer usage. Operating revenues are not impacted by abnormal weather,
usage per customer, or number of customers as a result of revenue decoupling mechanisms implemented pursuant to FEJA.
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ComEd
Energy Efficiency Revenue. FEJA provides for a performance-based formula rate, which requires an annual reconciliation of the revenue requirement in
effect to the actual costs that the ICC determines are prudently and reasonably incurred in a given year. Under FEJA, energy efficiency revenue varies from
year to year based upon fluctuations in the underlying costs, investments being recovered, and allowed ROE. Energy efficiency revenue increased for the
year ended December 31, 2020, as compared to the same period in 2019, primarily due to increased regulatory asset amortization which is fully recoverable.
See Depreciation and amortization expense discussions below and Note 3 — Regulatory Matters of the Combined Notes to Consolidated Financial
Statements for additional information.
Distribution Revenue. EIMA and FEJA provide for a performance-based formula rate, which requires an annual reconciliation of the revenue requirement in
effect to the actual costs that the ICC determines are prudently and reasonably incurred in a given year. Electric distribution revenue varies from year to year
based upon fluctuations in the underlying costs (e.g., severe weather and storm restoration), investments being recovered, and allowed ROE. During the
year ended December 31, 2020, as compared to the same period in 2019, electric distribution revenue increased due to the impact of higher rate base and
higher fully recoverable costs, offset by lower allowed ROE due to a decrease in treasury rates. See Note 3 — Regulatory Matters of the Combined Notes to
Consolidated Financial Statements for additional information.
Transmission Revenue. Under a FERC-approved formula, transmission revenue varies from year to year based upon fluctuations in the underlying costs,
capital investments being recovered, and the highest daily peak load, which is updated annually in January based on the prior calendar year. Generally,
increases/decreases in the highest daily peak load will result in higher/lower transmission revenue. During the year ended December 31, 2020, as compared
to the same period in 2019, transmission revenues remained relatively consistent. See Note 3 — Regulatory Matters of the Combined Notes to Consolidated
Financial Statements for additional information.
Other Revenue primarily includes assistance provided to other utilities through mutual assistance programs. The increase in Other revenue for the year
ended December 31, 2020, as compared to the same period in 2019, primarily reflects mutual assistance revenues associated with storm restoration efforts.
Regulatory Required Programs represents revenues collected under approved riders to recover costs incurred for regulatory programs such as recoveries
under the credit loss expense tariff, environmental costs associated with MGP sites, and costs related to electricity, ZEC, and REC procurement. The riders
are designed to provide full and current cost recovery. The costs of these programs are included in Purchased power expense, Operating and maintenance
expense, Depreciation and amortization expense, and Taxes other than income. Customers have the choice to purchase electricity from competitive electric
generation suppliers. Customer choice programs do not impact the volume of deliveries as ComEd remains the distribution service provider for all customers
and charges a regulated rate for distribution service, which is recorded in Operating revenues. For customers that choose to purchase electric generation
from competitive suppliers, ComEd acts as the billing agent and therefore does not record Operating revenues or Purchased power expense related to the
electricity. For customers that choose to purchase electric generation from ComEd, ComEd is permitted to recover the electricity, ZEC, and REC
procurement costs without mark-up and therefore records equal and offsetting amounts in Operating revenues and Purchased power expense related to the
electricity, ZECs, and RECs.
See Note 5 — Segment Information of the Combined Notes to Consolidated Financial Statements for the presentation of ComEd's revenue disaggregation.
The increase of $57 million for the year ended December 31, 2020, as compared to the same period in 2019, in Purchased power expense is offset in
Operating revenues as part of regulatory required programs.
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The changes in Operating and maintenance expense consisted of the following:
Deferred Prosecution Agreement payments
(a)
BSC costs
Labor, other benefits, contracting, and materials
Pension and non-pension postretirement benefits expense
Storm-related costs
Other
(c)
(b)
Regulatory required programs
(d)
Total increase
ComEd
2020 vs. 2019
Increase (Decrease)
200
20
7
5
(12)
(4)
216
(1)
215
$
$
__________
(a) See Note 19 — Commitments and Contingencies of the Combined Notes to Consolidated Financial Statements for additional information.
(b) For the year ended December 31, 2020, the decrease primarily reflects lower storm costs as a result of the August 2020 storm costs being reclassified to a regulatory
asset.
(c) For the year ended December 31, 2020, the decrease primarily reflects lower travel costs offset by an impairment charge related to acquisition of transmission assets.
(d) ComEd is allowed to recover from or refund to customers the difference between its annual credit loss expense and the amounts collected in rates annually through a rider
mechanism.
The changes in Depreciation and amortization expense consisted of the following:
Regulatory asset amortization
Depreciation and amortization expense
(a)
(b)
Total increase
2020 vs. 2019
Increase
$
$
64
36
100
__________
(a)
(b) Reflects ongoing capital expenditures.
Includes amortization of ComEd's energy efficiency formula rate regulatory asset and amortization related to the August 2020 storm regulatory asset.
Interest Expense, net increased $23 million for the year ended December 31, 2020, as compared to the same period in 2019, primarily due to the issuance
of debt in February 2020.
Effective income tax rates for the years ended December 31, 2020 and 2019, were 28.8% and 19.2%, respectively. See Note 14 — Income Taxes of the
Combined Notes to Consolidated Financial Statements for additional information regarding the components of the effective income tax rates.
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Results of Operations—PECO
Operating revenues
Operating expenses
Purchased power and fuel expense
Operating and maintenance
Depreciation and amortization
Taxes other than income taxes
Total operating expenses
Gain on sales of assets
Operating income
Other income and (deductions)
Interest expense, net
Other, net
Total other income and (deductions)
Income before income taxes
Income taxes
Net income
PECO
(Unfavorable)
Favorable Variance
(42)
11
(114)
(14)
(7)
(124)
(1)
(167)
(11)
2
(9)
(176)
95
(81)
2020
2019
$
3,058 $
3,100 $
1,018
975
347
172
2,512
—
546
(147)
18
(129)
417
(30)
1,029
861
333
165
2,388
1
713
(136)
16
(120)
593
65
$
447 $
528 $
Year Ended December 31, 2020 Compared to Year Ended December 31, 2019. Net income decreased by $81 million primarily due to unfavorable
weather conditions, higher storm costs due to the June and August 2020 storms net of tax repairs, increased depreciation and amortization expense, and
increased interest expense, partially offset by favorable volume and an increase in the tax repairs deduction.
The changes in Operating revenues consisted of the following:
Weather
Volume
Pricing
Transmission
Other
Regulatory required programs
Total increase (decrease)
2020 vs. 2019
(Decrease) Increase
Electric
Gas
Total
(29) $
(21) $
12
2
11
(7)
(11)
65
(3)
6
—
(1)
(19)
(77)
54 $
(96) $
(50)
9
8
11
(8)
(30)
(12)
(42)
$
$
Weather. The demand for electricity and natural gas is affected by weather conditions. With respect to the electric business, very warm weather in summer
months and, with respect to the electric and natural gas businesses, very cold weather in winter months are referred to as “favorable weather conditions”
because these weather conditions result in increased deliveries of electricity and natural gas. Conversely, mild weather reduces demand. For the year ended
December 31, 2020 compared to the same period in 2019, Operating revenues related to weather decreased due to the impact of unfavorable weather
conditions in PECO's service territory.
Heating and cooling degree days are quantitative indices that reflect the demand for energy needed to heat or cool a home or business. Normal weather is
determined based on historical average heating and cooling degree days for a 30-year period in PECO’s service territory. The changes in heating and
cooling degree days in PECO’s service territory for the years ended December 31, 2020 compared to the same period in 2019 and normal weather
consisted of the following:
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PECO
Heating and Cooling Degree-Days
2020
2019
Normal
2020 vs. 2019
2019 vs. Normal
Heating Degree-Days
Cooling Degree-Days
3,959
1,521
4,307
1,610
4,437
1,423
(8.1)%
(5.5)%
(10.8)%
6.9 %
For the Years Ended December 31,
% Change
Volume. Electric volume, exclusive of the effects of weather, for the year ended December 31, 2020 compared to the same period in 2019, increased due to
an increase in usage for residential customers during COVID-19 further increased by customer growth. Natural gas volume for the year ended December 31,
2020 compared to the same period in 2019, decreased on a net basis due to a decrease in usage for the commercial and industrial natural gas classes
during COVID-19.
Electric Retail Deliveries to Customers (in GWhs)
Retail Deliveries
Residential
Small commercial & industrial
(a)
Large commercial & industrial
Public authorities & electric railroads
Total electric retail deliveries
2020
2019
% Change 2020 vs.
2019
Weather - Normal %
Change
(b)
14,041
7,210
13,669
575
35,495
13,650
7,983
14,958
725
37,316
2.9 %
(9.7)%
(8.6)%
(20.7)%
(4.9)%
5.6 %
(8.2)%
(8.5)%
(20.7)%
(3.5)%
__________
(a) Reflects delivery volumes and revenue from customers purchasing electricity directly from PECO and customers purchasing electricity from a competitive electric
generation supplier as all customers are assessed distribution charges.
(b) Reflects the change in delivery volumes assuming normalized weather based on the historical 30-year average.
Number of Electric Customers
Residential
Small commercial & industrial
Large commercial & industrial
Public authorities & electric railroads
Total
Natural Gas Deliveries to customers (in mmcf)
Retail Deliveries
Residential
(a)
Small commercial & industrial
Large commercial & industrial
Transportation
Total natural gas deliveries
As of December 31,
2020
2019
1,508,622
154,421
3,101
10,206
1,676,350
1,494,462
154,000
3,104
10,039
1,661,605
2020
2019
% Change 2020 vs.
2019
Weather - Normal %
Change
(b)
38,272
19,341
36
24,533
82,182
40,196
23,828
50
25,822
89,896
(4.8)%
(18.8)%
(28.0)%
(5.0)%
(8.6)%
1.6 %
(6.6)%
(11.9)%
(2.9)%
(1.8)%
__________
(a) Reflects delivery volumes and revenue from customers purchasing electricity directly from PECO and customers purchasing electricity from a competitive electric
generation supplier as all customers are assessed distribution charges.
(b) Reflects the change in delivery volumes assuming normalized weather based on the historical 30-year average.
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Number of Gas Customers
Residential
Small commercial & industrial
Large commercial & industrial
Transportation
Total
PECO
487,337
44,374
2
730
532,443
As of December 31,
2020
2019
492,298
44,472
5
713
537,488
Pricing for the year ended December 31, 2020 compared to the same period in 2019 increased primarily due to higher overall effective rates due to
decreased 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. PECO's transmission formula rate filing was approved in the fourth quarter of 2019.
Other Revenue primarily includes revenue related to late payment charges. Other revenues for the year ended December 31, 2020 compared to the same
period in 2019, decreased as PECO ceased new late fees for all customers and restored service to customers upon request who were disconnected in the
last twelve months beginning March of 2020.
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 as 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 acts as the
billing agent and therefore does not record Operating revenues or Purchased power and fuel expense related to the electricity and/or natural gas. For
customers that choose to purchase electric generation or natural gas from PECO, PECO is permitted to recover the electricity, natural gas, and REC
procurement costs without 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.
See Note 5—Segment Information of the Combined Notes to Consolidated Financial Statements for the presentation of PECO's revenue disaggregation.
The decrease of $11 million for the year ended December 31, 2020 compared to the same period in 2019, respectively, in Purchased power and fuel
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:
Storm-related costs
(a)
Labor, other benefits, contracting, and materials
Credit loss expense
(b)
BSC costs
Pension and non-pension postretirement benefits expense
Other
Regulatory Required Programs
Total increase
PECO
2020 vs. 2019
Increase (Decrease)
82
23
12
1
(4)
7
121
(7)
114
$
$
__________
(a) Reflects increased storm costs due to June and August 2020 storms.
(b)
Increased credit loss expense primarily as a result of suspending customer disconnections, partially offset by the regulatory asset recorded in 2020 related to incremental
credit loss expense due to COVID-19. See Note 3 - Regulatory Matters of the Combined Notes to Consolidated Financial Statements for additional information.
The changes in Depreciation and amortization expense consisted of the following:
Depreciation and amortization
(a)
Regulatory asset amortization
Total increase
2020 vs. 2019
Increase (Decrease)
$
$
16
(2)
14
__________
(a) Depreciation and amortization expense increased primarily due to ongoing capital expenditures.
Interest expense, net increased $11 million for the year ended December 31, 2020 compared to the same period in 2019, respectively, primarily due to the
issuance of debt in June 2020.
Effective income tax rates were (7.2)% and 11.0% for the years ended December 31, 2020 and 2019, respectively. See Note 14 — Income Taxes of the
Combined Notes to Consolidated Financial Statements for additional information of the change in effective income tax rates.
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Results of Operations—BGE
Operating revenues
Operating expenses
Purchased power and fuel expense
Operating and maintenance
Depreciation and amortization
Taxes other than income taxes
Total operating expenses
Operating income
Other income and (deductions)
Interest expense, net
Other, net
Total other income and (deductions)
Income before income taxes
Income taxes
Net income
BGE
(Unfavorable)
Favorable Variance
(8)
61
(29)
(48)
(8)
(24)
(32)
(12)
(5)
(17)
(49)
38
(11)
2020
2019
$
3,098 $
3,106 $
991
789
550
268
2,598
500
(133)
23
(110)
390
41
1,052
760
502
260
2,574
532
(121)
28
(93)
439
79
$
349 $
360 $
Year Ended December 31, 2020 Compared to Year Ended December 31, 2019. Net income remained relatively consistent primarily due to higher natural
gas and electric distribution rates, partially offset by increased depreciation and amortization expense, increased interest expense, increased expense due to
a commitment to a multi-year small business grants program, and a decrease in other revenues.
The changes in Operating revenues consisted of the following:
Distribution
Transmission
Other
Regulatory required programs
Total (decrease) increase
2020 vs. 2019
Increase (Decrease)
Electric
Gas
Total
30 $
54 $
(3)
(14)
13
(55)
—
(9)
45
(11)
(42) $
34 $
84
(3)
(23)
58
(66)
(8)
$
$
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BGE
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.
Number of Electric Customers
Residential
Small commercial & industrial
Large commercial & industrial
Public authorities & electric railroads
Total
Number of Gas Customers
Residential
Small commercial & industrial
Large commercial & industrial
Total
As of December 31,
2020
2019
1,190,678
114,173
12,478
267
1,317,596
As of December 31,
2020
2019
647,188
38,267
6,101
691,556
1,177,333
114,504
12,322
268
1,304,427
639,426
38,345
6,037
683,808
Distribution Revenue increased for the year ended December 31, 2020 compared to the same period in 2019, primarily due to the impact of higher natural
gas and electric distribution rates that became effective in December 2019.
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 year ended
December 31, 2020 compared to the same period in 2019, primarily due to the settlement agreement of transmission-related income tax regulatory liabilities,
partially offset by higher fully recoverable costs. See Note 3 — Regulatory Matters of the Combined Notes to Consolidated Financial Statements for
additional information.
Other Revenue includes revenue related to late payment charges, mutual assistance, off-system sales, and service application fees. Other revenue
decreased for the year ended December 31, 2020 compared to the same period in 2019, as BGE temporarily suspended customer disconnections for non-
payment beginning March of 2020 and temporarily ceased new late fees for all customers and restored service 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
conservation, demand response, STRIDE, and the POLR 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 as 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 acts as the billing agent and therefore does not record Operating revenues or Purchased power
and fuel expense related to the electricity and/or natural gas. For customers that choose to purchase electric generation or natural gas from BGE, BGE is
permitted to recover the electricity and natural gas procurement costs from customers and therefore records the amounts related to the electricity and/or
natural gas in Operating revenues and Purchased power and fuel expense. BGE recovers electricity and natural gas procurement costs from customers with
a slight mark-up.
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BGE
See Note 5 — Segment Information of the Combined Notes to Consolidated Financial Statements for the presentation of BGE's revenue disaggregation.
The decrease of $61 million for the year ended December 31, 2020 compared to the same period in 2019, 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:
Small business grants commitment
BSC costs
(a)
Credit loss expense
Labor, other benefits, contracting, and materials
(b)
Pension and non-pension postretirement benefits expense
Regulatory required programs
Total increase
2020 vs. 2019
Increase (Decrease)
15
13
7
(1)
(2)
32
(3)
29
$
$
__________
(a) Reflects increased charitable contributions as a result of a commitment in 2020 to a multi-year small business grants program.
(b)
Increased credit loss expense primarily as a result of suspending customer disconnections, partially offset by the regulatory asset recorded in 2020 related to incremental
credit loss expense due to COVID-19. See Note 3 - Regulatory Matters of the Combined Notes to Consolidated Financial Statements for additional information.
The changes in Depreciation and amortization expense consisted of the following:
Depreciation and amortization
(a)
Regulatory required programs
Regulatory asset amortization
Total increase
2020 vs. 2019
Increase
35
10
3
48
$
$
__________
(a) Depreciation and amortization increased primarily due to ongoing capital expenditures.
Taxes other than income increased for the year ended December 31, 2020 compared to the same period in 2019, primarily due to higher property taxes.
Interest expense, net increased for the year ended December 31, 2020 compared to the same period in 2019, primarily due to the issuance of debt in
September 2019 and June 2020.
Effective income tax rates were 10.5% and 18.0% for the years ended December 31, 2020 and 2019, respectively. The change is primarily related to the
settlement agreement of transmission-related income tax regulatory liabilities. See Note 3 — Regulatory Matters and Note 14 — Income Taxes of the
Combined Notes to Consolidated Financial Statements for additional information regarding the components of the effective income tax rates.
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Results of Operations—PHI
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 year ended December 31, 2020
compared to the same period in 2019. See the Results of Operations for Pepco, DPL, and ACE for additional information.
PHI
Pepco
DPL
ACE
Other
(a)
$
2020
2019
Favorable
(Unfavorable) Variance
495 $
266
125
112
(8)
477 $
243
147
99
(12)
18
23
(22)
13
4
__________
(a) Primarily includes eliminating and consolidating adjustments, PHI's corporate operations, shared service entities, and other financing and investing activities.
Year Ended December 31, 2020 Compared to Year Ended December 31, 2019. Net income increased by $18 million primarily due to higher electric
distribution rates, higher transmission rates (net of the impact of the settlement agreement of ongoing transmission-related income tax regulatory liabilities),
and decreased expense resulting from an absence of an increase in environmental liabilities, and a gain on sale of land at Pepco in the fourth quarter of
2020, partially offset by an increase in depreciation and amortization expense, an increase in DPL storm costs related to the August 2020 storms in
Delaware, an increase in credit loss expense primarily as a result of suspending customer disconnections partially offset by the regulatory asset recorded in
2020 related to incremental credit loss expense due to COVID-19, and unfavorable weather conditions in ACE and DPL Delaware's service territories.
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Pepco
Results of Operations—Pepco
Operating revenues
Operating expenses
Purchased power expense
Operating and maintenance
Depreciation and amortization
Taxes other than income taxes
Total operating expenses
Gain on sales of assets
Operating income
Other income and (deductions)
Interest expense, net
Other, net
Total other income and (deductions)
Income before income taxes
Income taxes
Net income
2020
2019
(Unfavorable)
Favorable Variance
$
2,149 $
2,260 $
(111)
602
453
377
367
1,799
9
359
(138)
38
(100)
259
(7)
665
482
374
378
1,899
—
361
(133)
31
(102)
259
16
$
266 $
243 $
63
29
(3)
11
100
9
(2)
(5)
7
2
—
23
23
Year Ended December 31, 2020 Compared to Year Ended December 31, 2019. Net income increased by $23 million primarily due to decreased expense
resulting from an absence of an increase in environmental liabilities, increased electric distribution revenues, and a gain on sale of land in the fourth quarter
of 2020, partially offset by an increase in depreciation and amortization expense and an increase in credit loss expense primarily as a result of suspending
customer disconnections partially offset by the regulatory asset recorded in 2020 related to incremental credit loss expense due to COVID-19.
The changes in Operating revenues consisted of the following:
Distribution
Transmission
Other
Regulatory required programs
Total decrease
2020 vs. 2019
Increase (Decrease)
19
(36)
(3)
(20)
(91)
(111)
$
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.
Number of Electric Customers
Residential
Small commercial & industrial
Large commercial & industrial
Public authorities & electric railroads
Total
As of December 31,
2020
2019
832,190
53,800
22,459
168
908,617
817,770
54,265
22,271
160
894,466
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Pepco
Distribution Revenue increased for the year ended December 31, 2020 compared to the same period in 2019, primarily due to higher electric distribution
rates in Maryland that became effective in August 2019 and customer growth in the District of Columbia.
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 year ended
December 31, 2020 compared to the same period in 2019 primary due to the settlement agreement of transmission-related income tax regulatory liabilities.
See Note 3 — 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 year ended December 31, 2020 compared to the same period in 2019, as Pepco temporarily suspended customer disconnections
for non-payment beginning March of 2020 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, as 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 acts as the billing agent and therefore does not record Operating revenues or Purchased power expense related to the
electricity. For customers that choose to purchase electric generation from Pepco, Pepco is permitted to recover the electricity and REC procurement costs
from customers and therefore records the amounts related to the electricity and RECs in Operating revenues and Purchased power expense. Pepco
recovers electricity and REC procurement costs from customers with a slight mark-up.
See Note 5 - Segment Information of the Combined Notes to Consolidated Financial Statements for the presentation of Pepco's revenue disaggregation.
The decrease of $63 million for the year ended December 31, 2020 compared to the same period in 2019, 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:
Change in environmental liabilities
Expiration of lease arrangement
Pension and non-pension postretirement benefits expense
BSC and PHISCO costs
Storm related costs
Credit loss expense
Labor, other benefits, contracting, and materials
(a)
Other
Regulatory required programs
Total decrease
Pepco
2020 vs. 2019
(Decrease) Increase
(22)
(15)
(6)
(4)
(2)
8
15
(1)
(27)
(2)
(29)
$
$
__________
(a)
Increased credit loss expense primarily as a result of suspending customer disconnections, partially offset by the regulatory asset recorded in 2020 related to incremental
credit loss expense due to COVID-19. See Note 3 — Regulatory Matters of the Combined Notes to Consolidated Financial Statements for additional information.
The changes in Depreciation and amortization expense consisted of the following:
Depreciation expense
(a)
Regulatory asset amortization
Regulatory required programs
Total increase
2020 vs. 2019
Increase (Decrease)
$
$
18
(2)
(13)
3
__________
(a) Depreciation and amortization increased primarily due to ongoing capital expenditures.
Taxes other than income decreased for the year ended December 31, 2020 compared to the same period in 2019, primarily due to lower taxes as part of
regulatory required programs that are fully offset within Operating revenues.
Interest expense, net increased for the year ended December 31, 2020 compared to the same period in 2019, primarily due to issuance of debt in June
2019, February 2020, and June 2020.
Gain on sales of assets for the year ended December 31, 2020 compared to the year ended December 31, 2019 increased due the sale of land in the
fourth quarter of 2020.
Effective income tax rates were (2.7)% and 6.2% for the years ended December 31, 2020 and 2019, respectively. The change is primarily related to the
settlement agreement of ongoing transmission-related income tax regulatory liabilities. See Note 3 — Regulatory Matters and Note 14 — 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
Operating revenues
Operating expenses
Purchased power and fuel expense
Operating and maintenance
Depreciation and amortization
Taxes other than income taxes
Total operating expenses
Operating income
Other income and (deductions)
Interest expense, net
Other, net
Total other income and (deductions)
Income before income taxes
Income taxes
Net income
DPL
(Unfavorable)
Favorable Variance
(35)
23
(38)
(7)
(9)
(31)
(66)
—
(3)
(3)
(69)
47
(22)
2020
2019
$
1,271 $
1,306 $
503
361
191
65
1,120
151
(61)
10
(51)
100
(25)
526
323
184
56
1,089
217
(61)
13
(48)
169
22
$
125 $
147 $
Year Ended December 31, 2020 Compared to Year Ended December 31, 2019. Net income decreased by $22 million primarily due to an increase in
storm costs related to the August 2020 storms in Delaware, an increase in credit loss expense primarily as a result of suspending customer disconnections
partially offset by the regulatory asset recorded in 2020 related to incremental credit loss expense due to COVID-19, unfavorable weather conditions in
DPL's Delaware electric service territory, and an increase in depreciation and amortization expense, partially offset by higher electric distribution rates and an
increase in transmission rates (net of the impact of the settlement agreement of transmission-related income tax regulatory liabilities).
The changes in Operating revenues consisted of the following:
Weather
Volume
Distribution
Transmission
Other
Regulatory required programs
Total decrease
2020 vs. 2019
(Decrease) Increase
Electric
Gas
Total
(9) $
— $
2
12
(18)
2
(11)
(17)
(5)
4
—
(1)
(2)
(5)
(28) $
(7) $
(9)
(3)
16
(18)
1
(13)
(22)
(35)
$
$
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 in Maryland are not impacted by abnormal weather
or usage per customer, they are impacted by changes in the number of customers.
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 demand. During
the year ended December 31, 2020 compared to the same period in 2019, Operating revenues related to weather decreased primarily due to unfavorable
weather conditions in DPL's Delaware service territory.
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DPL
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 year
ended December 31, 2020 compared to same period in 2019 and normal weather consisted of the following:
Delaware Electric Service Territory
2020
2019
Normal
2020 vs. 2019
2020 vs. Normal
Heating Degree-Days
Cooling Degree-Days
4,146
1,264
4,475
1,476
4,652
1,239
(7.4)%
(14.4)%
(10.9)%
2.0 %
For the Years Ended December 31,
% Change
Delaware Natural Gas Service Territory
2020
2019
Normal
2020 vs. 2019
2020 vs. Normal
Heating Degree-Days
4,146
4,475
4,675
(7.4)%
(11.3)%
For the Years Ended December 31,
% Change
Volume, exclusive of the effects of weather, remained relatively consistent for the year ended December 31, 2020 compared to the same period in 2019.
Electric Retail Deliveries to Delaware Customers (in GWhs)
2020
2019
% Change
2020 vs. 2019
Weather - Normal
(b)
% Change
Residential
Small commercial & industrial
Large commercial & industrial
Public authorities & electric railroads
Total electric retail deliveries
(a)
Number of Total Electric Customers (Maryland and Delaware)
Residential
Small commercial & industrial
Large commercial & industrial
Public authorities & electric railroads
Total
3,149
1,255
3,225
32
7,661
3,149
1,320
3,424
34
7,927
— %
(4.9)%
(5.8)%
(5.9)%
(3.4)%
4.8 %
(2.6)%
(4.8)%
(5.9)%
(0.7)%
As of December 31,
2020
2019
472,621
62,461
1,223
609
536,914
468,162
61,721
1,411
613
531,907
__________
(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)
Residential
Small commercial & industrial
Large commercial & industrial
Transportation
Total natural gas deliveries
(a)
2020
2019
% Change
2020 vs. 2019
7,832
3,718
1,703
6,631
8,613
4,287
1,811
6,733
19,884
21,444
(9.1)%
(13.3)%
(6.0)%
(1.5)%
(7.3)%
103
Weather - Normal
(b)
% Change
(2.5)%
(7.5)%
(6.0)%
0.2 %
(3.0)%
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Number of Delaware Natural Gas Customers
Residential
Small commercial & industrial
Large commercial & industrial
Transportation
Total
DPL
As of December 31,
2020
2019
127,128
10,017
16
161
137,322
125,873
9,999
17
159
136,048
__________
(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 year ended December 31, 2020 compared to the same period in 2019 primarily due to higher electric distribution
rates in Maryland that became effective in July 2020, higher electric and natural gas distribution rates in Delaware that became effective in the second half of
2020, and the Distribution System Improvement Charge (DSIC) rate increases during 2020.
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 years. Generally,
increases/decreases in the highest daily peak load will result in higher/lower transmission revenue. Transmission revenue decreased for the year ended
December 31, 2020 compared to the same period in 2019 primarily due to the settlement agreement of transmission-related income tax regulatory liabilities,
partially offset by higher fully recoverable costs. See Note 3 — 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.
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 as 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 or natural gas from competitive suppliers, DPL acts as the billing agent and therefore does not record Operating revenues or
Purchased power and fuel expense related to the electricity and/or natural gas. For customers that choose to purchase electric generation or natural gas
from DPL, DPL is permitted to recover the electricity, natural gas, and REC procurement costs from customers and therefore records the amounts related to
the electricity, natural gas, and RECs in Operating revenues and Purchased power and fuel expense. DPL recovers electricity and REC procurement costs
from customers with a slight mark-up and natural gas costs without mark-up.
See Note 5 - Segment Information of the Combined Notes to Consolidated Financial Statements for the presentation of DPL's revenue disaggregation.
The decrease of $23 million for the year ended December 31, 2020 compared to the same period in 2019, in Purchased power and fuel 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:
Storm-related costs
Labor, other benefits, contracting, and materials
Credit loss expense
(a)
Pension and non-pension postretirement benefits expense
BSC and PHISCO costs
Other
Regulatory required programs
Total increase
DPL
19
14
8
(4)
(1)
(1)
35
3
38
2020 vs. 2019
Increase
(Decrease)
$
$
__________
(a)
Increased credit loss expense primarily as a result of suspending customer disconnections, partially offset by the regulatory asset recorded in 2020 related to incremental
credit loss expense due to COVID-19. See Note 3 - Regulatory Matters of the Combined Notes to Consolidated Financial Statements for additional information.
The changes in Depreciation and amortization expense consisted of the following:
Depreciation and amortization
(a)
Regulatory asset amortization
Regulatory required programs
Total increase
2020 vs. 2019
Increase
(Decrease)
10
(1)
(2)
7
$
$
__________
(a) Depreciation and amortization increased primarily due to ongoing capital expenditures.
Taxes other than income taxes increased for the year ended December 31, 2020 compared to the same period in 2019 primarily due to higher property
taxes for Maryland and Delaware.
Effective income tax rates were (25.0)% and 13.0% for the years ended December 31, 2020 and 2019, respectively. The decrease for the year ended
December 31, 2020 is primarily related to the settlement agreement of transmission-related income tax regulatory liabilities. See Note 3 — Regulatory
Matters and Note 14 — 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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ACE
Results of Operations—ACE
Operating revenues
Operating expenses
Purchased power expense
Operating and maintenance
Depreciation and amortization
Taxes other than income taxes
Total operating expenses
Gain on sale of assets
Operating income
Other income and (deductions)
Interest expense, net
Other, net
Total other income and (deductions)
Income before income taxes
Income taxes
Net income
2020
2019
Favorable
(Unfavorable) Variance
$
1,245 $
1,240 $
609
326
180
8
1,123
2
124
(59)
6
(53)
71
(41)
608
320
157
4
1,089
—
151
(58)
6
(52)
99
—
$
112 $
99 $
5
(1)
(6)
(23)
(4)
(34)
2
(27)
(1)
—
(1)
(28)
41
13
Year Ended December 31, 2020 Compared to Year Ended December 31, 2019. Net income increased $13 million primarily due to higher electric
distribution rates and an increase in transmission rates (net of the impact of the settlement agreement of transmission-related income tax regulatory
liabilities), partially offset by an increase in depreciation and amortization expense and unfavorable weather conditions in ACE's service territory.
The changes in Operating revenues consisted of the following:
Weather
Volume
Distribution
Transmission
Other
Regulatory required programs
Total increase
2020 vs. 2019
(Decrease) Increase
(8)
(1)
24
(19)
3
(1)
6
5
$
$
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 decrease related to weather for the year ended December 31, 2020 compared to the same period
in 2019 due to the impact of unfavorable weather conditions in ACE's service territory.
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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 year ended December 31, 2020 compared to same period in 2019, and normal weather consisted of the
following:
Heating and Cooling Degree-Days
2020
2019
Normal
2020 vs. 2019
2020 vs. Normal
Heating Degree-Days
Cooling Degree-Days
4,029
1,314
4,467
1,374
4,667
1,174
(9.8)%
(4.4)%
(13.7)%
11.9 %
For the Years Ended December 31,
% Change
Volume, exclusive of the effects of weather, remained relatively consistent for the year ended December 31, 2020 compared to the same period in 2019.
Electric Retail Deliveries to Customers (in GWhs)
Residential
Small commercial & industrial
Large commercial & industrial
Public authorities & electric railroads
Total retail deliveries
(a)
Number of Electric Customers
Residential
Small commercial & industrial
Large commercial & industrial
Public authorities & electric railroads
2020
2019
% Change 2020 vs.
2019
Weather - Normal %
Change
(b)
4,029
1,277
3,067
47
8,420
3,966
1,346
3,429
47
8,788
1.6 %
(5.1)%
(10.6)%
— %
(4.2)%
4.7 %
(4.0)%
(10.0)%
(0.2)%
(2.5)%
As of December 31,
2020
2019
497,672
61,622
3,282
701
494,596
61,497
3,392
679
Total
__________
(a) Reflects delivery volumes from customers purchasing electricity directly from ACE and customers purchasing electricity from a competitive electric generation supplier as
563,277
560,164
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 year ended December 31, 2020 compared to the same period in 2019 primarily due to higher electric distribution
rates that became effective in April 2019 and April 2020.
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 year ended
December 31, 2020 compared to the same period in 2019 primarily due to the settlement agreement for transmission-related income tax regulatory liabilities,
partially offset by higher fully recoverable costs. See Note 3 — Regulatory Matters of the Combined Notes to Consolidated Financial Statements for
additional information.
Other Revenue includes rental revenue, service connection fees, and mutual assistance revenues.
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 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.
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ACE
Customer choice programs do not impact the volume of deliveries, as 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 acts as the billing agent and therefore does not record Operating revenues or Purchased power expense related to the electricity. For
customers that choose to purchase electric generation from 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 the electricity, ZECs, and
RECs.
See Note 5 - Segment Information of the Combined Notes to Consolidated Financial Statements for the presentation of ACE's revenue disaggregation.
The increase of $1 million for the year ended December 31, 2020 compared to same period in 2019, 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:
Labor, other benefits, contracting and materials
Storm-related costs
Pension and non-pension postretirement benefits expense
Other
Regulatory required programs
Total increase
(a)
2020 vs. 2019
Increase (Decrease)
6
3
(1)
(2)
6
—
6
$
$
__________
(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:
Depreciation and amortization
(a)
Regulatory asset amortization
Regulatory required programs
Total increase
2020 vs. 2019
Increase (Decrease)
$
$
17
(2)
8
23
__________
(a) Depreciation and amortization increased primarily due to ongoing capital expenditures.
Gain on sale of assets for year ended December 31, 2020 compared to same period in 2019 increased due to the sale of land in the first quarter of 2020.
Effective income tax rates were (57.7)% and 0.0% for the years ended December 31, 2020 and 2019, respectively. The change is primarily related to the
settlement agreement of transmission-related income tax regulatory liabilities. See Note 3 — Regulatory Matters and Note 14 — Income Taxes of the
Combined Notes to Consolidated Financial Statements for additional information regarding the components of the change in effective income tax rates.
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,
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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 $10.6 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 6 — Accounts Receivable of the Combined Notes to Consolidated Financial Statements for additional
information on the sale of customer accounts receivable. 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 OPEB 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 17 — Debt and Credit Agreements of the Combined Notes to Consolidated Financial Statements for additional information of the Registrants’
debt and credit agreements.
Despite disruptions in the financial markets due to COVID-19, the Registrants issued long-term debt of $5.3 billion and were able to successfully complete
their planned long-term debt issuances in 2020.
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 10 - Asset Retirement Obligations 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 funds could appreciate in value. A shortfall could require that Generation address
the shortfall by, among other things, obtaining a parental guarantee 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. Within 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 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, the NRC may require additional financial assurance including possibly a parental guarantee from Exelon. Considering the
different approaches to decommissioning available to Generation, the most likely estimates currently anticipated could require financial assurance for
radiological decommissioning at Byron of up to $90 million.
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Upon issuance of any required financial guarantees, 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
Generation to utilize the NDT funds to pay for non-radiological decommissioning costs (i.e. spent fuel management and site restoration costs, if applicable).
If a unit does not receive this exemption, those costs would be borne by Generation without reimbursement from or access to the NDT funds. Accordingly,
based on current projections of the most likely decommissioning approach, 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 and could be offset by reimbursement of certain spent fuel management costs under the DOE settlement agreement,
decommissioning for Byron may require supplemental cash from Generation of up to $185 million, net of taxes, over a period of 10 years after permanent
shutdown.
As of December 31, 2020, Exelon would not be required to post a parental guarantee 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 funds to be spent on site restoration costs, which are not expected to be incurred in the near term.
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. See Note 17 — Debt and Credit
Agreements of the Combined Notes to Consolidated Financial Statements for additional information on nonrecourse debt and credit facilities.
Cash Flows from Operating Activities (All Registrants)
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.
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 19 — Commitments and Contingencies of the Combined Notes to Consolidated Financial Statements for
additional information of regulatory and legal proceedings and proposed legislation.
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The following table provides a summary of the change in cash flows from operating activities for the years ended December 31, 2020 and 2019 by
Registrant:
(Decrease) increase in cash flows from operating
activities
Net income
Adjustments to reconcile net income to cash:
Non-cash operating activities
Pension and non-pension postretirement benefit
contributions
Income taxes
Changes in working capital and other noncurrent assets
and liabilities
Option premiums paid, net
Collateral received (posted), net
Exelon
Generation
ComEd
PECO
BGE
PHI
Pepco
DPL
ACE
$
(1,074)
$
(638)
$
(250)
$
(81)
$
(11)
$
18
$
23
$
(22)
$
13
273
(193)
204
(2,456)
(110)
932
328
(80)
(116)
(2,633)
(110)
960
156
(71)
(87)
(93)
—
(34)
(42)
10
65
74
—
—
26
(33)
(30)
127
79
—
4
(120)
(123)
(14)
(41)
42
—
—
3
(10)
96
—
—
25
1
(37)
11
—
—
$
136
$
(115)
$
(11)
$
(22)
$
(3)
(1)
(3)
(68)
—
—
(62)
(Decrease) increase in cash flows from operating activities
$
(2,424)
$
(2,289)
$
(379)
$
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 2020 and 2019 were as follows:
•
•
•
•
See Note 24 —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 14 —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 6 — Accounts Receivable for
additional information on the sales of customer accounts receivable.
Pension and Other Postretirement Benefits
Management considers various factors when making pension funding decisions, including actuarially determined minimum contribution requirements under
ERISA, contributions required to avoid benefit restrictions and at-risk status as defined by the Pension Protection Act of 2006 (the Act), management of the
pension obligation, and regulatory implications. The Act requires the attainment of certain funding levels to avoid benefit restrictions (such as an inability to
pay lump sums or to accrue benefits prospectively), and at-risk status (which triggers higher minimum contribution requirements and participant notification).
The projected contributions below reflect a funding strategy to make levelized annual contributions with the objective of achieving 100% funded status on an
ABO basis over time. This level funding strategy helps minimize volatility of future period required pension contributions. Based on this funding strategy and
current market conditions, which are subject to change, Exelon’s estimated annual qualified pension contributions will be approximately $500 million in 2021.
Unlike the qualified pension plans, Exelon’s non-qualified pension plans are not funded, given that they are not subject to statutory minimum contribution
requirements.
While OPEB plans are also not subject to statutory minimum contribution requirements, Exelon does fund certain of its plans. For Exelon's funded OPEB
plans, contributions generally equal accounting costs, however, Exelon’s management has historically considered several factors in determining the level of
contributions to its OPEB plans, including liabilities management, levels of benefit claims paid, and regulatory implications (amounts deemed prudent to meet
regulatory expectations and best assure continued rate recovery). The amounts below include benefit payments related to unfunded plans.
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The following table provides all Registrants' planned contributions to the qualified pension plans, planned benefit payments to non-qualified pension plans,
and planned contributions to OPEB plans in 2021:
Exelon
Generation
ComEd
PECO
BGE
PHI
Pepco
DPL
ACE
Qualified Pension Plans
Non-Qualified Pension Plans
OPEB
$
505 $
196
170
14
57
29
1
—
3
51 $
27
2
1
1
9
2
1
—
75
24
23
—
16
7
6
—
—
To the extent interest rates decline significantly or the pension and OPEB plans earn less than the expected asset returns, annual pension contribution
requirements in future years could increase. Conversely, to the extent interest rates increase significantly or the pension and OPEB plans earn greater than
the expected asset returns, annual pension and OPEB contribution requirements in future years could decrease. Additionally, expected contributions could
change if Exelon changes its pension or OPEB funding strategy.
Cash Flows from Investing Activities (All Registrants)
The following table provides a summary of the change in cash flows from investing activities for the years ended December 31, 2020 and 2019 by
Registrant:
Increase (decrease) in cash flows from investing
activities
Capital expenditures
$
Proceeds from NDT fund sales, net
Acquisitions of assets and businesses, net
Proceeds from sales of assets and businesses
Changes in intercompany money pool
Collection of DPP
Other investing activities
Exelon
Generation
ComEd
PECO
BGE
PHI
Pepco
DPL
ACE
$
(800)
(87)
41
(7)
—
3,771
6
$
98
(87)
41
(6)
—
3,771
8
(302)
—
—
—
—
—
(27)
(329)
$
$
(208)
—
—
—
136
—
8
$
(64)
$
(102)
—
—
—
—
—
(6)
(108)
$
$
(249)
—
—
—
—
—
10
(239)
$
$
(147)
—
—
—
—
—
(3)
(150)
$
$
(76)
—
—
—
—
—
(4)
(80)
$
$
(26)
—
—
—
—
—
7
(19)
Increase (decrease) in cash flows from investing activities
$
2,924
$
3,825
$
Significant investing cash flow impacts for the Registrants for 2020 and 2019 were as follows:
•
•
Variances in capital expenditures are primarily due to the timing of cash expenditures for capital projects. Refer below for additional information
on projected capital expenditure spending.
Changes in intercompany money pool are driven by short-term borrowing needs. Refer to more information regarding the intercompany money
pool below.
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Capital Expenditure Spending
The Registrants most recent estimates of capital expenditures for plant additions and improvements for 2021 are approximately as follows:
(in millions)
Exelon
Generation
ComEd
PECO
BGE
PHI
Pepco
DPL
ACE
Transmission
Distribution
Gas
Total
N/A
N/A
475
175
325
525
250
125
150
N/A
N/A
1,925
750
450
1,100
675
225
200
N/A $
N/A
N/A
350
425
75
N/A
75
N/A
7,775
1,150
2,400
1,275
1,200
1,700
925
425
350
Projected capital expenditures and other investments are subject to periodic review and revision to reflect changes in economic conditions and other factors.
Generation
Approximately 48% of projected 2021 capital expenditures at Generation are for the acquisition of nuclear fuel, with the remaining amounts primarily
reflecting additions and upgrades to existing generation facilities (including material condition improvements during nuclear refueling outages). Generation
anticipates that it will fund capital expenditures with internally generated funds and borrowings.
Utility Registrants
Projected 2021 capital expenditures at the Utility Registrants are for continuing projects to maintain and improve operations, including enhancing reliability
and adding capacity to the transmission and distribution systems such as the Utility Registrants' construction commitments under PJM’s RTEP.
The Utility Registrants as transmission owners are subject to NERC compliance requirements. NERC provides guidance to transmission owners regarding
assessments of transmission lines. The results of these assessments could require the Utility Registrants to incur incremental capital or operating and
maintenance expenditures to ensure their transmission lines meet NERC standards. In 2010, NERC provided guidance to transmission owners that
recommended the Utility Registrants perform assessments of their transmission lines. ComEd, PECO, and BGE submitted their final bi-annual reports to
NERC in January 2014. PECO will be incurring incremental capital expenditures associated with this guidance following the completion of the assessments.
Specific projects and expenditures are identified as the assessments are completed. PECO’s forecasted 2021 capital expenditures above reflect capital
spending for remediation to be completed through 2021. ComEd, BGE, Pepco, DPL, and ACE are complete with their assessments and do not expect
capital expenditures related to this guidance in 2021.
The Utility Registrants anticipate that they will fund their capital expenditures with a combination of internally generated funds and borrowings and additional
capital contributions from parent.
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Cash Flows from Financing Activities (All Registrants)
The following tables provides a summary of the change in cash flows from financing activities for the years ended December 31, 2020 and 2019 by
Registrant:
Increase (decrease) in cash flows from financing
activities
Changes in short-term borrowings, net
Long-term debt, net
Changes in intercompany money pool
Dividends paid on common stock
Distributions to member
Contributions from parent/member
Other financing activities
Exelon
Generation
ComEd
PECO
BGE
PHI
Pepco
DPL
ACE
$
$
5
403
—
(84)
—
—
(121)
$
200
(958)
385
—
(835)
23
(19)
63
100
—
9
—
462
3
637
$
$
—
25
40
18
—
60
2
$
(116)
—
—
(22)
—
218
—
$
145
$
80
$
131
146
(3)
—
(27)
96
(5)
338
$
$
(89)
162
—
(19)
—
102
(3)
153
$
$
34
35
—
(2)
—
49
(1)
$
115
$
186
(53)
—
10
—
(58)
—
85
Increase (decrease) in cash flows from financing activities
$
203
$
(1,204)
$
Significant financing cash flow impacts for the Registrants for 2020 and 2019 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 Note 17 - 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 debt issuances and 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 for additional information on
dividend restrictions. See below for quarterly dividends declared.
For the years ended December 31, 2020 and 2019, other financing activities primarily consists of debt issuance costs. See debt issuances table
below for additional information on the Registrants’ debt issuances.
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Debt Issuances and Redemptions
See Note 17 — Debt and Credit Agreements of the Combined Notes to Consolidated Financial Statements for additional information of the Registrants’ long-
term debt. Debt activity for 2020 and 2019 by Registrant was as follows:
During 2020, the following long-term debt was issued:
Company
Type
Interest Rate
Maturity
Amount
Use of Proceeds
Exelon
Exelon
Notes
Notes
Generation
Senior Notes
4.05 %
4.70 %
3.25 %
April 15, 2030 $
1,250 Repay existing indebtedness and for general
corporate purposes.
April 15, 2050
750 Repay existing indebtedness and for general
corporate purposes.
June 1, 2025
900 Repay existing indebtedness and for general
corporate purposes.
Generation
EGR IV Nonrecourse Debt
(a)
LIBOR + 2.75%
December 15, 2027
750 Repay existing indebtedness and for general
corporate purposes.
Generation
Energy Efficiency Project
Financing
(b)
3.95 %
February 28, 2021
3 Funding to install energy conservation measures
for the Fort Meade project.
Generation
ComEd
ComEd
PECO
BGE
Pepco
Pepco
DPL
DPL
ACE
ACE
Energy Efficiency Project
Financing
(b)
First Mortgage Bonds,
Series 128
First Mortgage Bonds,
Series 129
First and Refunding
Mortgage Bonds
Senior Notes
2.53 %
2.20 %
March 1, 2030
3.00 %
March 1, 2050
March 31, 2021
3 Funding to install energy conservation measures
for the Fort AP Hill project.
350 Repay a portion of outstanding commercial paper
obligations and fund other general corporate
purposes.
650 Repay a portion of outstanding commercial paper
obligations and fund other general corporate
purposes.
2.80 %
2.90 %
June 15, 2050
350 Funding for general corporate purposes.
June 15, 2050
400 Repay commercial paper obligations and for
general corporate purposes.
First Mortgage Bonds
2.53 %
February 25, 2030
150 Repay existing indebtedness and for general
corporate purposes.
First Mortgage Bonds
3.28 %
September 23, 2050
150 Repay existing indebtedness and for general
First Mortgage Bonds
Tax-Exempt Bonds
(c)
Tax-Exempt First Mortgage
Bonds
First Mortgage Bonds
2.53 %
1.05 %
2.25 %
3.24 %
corporate purposes.
June 9, 2030
100 Repay existing indebtedness and for general
January 1, 2031
June 1, 2029
corporate purposes.
78 Refinance existing indebtedness.
23 Refinance existing indebtedness.
June 9, 2050
100 Repay existing indebtedness and for general
corporate purposes.
__________
(a) See Note 17 — Debt and Credit Agreements of the Combined Notes to Consolidated Financial Statements for additional information of nonrecourse debt.
(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) The bonds have a 1.05% interest rate through July 2025.
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During 2019, the following long-term debt was issued:
Company
Type
Interest Rate
Maturity
Amount
Use of Proceeds
Generation
Generation
Generation
ComEd
ComEd
PECO
BGE
Pepco
Pepco
DPL
ACE
ACE
Energy Efficiency Project
Financing
(a)
Energy Efficiency Project
Financing
(a)
Energy Efficiency Project
Financing
(a)
First Mortgage Bonds,
Series 126
First Mortgage Bonds,
Series 127
First and Refunding
Mortgage Bonds
Senior Notes
3.95 %
February 28, 2021
$
4 Funding to install energy conservation measures
for the Fort Meade project.
3.46 %
February 28, 2021
39 Funding to install energy conservation measures
for the Marine Corps. Logistics Project.
2.53 %
March 31, 2021
2 Funding to install energy conservation measures
for the Fort AP Hill project.
4.00 %
March 1, 2049
400 Repay a portion of ComEd’s outstanding
commercial paper obligations and fund other
general corporate purposes.
3.20 %
November 15, 2049
300 Repay a portion of ComEd’s outstanding
commercial paper obligations and fund other
general corporate purposes.
3.00 %
September 15, 2049
325 Repay short-term borrowings and for general
corporate purposes.
3.20 %
September 15, 2049
400 Repay commercial paper obligations and for
general corporate purposes.
First Mortgage Bonds
3.45 %
June 13, 2029
150 Repay existing indebtedness and for general
Unsecured Tax-Exempt
Bonds
First Mortgage Bonds
1.70 %
September 1, 2022
110 Refinance existing indebtedness.
corporate purposes.
4.14 %
December 12, 2049
75 Repay existing indebtedness and for general
corporate purposes.
First Mortgage Bonds
3.50 %
May 21, 2029
100 Repay existing indebtedness and for general
corporate purposes.
First Mortgage Bonds
4.14 %
May 21, 2049
50 Repay existing indebtedness and for general
corporate purposes.
__________
(a) For Energy Efficiency Project Financing, the maturity dates represent the expected date of project completion, upon which the respective customer assumes the
outstanding debt.
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During 2020, the following long-term debt was retired and/or redeemed:
Company
Type
Interest Rate
Exelon
Exelon
Generation
Generation
Generation
Generation
Generation
Generation
Generation
Generation
Generation
Generation
Generation
Generation
ComEd
DPL
ACE
ACE
Notes
Long-Term Software License Agreement
Senior Notes
Senior Notes
Senior Notes
(a)
Tax-Exempt Bonds
EGR IV Nonrecourse Debt
(b)
Continental Wind Nonrecourse Debt
(b)
Antelope Valley DOE Nonrecourse Debt
(b)
RPG Nonrecourse Debt
(b)
Energy Efficiency Project Financing
NUKEM
SolGen Nonrecourse Debt
Energy Efficiency Project Financing
First Mortgage Bonds
Tax-Exempt Bonds
Tax-Exempt First Mortgage Bonds
Transition Bonds
2.85%
3.95%
2.95%
4.00%
5.15%
Maturity
June 15, 2020
May 1, 2024
January 15, 2020
October 1, 2020
December 1, 2020
2.50% - 2.70%
December 1, 2025 - June 1, 2036
3 month LIBOR +
3.00%
6.00%
2.29% - 3.56%
4.11%
3.71%
3.15%
3.93%
4.12%
4.00%
5.40%
4.88%
5.55%
November 30, 2024
February 28, 2033
January 5, 2037
March 31, 2035
December 31, 2020
September 30, 2020
September 30, 2036
November 30, 2020
August 1, 2020
February 1, 2031
June 1, 2029
October 20, 2023
$
Amount
900
24
1,000
550
550
412
796
33
23
9
4
3
3
1
500
78
23
20
__________
(a) The senior notes are legacy Constellation mirror debt that were previously held at Exelon and Generation. As part of the 2012 Constellation merger, Exelon and Generation
assumed intercompany loan agreements that mirrored the terms and amounts of external obligations held by Exelon, resulting in intercompany notes payable at
Generation.
(b) See Note 17 — Debt and Credit Agreements of the Combined Notes to Consolidated Financial Statements for additional information of nonrecourse debt.
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During 2019, the following long-term debt was retired and/or redeemed:
Company
Type
Exelon
Generation
Generation
Generation
Generation
Generation
Generation
Generation
Generation
Generation
Generation
Generation
Generation
Generation
Generation
Generation
Generation
Generation
ComEd
Pepco
DPL
ACE
Long-Term Software License Agreement
Antelope Valley DOE Nonrecourse Debt
Kennett Square Capital Lease
(a)
Continental Wind Nonrecourse Debt
Pollution control notes
(a)
RPG Nonrecourse Debt
(a)
Energy Efficiency Project Financing
EGR IV Nonrecourse Debt
(a)
Hannie Mae, LLC Defense Financing
Energy Efficiency Project Financing
NUKEM
SolGen Nonrecourse Debt
Energy Efficiency Project Financing
(a)
Energy Efficiency Project Financing
Energy Efficiency Project Financing
Senior Notes
Dominion Federal Corp
Fort Detrick Project Financing
First Mortgage Bonds
Secured Tax-Exempt Bonds
Medium Term Notes, Unsecured
Transition Bonds
Interest Rate
3.95%
2.33% - 3.56%
7.83%
6.00%
2.50%
4.11%
3.46%
3 month LIBOR + 3.00%
4.12%
3.72%
3.15%
3.93%
4.17%
3.53%
4.26%
5.20%
3.17%
3.55%
2.15%
6.20% - 7.49%
7.61%
5.55%
Maturity
Amount
May 1, 2024
January 5, 2037
September 20, 2020
February 28, 2033
March 1, 2019
March 31, 2035
April 30, 2019
November 30, 2024
November 30, 2019
July 31, 2019
September 30, 2020
September 30, 2036
October 31, 2019
March 31, 2020
September 30, 2019
October 1, 2019
October 31, 2019
October 31, 2019
January 15, 2019
2021 - 2022
December 2, 2019
October 20, 2023
$
18
23
5
32
23
10
39
38
1
25
36
6
1
1
1
600
18
1
300
110
12
18
__________
(a) See Note 17 — Debt and Credit Agreements of the Combined Notes to Consolidated Financial Statements for additional information of nonrecourse debt.
From time to time and as market conditions warrant, the Registrants may engage in long-term debt retirements via tender offers, open market repurchases
or other viable options to reduce debt on their respective balance sheets.
Dividends
Quarterly dividends declared by the Exelon Board of Directors during the year ended December 31, 2020 and for the first quarter of 2021 were as follows:
Period
Declaration Date
Shareholder of Record Date
Dividend Payable Date
Cash per Share
(a)
First Quarter 2020
Second Quarter 2020
Third Quarter 2020
Fourth Quarter 2020
First Quarter 2021
January 28, 2020
April 28, 2020
July 28, 2020
November 2, 2020
February 21, 2021
February 20, 2020
May 15, 2020
August 14, 2020
November 16, 2020
March 8, 2021
March 10, 2020 $
June 10, 2020 $
September 10, 2020 $
December 10, 2020 $
March 15, 2021 $
0.3825
0.3825
0.3825
0.3825
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.
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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 $10.6 billion in
aggregate total commitments of which $7.7 billion was available to support additional commercial paper as of December 31, 2020, 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 facilities during 2020 to fund their short-term liquidity needs, when necessary. The Registrants routinely review the
sufficiency of their liquidity position, including appropriate sizing of credit facility commitments, by performing various stress test scenarios, such as
commodity price movements, increases in margin-related transactions, changes in hedging levels, and the impacts of hypothetical credit downgrades. The
Registrants have continued to closely monitor events in the financial markets and the financial institutions associated with the credit facilities, including
monitoring credit ratings and outlooks, credit default swap levels, capital raising, and merger activity. See PART I. ITEM 1A. RISK FACTORS for 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 December 31, 2020, it would have been required to provide incremental collateral of approximately $1.5 billion to
meet collateral 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 $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 December 31, 2020 and available credit facility capacity prior to any incremental collateral at December 31, 2020:
ComEd
PECO
BGE
Pepco
DPL
ACE
PJM Credit Policy
Collateral
Other Incremental Collateral
Required
(a)
Available Credit Facility Capacity Prior
to Any Incremental Collateral
$
13 $
2
10
8
4
—
$
—
34
54
—
9
—
675
600
600
264
154
113
__________
(a) Represents 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 17 — Debt and Credit Agreements of the Combined Notes to Consolidated Financial Statements for additional information of the Registrants’
credit facilities and short term borrowing activity.
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Capital Structure
At December 31, 2020, the capital structures of the Registrants consisted of the following:
Exelon
Generation
ComEd
PECO
BGE
PHI
Pepco
DPL
ACE
Long-term debt
Long-term debt to
(a)
affiliates
Common equity
Member’s equity
Commercial paper and
notes payable
50 %
1 %
46 %
— %
3 %
27 %
1 %
— %
68 %
4 %
43 %
1 %
54 %
— %
44 %
2 %
54 %
— %
47 %
— %
53 %
— %
40 %
— %
— %
58 %
2 %
— %
— %
2 %
49 %
— %
50 %
— %
1 %
48 %
— %
48 %
— %
4 %
47 %
— %
47 %
— %
6 %
__________
(a)
Includes approximately $390 million, $205 million, and $184 million owed to unconsolidated affiliates of Exelon, ComEd, and PECO respectively. These special purpose
entities were created for the sole purposes of issuing mandatorily redeemable trust preferred securities of ComEd and PECO. See Note 23 — Variable Interest Entities of
the Combined Notes to Consolidated Financial Statements for additional information regarding the authoritative guidance for VIEs.
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 16 —
Derivative Financial Instruments of the Combined Notes to Consolidated Financial Statements for additional information on collateral provisions.
The credit ratings for Exelon Corporate, PECO, BGE, PHI, Pepco, DPL, and ACE did not change for the twelve months ended December 31, 2020. On
November 4, 2020, S&P revised its assessment of the strategic relationship between Exelon and Generation and subsequently lowered Generation's senior
unsecured debt rating to 'BBB' from 'BBB+'. On July 21, 2020, S&P lowered ComEd's long-term issuer credit rating from 'A-' to a '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 December 31, 2020, are presented in the following tables:
Exelon Intercompany Money Pool
Exelon Corporate
Generation
PECO
BSC
PHI Corporate
PCI
PHI Intercompany Money Pool
Pepco
DPL
ACE
Shelf Registration Statements
$
$
For the Year Ended December 31, 2020
As of December 31, 2020
Maximum
Contributed
Maximum
Borrowed
Contributed (Borrowed)
1,364 $
— $
254
292
25
—
60
(980)
(40)
(563)
(22)
—
598
(285)
(40)
(312)
(21)
60
For the Year Ended December 31, 2020
As of December 31, 2020
Maximum
Contributed
Maximum
Borrowed
Contributed (Borrowed)
166 $
62
—
(57) $
(95)
(133)
—
—
—
Exelon, Generation, and the 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
The Utility Registrants are required to obtain short-term and long-term financing authority from Federal and State Commissions as follows:
As of December 31, 2020
(b)
ComEd
PECO
BGE
Pepco
DPL
ACE
(c)
Short-term Financing Authority
(a)
Long-term Financing Authority
(a)
Commission
Expiration Date
Amount
Commission
Expiration Date
Amount
FERC
FERC
FERC
FERC
FERC
NJBPU
December 31, 2021
$
December 31, 2021
December 31, 2021
December 31, 2021
December 31, 2021
December 31, 2021
2,500
1,500
700
500
500
350
ICC
PAPUC
MDPSC
MDPSC / DCPSC
MDPSC / DPSC
NJBPU
February 1, 2023
$
December 31, 2021
N/A
December 31, 2022
December 31, 2022
December 31, 2022
893
1,225
1,100
900
297
600
__________
(a) Generation currently has blanket financing authority it received from FERC in connection with its market-based rate authority.
(b) As of December 31, 2020, ComEd had $893 million in new money long-term debt financing authority from the ICC with an expiration date of February 1, 2023. On January
20, 2021, ComEd received $350 million of long-term debt refinancing authority from the ICC approved with an effective date of February 1, 2021 and an expiration date of
February 1, 2024.
(c) On December 2, 2020, ACE received approval from the NJBPU for $600 million in new long-term debt financing authority with an effective date of January 1, 2021.
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Contractual Obligations and Off-Balance Sheet Arrangements
The following tables summarize the Registrants’ future estimated cash payments as of December 31, 2020 under existing contractual obligations, including
payments due by period.
Exelon
(a)
Long-term debt
Interest payments on long-term debt
(c)
(b)
Operating leases
Purchase power obligations
(e)
Fuel purchase agreements
Electric supply procurement
(d)
Long-term renewable energy and REC commitments
Other purchase obligations
DC PLUG obligation
SNF obligation
(f)
Pension contributions
(g)
Total contractual obligations
Total
2021
2022 -
2023
2024 -
2025
2026
and beyond
Payment due within
$
36,839 $
1,809 $
3,933 $
3,012 $
24,486
1,213
1,613
5,667
3,170
2,238
9,374
100
1,208
3,030
1,468
141
512
1,183
1,909
301
6,673
30
—
505
2,766
224
823
1,584
1,253
548
1,492
60
—
1,010
2,592
193
264
1,237
8
437
440
10
—
1,010
$
88,938 $
14,531 $
13,693 $
9,203 $
28,085
17,660
655
14
1,663
—
952
769
—
1,208
505
51,511
__________
(a)
(b)
Includes amounts from ComEd and PECO financing trusts.
Interest payments are estimated based on final maturity dates of debt securities outstanding at December 31, 2020 and do not reflect anticipated future refinancing, early
redemptions, or debt issuances. Variable rate interest obligations are estimated based on rates as of December 31, 2020. Includes estimated interest payments due to
ComEd and PECO financing trusts.
(c) Capacity payments associated with contracted generation lease agreements are net of sublease and capacity offsets of $98 million, $55 million, $44 million, $44 million,
$44 million, and $179 million for 2021, 2022, 2023, 2024, 2025, and thereafter, respectively and $464 million in total.
(d) Purchase power obligations primarily include expected payments for REC purchases and payments associated with contracted generation agreements, which may be
reduced based on plant availability. Expected payments exclude payments on renewable generation contracts that are contingent in nature.
(e) Represents commitments to purchase nuclear fuel, natural gas and related transportation, storage capacity, and services, including those related to CENG.
(f) Represents the future estimated value at December 31, 2020 of the cash flows associated with all contracts, both cancellable and non-cancellable, entered into between
the Registrants and third-parties for the provision of services and materials, entered into in the normal course of business not specifically reflected elsewhere in this table.
These estimates are subject to significant variability from period to period.
(g) These amounts represent Exelon’s expected contributions to its qualified pension plans. Qualified pension contributions for years after 2026 are not included.
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Generation
Long-term debt
Interest payments on long-term debt
(b)
Operating leases
(a)
Purchase power obligations
(d)
Fuel purchase agreements
Other purchase obligations
(e)
(c)
SNF obligation
Total contractual obligations
Total
2021
2022 -
2023
2024 -
2025
2026
and beyond
Payment due within
$
6,066 $
195 $
1,024 $
900 $
3,536
731
1,613
4,450
2,286
1,208
270
47
512
928
1,208
—
474
114
823
1,207
231
—
443
109
264
1,022
155
—
$
19,890 $
3,160 $
3,873 $
2,893 $
3,947
2,349
461
14
1,293
692
1,208
9,964
__________
(a)
Interest payments are estimated based on final maturity dates of debt securities outstanding at December 31, 2020 and do not reflect anticipated future refinancing, early
redemptions, or debt issuances. Variable rate interest obligations are estimated based on rates as of December 31, 2020.
(b) Capacity payments associated with contracted generation lease agreements are net of sublease and capacity offsets of $98 million, $55 million, $44 million, $44 million,
$44 million, and $179 million for 2021, 2022, 2023, 2024, 2025, and thereafter, respectively and $464 million in total.
(c) Purchase power obligations primarily include expected payments for REC purchases and capacity payments associated with contracted generation agreements, which
may be reduced based on plant availability. Expected payments exclude payments on renewable generation contracts that are contingent in nature.
(d) Represents commitments to purchase nuclear fuel, natural gas and related transportation, storage capacity, and services, including those related to CENG.
(e) Represents the future estimated value at December 31, 2020 of the cash flows associated with all contracts, both cancellable and non-cancellable, entered into between
Generation and third-parties for the provision of services and materials, entered into in the normal course of business not specifically reflected elsewhere in this table.
These estimates are subject to significant variability from period to period.
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ComEd
(a)
Long-term debt
Interest payments on long-term debt
Operating leases
(b)
Electric supply procurement
Long-term renewable energy and REC commitments
Other purchase obligations
ZEC commitments
(c)
Total contractual obligations
Total
2021
2022 -
2023
2024 -
2025
2026
and beyond
Payment due within
$
9,284 $
350 $
— $
250 $
7,207
8
600
1,953
1,524
1,127
360
3
388
269
1,397
176
720
3
212
485
74
351
711
2
—
384
35
351
8,684
5,416
—
—
815
18
249
$
21,703 $
2,943 $
1,845 $
1,733 $
15,182
__________
(a)
(b)
Includes amounts from ComEd financing trust.
Interest payments are estimated based on final maturity dates of debt securities outstanding at December 31, 2020 and do not reflect anticipated future refinancing, early
redemptions, or debt issuances. Includes estimated interest payments due to the ComEd financing trust.
(c) Represents the future estimated value at December 31, 2020 of the cash flows associated with all contracts, both cancellable and non-cancellable, entered into between
ComEd and third-parties for the provision of services and materials, entered into in the normal course of business not specifically reflected elsewhere in this table. These
estimates are subject to significant variability from period to period.
PECO
Long-term debt
(a)
Interest payments on long-term debt
Operating leases
(b)
(c)
Fuel purchase agreements
Electric supply procurement
(d)
Other purchase obligations
Total contractual obligations
Total
2021
2022 -
2023
2024 -
2025
2026
and beyond
Payment due within
$
3,984 $
2,867
1
405
536
898
300 $
146
1
138
431
813
400 $
280
—
183
105
66
350 $
271
—
41
—
19
2,934
2,170
—
43
—
—
$
8,691 $
1,829 $
1,034 $
681 $
5,147
__________
(a)
(b)
Includes amounts from PECO financing trusts.
Interest payments are estimated based on final maturity dates of debt securities outstanding at December 31, 2020 and do not reflect anticipated future refinancing, early
redemptions, or debt issuances. Includes estimated interest payments due to the PECO financing trusts.
(c) Represents commitments to purchase natural gas and related transportation, storage capacity, and services.
(d) Represents the future estimated value at December 31, 2020 of the cash flows associated with all contracts, both cancellable and non-cancellable, entered into between
PECO and third-parties for the provision of services and materials, entered into in the normal course of business not specifically reflected elsewhere in this table. These
estimates are subject to significant variability from period to period.
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BGE
Long-term debt
Interest payments on long-term debt
Operating leases
(a)
Fuel purchase agreements
Electric supply procurement
(b)
Other purchase obligations
Total contractual obligations
(c)
Total
2021
2022 -
2023
2024 -
2025
2026
and beyond
Payment due within
$
3,700 $
300 $
550 $
— $
2,450
81
517
1,088
1,372
127
46
84
665
976
240
17
128
423
364
220
—
109
—
26
2,850
1,863
18
196
—
6
$
9,208 $
2,198 $
1,722 $
355 $
4,933
__________
(a)
Interest payments are estimated based on final maturity dates of debt securities outstanding at December 31, 2020 and do not reflect anticipated future refinancing, early
redemptions, or debt issuances.
(b) Represents commitments to purchase natural gas and related transportation, storage capacity, and services.
(c) Represents the future estimated value at December 31, 2020 of the cash flows associated with all contracts, both cancellable and non-cancellable, entered into between
BGE and third-parties for the provision of services and materials, entered into in the normal course of business not specifically reflected elsewhere in this table. These
estimates are subject to significant variability from period to period.
PHI
Long-term debt
Interest payments on long-term debt
Finance leases
Operating leases
(a)
Fuel purchase agreements
Electric supply procurement
Long-term renewable energy and REC commitments
(b)
Other purchase obligations
DC PLUG obligation
(c)
Total contractual obligations
Total
2021
2022 -
2023
2024 -
2025
2026
and beyond
Payment due within
$
6,443 $
4,135
339 $
266
809 $
517
700 $
447
53
306
295
1,791
285
1,767
100
8
40
33
1,051
32
1,362
30
16
77
66
732
63
341
60
16
69
65
8
53
48
10
4,595
2,905
13
120
131
—
137
16
—
$
15,175 $
3,161 $
2,681 $
1,416 $
7,917
__________
(a)
Interest payments are estimated based on final maturity dates of debt securities outstanding at December 31, 2020 and do not reflect anticipated future refinancing, early
redemptions, or debt issuances. Variable rate interest obligations are estimated based on rates as of December 31, 2020.
(b) Represents commitments to purchase natural gas and related transportation, storage capacity, and services.
(c) Represents the future estimated value at December 31, 2020 of the cash flows associated with all contracts, both cancellable and non-cancellable, entered into between
Pepco, DPL, ACE, and PHISCO and third-parties for the provision of services and materials, entered into in the normal course of business not specifically reflected
elsewhere in this table. These estimates are subject to significant variability from period to period.
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Pepco
Long-term debt
Interest payments on long-term debt
Finance leases
Operating leases
(a)
Electric supply procurement
Other purchase obligations
DC PLUG obligation
(b)
Total contractual obligations
Total
2021
2022 -
2023
2024 -
2025
2026
and beyond
Payment due within
$
3,185 $
2,429
18
63
754
1,034
100
— $
147
3
8
432
748
30
309 $
281
400 $
251
2,476
1,750
6
15
314
243
60
6
12
8
32
10
3
28
—
11
—
$
7,583 $
1,368 $
1,228 $
719 $
4,268
__________
(a)
Interest payments are estimated based on final maturity dates of debt securities outstanding at December 31, 2020 and do not reflect anticipated future refinancing, early
redemptions, or debt issuances.
(b) Represents the future estimated value at December 31, 2020 of the cash flows associated with all contracts, both cancellable and non-cancellable, entered into between
Pepco and third-parties for the provision of services and materials, entered into in the normal course of business not specifically reflected elsewhere in this table. These
estimates are subject to significant variability from period to period.
DPL
Long-term debt
Interest payments on long-term debt
Finance leases
Operating leases
(a)
Fuel purchase agreements
Electric supply procurement
(b)
Long-term renewable energy and associated REC commitments
Other purchase obligations
Total contractual obligations
(c)
Total
2021
2022 -
2023
2024 -
2025
2026
and beyond
Payment due within
$
1,666 $
1,016
79 $
59
500 $
116
— $
82
21
80
295
469
285
419
3
11
33
290
32
349
6
19
66
179
63
63
6
15
65
—
53
7
1,087
759
6
35
131
—
137
—
$
4,251 $
856 $
1,012 $
228 $
2,155
__________
(a)
Interest payments are estimated based on final maturity dates of debt securities outstanding at December 31, 2020 and do not reflect anticipated future refinancing, early
redemptions, or debt issuances. Variable rate interest obligations are estimated based on rates as of December 31, 2020.
(b) Represents commitments to purchase natural gas and related transportation, storage capacity, and services.
(c) Represents the future estimated value at December 31, 2020 of the cash flows associated with all contracts, both cancellable and non-cancellable, entered into between
DPL and third-parties for the provision of services and materials, entered into in the normal course of business not specifically reflected elsewhere in this table. These
estimates are subject to significant variability from period to period.
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ACE
Long-term debt
Interest payments on long-term debt
Finance leases
Operating leases
(a)
Electric supply procurement
Other purchase obligations
Total contractual obligations
(b)
Total
2021
2022 -
2023
2024 -
2025
2026
and beyond
Payment due within
$
1,407 $
527
14
16
568
267
259 $
46
2
5
329
236
— $
92
4
7
239
25
300 $
86
4
4
—
6
848
303
4
—
—
—
$
2,799 $
877 $
367 $
400 $
1,155
__________
(a)
Interest payments are estimated based on final maturity dates of debt securities outstanding at December 31, 2020 and do not reflect anticipated future refinancing, early
redemptions, or debt issuances.
(b) Represents the future estimated value at December 31, 2020 of the cash flows associated with all contracts, both cancellable and non-cancellable, entered into between
ACE and third-parties for the provision of services and materials, entered into in the normal course of business not specifically reflected elsewhere in this table. These
estimates are subject to significant variability from period to period.
See Note 19 — Commitments and Contingencies and Note 3 — Regulatory Matters of the Combined Notes to Consolidated Financial Statements for
additional information of the Registrants’ other commitments potentially triggered by future events. Additionally, see below for where to find additional
information regarding certain contractual obligations in the Combined Notes to the Consolidated Financial Statements:
Item
Long-term debt
Interest payments on long-term debt
Finance leases
Operating leases
SNF obligation
REC commitments
ZEC commitments
DC PLUG obligation
Pension contributions
Sales of Customer Accounts Receivable
Location within Notes to the Consolidated Financial Statements
Note 17 — Debt and Credit Agreements
Note 17 — Debt and Credit Agreements
Note 11 — Leases
Note 11 — Leases
Note 19 — Commitments and Contingencies
Note 3 — Regulatory Matters
Note 3 — Regulatory Matters
Note 3 — Regulatory Matters
Note 15 — Retirement Benefits
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 6 — Accounts Receivable of the Combined Notes to Consolidated
Financial Statements for additional information.
ITEM 7A.
QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK
The Registrants are exposed to market risks associated with adverse changes in commodity prices, counterparty credit, interest rates, and equity prices.
Exelon’s RMC approves risk management policies and objectives for risk assessment, control and valuation, counterparty credit approval, and the
monitoring and reporting of risk exposures. The RMC is chaired by the chief executive officer and includes the chief risk officer, chief strategy officer, chief
executive officer of Exelon Utilities, chief commercial officer, chief financial officer, and chief executive officer of Constellation. The RMC reports to the
Finance and Risk Committee of the Exelon Board of Directors on the scope of the risk management activities.
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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 2021 through 2023.
In general, increases and decreases in forward market prices have a positive and negative impact, respectively, on Generation’s owned and contracted
generation positions which have not been hedged. Exelon's hedging program involves the hedging of commodity price risk for Exelon's expected generation,
typically on a ratable basis over three-year periods. As of December 31, 2020, the percentage of expected generation hedged for the Mid-Atlantic, Midwest,
New York, and ERCOT reportable segments is 94%-97% for 2021. The percentage of expected generation hedged is the amount of equivalent sales divided
by the expected generation. Expected generation is the volume of energy that best represents our commodity position in energy markets from owned or
contracted generation based upon a simulated dispatch model that makes assumptions regarding future market conditions, which are calibrated to market
quotes for power, fuel, load following products, and options. Equivalent sales represent all hedging products, which include economic hedges and certain
non-derivative contracts, including Generation’s sales to ComEd, PECO, BGE, Pepco, DPL, and ACE to serve their retail load.
A portion of Generation’s hedging strategy may be accomplished with fuel products based on assumed correlations between power and fuel prices, which
routinely change in the market. Market price risk exposure is the risk of a change in the value of unhedged positions. The forecasted market price risk
exposure for Generation’s entire economic hedge portfolio associated with a $5 reduction in the annual average around-the-clock energy price based on
December 31, 2020 market conditions and hedged position would be a decrease in pre-tax net income of approximately $15 million for 2021. Power price
sensitivities are derived by adjusting power price assumptions while keeping all other price inputs constant. Generation actively manages its portfolio to
mitigate market price risk exposure for its unhedged position. Actual results could differ depending on the specific timing of, and markets affected by, price
changes, as well as future changes in Generation’s portfolio. See Note 16 — Derivative Financial Instruments of the Combined Notes to Consolidated
Financial Statements for additional information.
Fuel Procurement
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. Supply market conditions may make Generation’s procurement contracts subject to credit risk related to the potential
non-performance of counterparties to deliver the contracted commodity or service at the contracted prices. Approximately 60% of Generation’s uranium
concentrate requirements from 2021 through 2025 are supplied by three suppliers. In the event of non-performance by these or other suppliers, Generation
believes that replacement uranium 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.
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Utility Registrants
ComEd entered into 20-year floating-to-fixed renewable energy swap contracts beginning in June 2012, which are considered an economic hedge and have
changes in fair value recorded to an offsetting regulatory asset or liability. ComEd has block energy contracts to procure electric supply that are executed
through a competitive procurement process, which are considered derivatives and qualify for NPNS, and as a result are accounted for on an accrual basis of
accounting. PECO, BGE, Pepco, DPL, and ACE have contracts to procure electric supply that are executed through a competitive procurement process.
BGE, Pepco, DPL, and ACE have certain full requirements contracts, which are considered derivatives and qualify for NPNS, and as a result are accounted
for on an accrual basis of accounting. Other full requirements contracts are not derivatives.
PECO, BGE, and DPL also have executed derivative natural gas contracts, which either qualify for NPNS or have no mark-to-market balances because the
derivatives are index priced, to hedge their long-term price risk in the natural gas market. The hedging programs for natural gas procurement have no direct
impact on their financial statements. PECO, BGE, Pepco, DPL, and ACE do not execute derivatives for speculative or proprietary trading purposes.
For additional information on these contracts, see Note 3 — Regulatory Matters and Note 16 — Derivative Financial Instruments of the Combined Notes to
Consolidated Financial Statements.
Trading and Non-Trading Marketing Activities
The following table detailing Exelon’s, Generation’s, and ComEd’s trading and non-trading marketing activities are included to address the recommended
disclosures by the energy industry’s Committee of Chief Risk Officers (CCRO).
The following table provides detail on changes in Exelon’s, Generation’s, and ComEd’s commodity mark-to-market net asset or liability balance sheet
position from December 31, 2018 to December 31, 2020. 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 16 — Derivative Financial Instruments of the Combined Notes to Consolidated Financial Statements for additional information on the
balance sheet classification of the mark-to-market energy contract net assets (liabilities) recorded as of December 31, 2020 and 2019.
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Total mark-to-market energy contract net assets (liabilities) at December 31, 2018
(a)
$
299 $
548 $
(249)
Exelon
Generation
ComEd
Total change in fair value during 2019 of contracts recorded in result of operations
Reclassification to realized at settlement of contracts recorded in results of operations
Changes in fair value—recorded through regulatory assets
Changes in allocated collateral
(b)
Net option premium received
Option premium amortization
Upfront payments and amortizations
Total mark-to-market energy contract net assets (liabilities) at December 31, 2019
(a)
(c)
Total change in fair value during 2020 of contracts recorded in result of operations
Reclassification to realized at settlement of contracts recorded in results of operations
Changes in allocated collateral
Net option premium paid
Option premium amortization
Upfront payments and amortizations
(c)
(427)
226
(52)
572
29
(22)
(58)
567
(203)
469
(513)
139
(104)
73
(427)
226
—
572
29
(22)
(58)
868
(203)
469
(513)
139
(104)
73
—
—
(52)
—
—
—
—
(301)
—
—
—
—
—
—
Total mark-to-market energy contract net assets (liabilities) at December 31, 2020
(a)
$
428 $
729 $
(301)
__________
(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 December 31, 2019 and 2020, ComEd recorded a regulatory liability of $301
million and $301 million, respectively, related to its mark-to-market derivative liabilities with Generation and unaffiliated suppliers. ComEd recorded $78 million of decreases
in fair value and an increase for realized losses due to settlements of $26 million in purchased power expense associated with floating-to-fixed energy swap contracts with
unaffiliated suppliers for the year ended December 31, 2019. ComEd recorded $33 million of decrease in fair value and an increase for realized losses due to settlements
of $33 million recorded in purchased power expense associated with floating-to-fixed energy swap contracts with unaffiliated suppliers for the year ended December 31,
2020.
Includes derivative contracts acquired or sold by Generation through upfront payments or receipts of cash, excluding option premiums, and the associated amortizations.
(c)
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 18 — 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
2021
2022
2023
2024
2025
2026 and
Beyond
Total Fair
Value
Maturities Within
Normal Operations, Commodity derivative contracts
(a)(b)
:
Actively quoted prices (Level 1)
$
(48) $
8 $
8 $
11 $
17 $
Prices provided by external sources (Level 2)
Prices based on model or other valuation methods (Level
3)
(c)
212
182
78
80
13
47
(1)
(7)
1
(16)
— $
—
(157)
Total
$
346 $
166 $
68 $
3 $
2 $
(157) $
(4)
303
129
428
__________
(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 $416 million at December 31,
2020.
Includes ComEd’s net assets (liabilities) associated with the floating-to-fixed energy swap contracts with unaffiliated suppliers.
(c)
Generation
2021
2022
2023
2024
2025
2026 and
Beyond
Total Fair
Value
Maturities Within
Normal Operations, Commodity derivative contracts
(a)(b)
:
Actively quoted prices (Level 1)
$
(48) $
8 $
8 $
11 $
17 $
— $
Prices provided by external sources (Level 2)
Prices based on model or other valuation methods (Level
3)
212
215
78
109
13
75
(1)
20
1
10
—
1
Total
$
379 $
195 $
96 $
30 $
28 $
1 $
(4)
303
430
729
__________
(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 $416 million at December 31,
2020.
ComEd
(a)
Commodity derivative contracts :
Prices based on model or other valuation methods (Level
3)
(a)
$
(33) $
(29) $
(28) $
(27) $
(26) $
(158) $
(301)
2021
2022
2023
2024
2025
2026 and
Beyond
Total Fair
Value
Maturities Within
__________
(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 16—Derivative Financial
Instruments of the Combined Notes to Consolidated Financial Statements for a 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 December 31, 2020. The tables further
delineate that exposure by credit rating of the counterparties and provide guidance on the concentration of credit risk to individual counterparties and an
indication of the duration of a company’s credit risk by credit rating of the counterparties. The figures in the table 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 December 31, 2020
Investment grade
Non-investment grade
No external ratings
Internally rated—investment grade
Internally rated—non-investment grade
Total
$
$
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
577 $
32
165
80
27 $
—
1
28
854 $
56 $
550
32
164
52
798
— $
—
—
—
— $
Rating as of December 31, 2020
Investment grade
Non-investment grade
No external ratings
Internally rated—investment grade
Internally rated—non-investment grade
Total
Net Credit Exposure by Type of Counterparty
Financial institutions
Investor-owned utilities, marketers, power producers
Energy cooperatives and municipalities
Other
Total
Maturity of Credit Risk Exposure
Less than
2 Years
2-5
Years
Exposure
Greater than
5 Years
Total Exposure
Before Credit
Collateral
$
$
520 $
32
128
67
36 $
21 $
—
25
10
—
12
3
747 $
71 $
36 $
As of December 31, 2020
$
$
—
—
—
—
—
577
32
165
80
854
15
607
138
38
798
__________
(a) As of December 31, 2020, credit collateral held from counterparties where Generation had credit exposure included $31 million of cash and $25 million of letters of credit.
The Utility Registrants
Credit risk for the Utility Registrants is governed by credit and collection policies, which are aligned with state regulatory requirements. The Utility Registrants
are currently obligated to provide service to all electric customers within their franchised territories. The Utility Registrants record an allowance for credit
losses on customer receivables, based upon historical loss experience, current conditions, and forward-looking risk factors, to provide for the potential loss
from nonpayment by these customers. The Utility Registrants will monitor nonpayment from customers and will make any necessary adjustments to the
allowance for credit losses on customer receivables. See Note 1 — Significant Accounting Policies of the Combined Notes to Consolidated Financial
Statements for the allowance for credit losses policy. The Utility Registrants did not have any customers representing over 10% of their revenues as of
December 31, 2020. See Note 3 — Regulatory Matters of the
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Combined Notes to Consolidated Financial Statements for additional information regarding the regulatory recovery of credit losses on customer accounts
receivable.
As of December 31, 2020, the Utility Registrants net credit exposure to suppliers was immaterial. See Note 16 — Derivative Financial Instruments of the
Combined Notes to Consolidated Financial Statements.
Credit-Risk-Related Contingent Features (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 16 — Derivative Financial Instruments of the Combined Notes to Consolidated
Financial Statements for additional information regarding collateral requirements and Note 19 — 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 ITEM 7. Liquidity and Capital Resources — Credit Matters —
Exelon Credit Facilities for additional information.
The Utility Registrants
As of December 31, 2020, the Utility Registrants were not required to post collateral under their energy and/or natural gas procurement contracts. See Note
3 — Regulatory Matters and Note 16 — Derivative Financial Instruments of the Combined Notes to Consolidated Financial Statements for additional
information.
RTOs and ISOs (All Registrants)
All Registrants participate in all, or some, of the established, wholesale spot energy markets that are administered by PJM, ISO-NE, NYISO, CAISO, MISO,
SPP, AESO, OIESO, and ERCOT. ERCOT is not subject to regulation by FERC but performs a similar function in Texas to that performed by RTOs in
markets regulated by FERC. In these areas, power is traded through bilateral agreements between buyers and sellers and on the spot energy markets that
are administered by the RTOs or ISOs, as applicable. In areas where there is no spot energy market, electricity is purchased and sold solely through bilateral
agreements. For sales into the spot markets administered by an RTO or ISO, the RTO or ISO maintains financial assurance policies that are established and
enforced by those administrators. The credit policies of the RTOs and ISOs may, under certain circumstances, require that losses arising from the default of
one member on spot energy market transactions be shared by the remaining participants. Non-performance or non-payment by a major counterparty could
result in a material adverse impact on the Registrants’ financial statements.
Exchange Traded Transactions (Exelon, Generation, PHI, and DPL)
Generation enters into commodity transactions on NYMEX, ICE, NASDAQ, NGX, and the Nodal exchange ("the Exchanges"). DPL enters into commodity
transactions on ICE. The Exchange clearinghouses act as the counterparty to each trade. Transactions on the Exchanges must adhere to comprehensive
collateral and margining requirements. As a result, transactions on Exchanges are significantly collateralized and have limited counterparty credit risk.
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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 point increase in the interest rates associated with unhedged variable-
rate debt (excluding Commercial Paper) and fixed-to-floating swaps would result in approximately a $2 million decrease in Exelon pre-tax income for the
year ended December 31, 2020. 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 16—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 December 31, 2020,
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 $851 million reduction in
the fair value of the trust assets. This calculation holds all other variables constant and assumes only the discussed changes in interest rates and equity
prices. See Liquidity and Capital Resources section of ITEM 7. MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND
RESULTS OF OPERATIONS for additional information of equity price risk as a result of the current capital and credit market conditions.
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ITEM 7.
MANAGEMENT’S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS
Generation
General
Generation’s integrated business consists of the generation, physical delivery, and marketing of power across multiple geographical regions through its
customer-facing business, Constellation, which sells electricity and natural gas to both wholesale and retail customers. Generation also sells renewable
energy and other energy-related products and services. Generation has five reportable segments consisting of the Mid-Atlantic, Midwest, New York, ERCOT,
and Other Power Regions. These segments are discussed in further detail in ITEM 1. BUSINESS — Exelon Generation Company, LLC of this Form 10-K.
Executive Overview
A discussion of items pertinent to Generation’s executive overview is set forth under ITEM 7. MANAGEMENT'S DISCUSSION AND ANALYSIS OF
FINANCIAL CONDITION AND RESULTS OF OPERATIONS — Exelon Corporation — Executive Overview of this Form 10-K.
Results of Operations
Year Ended December 31, 2020 Compared to Year Ended December 31, 2019
A discussion of Generation’s results of operations for 2020 compared to 2019 is set forth under Results of Operations—Generation in EXELON
CORPORATION — Results of Operations of this Form 10-K.
Liquidity and Capital Resources
Generation’s business is capital intensive and requires considerable capital resources. Generation’s capital resources are primarily provided by internally
generated cash flows from operations and, to the extent necessary, external financing, including the issuance of long-term debt, commercial paper,
participation in the intercompany money pool, or capital contributions from Exelon. Generation’s access to external financing at reasonable terms is
dependent on its credit ratings and general business conditions, as well as that of the utility industry in general. If these conditions deteriorate to where
Generation no longer has access to the capital markets at reasonable terms, Generation has credit facilities in the aggregate of $5.3 billion that currently
support its commercial paper program and issuances of letters of credit.
See EXELON CORPORATION — Liquidity and Capital Resources and Note 17 — Debt and Credit Agreements of the Combined Notes to Consolidated
Financial Statements of this Form 10-K for additional information.
Capital resources are used primarily to fund Generation’s capital requirements, including construction expenditures, retire debt, pay dividends, fund pension
and OPEB obligations, and invest in new and existing ventures. Generation spends a significant amount of cash on capital improvements and construction
projects that have a long-term return on investment.
Cash Flows from Operating Activities
A discussion of items pertinent to Generation’s cash flows from operating activities is set forth under Cash Flows from Operating Activities in EXELON
CORPORATION — Liquidity and Capital Resources of this Form 10-K.
Cash Flows from Investing Activities
A discussion of items pertinent to Generation’s cash flows from investing activities is set forth under Cash Flows from Investing Activities in EXELON
CORPORATION — Liquidity and Capital Resources of this Form 10-K.
Cash Flows from Financing Activities
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A discussion of items pertinent to Generation’s cash flows from financing activities is set forth under Cash Flows from Financing Activities in EXELON
CORPORATION — Liquidity and Capital Resources of this Form 10-K.
Credit Matters
A discussion of credit matters pertinent to Generation is set forth under Credit Matters in EXELON CORPORATION — Liquidity and Capital Resources of
this Form 10-K.
Contractual Obligations and Off-Balance Sheet Arrangements
A discussion of Generation’s contractual obligations, commercial commitments, and off-balance sheet arrangements is set forth under Contractual
Obligations and Off-Balance Sheet Arrangements in EXELON CORPORATION — Liquidity and Capital Resources of this Form 10-K.
Critical Accounting Policies and Estimates
See All Registrants — Critical Accounting Policies and Estimates above for a discussion of Generation’s critical accounting policies and estimates.
New Accounting Pronouncements
See Note 1 — Significant Accounting Policies of the Combined Notes to Consolidated Financial Statements for information regarding new accounting
pronouncements.
ITEM 7A.
QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK
Generation
Generation is exposed to market risks associated with credit, interest rates, and equity price. These risks are described above under Quantitative and
Qualitative Disclosures about Market Risk — Exelon.
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ITEM 7.
MANAGEMENT’S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS
ComEd
General
ComEd operates in a single business segment and its operations consist of the purchase and regulated retail sale of electricity and the provision of
distribution and transmission services to retail customers in northern Illinois, including the City of Chicago. This segment is discussed in further detail in ITEM
1. BUSINESS—ComEd of this Form 10-K.
Executive Overview
A discussion of items pertinent to ComEd’s executive overview is set forth under EXELON CORPORATION—Executive Overview of this Form 10-K.
Results of Operations
Year Ended December 31, 2020 Compared to Year Ended December 31, 2019
A discussion of ComEd’s results of operations for 2020 compared to 2019 is set forth under Results of Operations—ComEd in EXELON CORPORATION —
Results of Operations of this Form 10-K.
Liquidity and Capital Resources
ComEd’s business is capital intensive and requires considerable capital resources. ComEd’s capital resources are primarily provided by internally generated
cash flows from operations and, to the extent necessary, external financing, including the issuance of long-term debt, commercial paper, or credit facility
borrowings. ComEd’s access to external financing at reasonable terms is dependent on its credit ratings and general business conditions, as well as that of
the utility industry in general. At December 31, 2020, ComEd had access to a revolving credit facility with aggregate bank commitments of $1 billion.
See EXELON CORPORATION — Liquidity and Capital Resources and Note 17 — Debt and Credit Agreements of the Combined Notes to Consolidated
Financial Statements of this Form 10-K for additional information.
Capital resources are used primarily to fund ComEd’s capital requirements, including construction expenditures, retire debt, pay dividends, fund pension and
OPEB obligations, and invest in new and existing ventures. ComEd spends a significant amount of cash on capital improvements and construction projects
that have a long-term return on investment. Additionally, ComEd operates in rate-regulated environments in which the amount of new investment recovery
may be limited and where such recovery takes place over an extended period of time.
Cash Flows from Operating Activities
A discussion of items pertinent to ComEd’s cash flows from operating activities is set forth under Cash Flows from Operating Activities in EXELON
CORPORATION — Liquidity and Capital Resources of this Form 10-K.
Cash Flows from Investing Activities
A discussion of items pertinent to ComEd’s cash flows from investing activities is set forth under Cash Flows from Investing Activities in EXELON
CORPORATION — Liquidity and Capital Resources of this Form 10-K.
Cash Flows from Financing Activities
A discussion of items pertinent to ComEd’s cash flows from financing activities is set forth under Cash Flows from Financing Activities in EXELON
CORPORATION — Liquidity and Capital Resources of this Form 10-K.
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Credit Matters
A discussion of credit matters pertinent to ComEd is set forth under Credit Matters in EXELON CORPORATION — Liquidity and Capital Resources of this
Form 10-K.
Contractual Obligations and Off-Balance Sheet Arrangements
A discussion of ComEd’s contractual obligations, commercial commitments, and off-balance sheet arrangements is set forth under Contractual Obligations
and Off-Balance Sheet Arrangements in EXELON CORPORATION — Liquidity and Capital Resources of this Form 10-K.
Critical Accounting Policies and Estimates
See All Registrants — Critical Accounting Policies and Estimates above for a discussion of ComEd’s critical accounting policies and estimates.
New Accounting Pronouncements
See Note 1 — Significant Accounting Policies of the Combined Notes to Consolidated Financial Statements for information regarding new accounting
pronouncements.
ITEM 7A.
QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK
ComEd
ComEd is exposed to market risks associated with commodity price and credit. These risks are described above under Quantitative and Qualitative
Disclosures about Market Risk— Exelon.
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ITEM 7.
MANAGEMENT’S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS
PECO
General
PECO operates in a single business segment and its operations consist of the purchase and regulated retail sale of electricity and the provision of
distribution and transmission services in southeastern Pennsylvania including the City of Philadelphia, and the purchase and regulated retail sale of natural
gas and the provision of distribution service in Pennsylvania in the counties surrounding the City of Philadelphia. This segment is discussed in further detail
in ITEM 1. BUSINESS—PECO of this Form 10-K.
Executive Overview
A discussion of items pertinent to PECO’s executive overview is set forth under EXELON CORPORATION—Executive Overview of this Form 10-K.
Results of Operations
Year Ended December 31, 2020 Compared to Year Ended December 31, 2019
A discussion of PECO’s results of operations for 2020 compared to 2019 is set forth under Results of Operations—PECO in EXELON CORPORATION —
Results of Operations of this Form 10-K.
Liquidity and Capital Resources
PECO’s business is capital intensive and requires considerable capital resources. PECO’s capital resources are primarily provided by internally generated
cash flows from operations and, to the extent necessary, external financing, including the issuance of long-term debt, commercial paper, or participation in
the intercompany money pool. PECO’s access to external financing at reasonable terms is dependent on its credit ratings and general business conditions,
as well as that of the utility industry in general. If these conditions deteriorate to where PECO no longer has access to the capital markets at reasonable
terms, PECO has access to a revolving credit facility. At December 31, 2020, PECO had access to a revolving credit facility with aggregate bank
commitments of $600 million.
See EXELON CORPORATION — Liquidity and Capital Resources and Note 17 — Debt and Credit Agreements of the Combined Notes to Consolidated
Financial Statements of this Form 10-K for additional information.
Capital resources are used primarily to fund PECO’s capital requirements, including construction expenditures, retire debt, pay dividends, fund pension and
OPEB obligations, and invest in new and existing ventures. PECO spends a significant amount of cash on capital improvements and construction projects
that have a long-term return on investment. Additionally, PECO operates in a rate-regulated environment in which the amount of new investment recovery
may be limited and where such recovery takes place over an extended period of time.
Cash Flows from Operating Activities
A discussion of items pertinent to PECO’s cash flows from operating activities is set forth under Cash Flows from Operating Activities in EXELON
CORPORATION — Liquidity and Capital Resources of this Form 10-K.
Cash Flows from Investing Activities
A discussion of items pertinent to PECO’s cash flows from investing activities is set forth under Cash Flows from Investing Activities in EXELON
CORPORATION — Liquidity and Capital Resources of this Form 10-K.
Cash Flows from Financing Activities
A discussion of items pertinent to PECO’s cash flows from financing activities is set forth under Cash Flows from Financing Activities in EXELON
CORPORATION — Liquidity and Capital Resources of this Form 10-K.
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Credit Matters
A discussion of credit matters pertinent to PECO is set forth under Credit Matters in “EXELON CORPORATION — Liquidity and Capital Resources of this
Form 10-K.
Contractual Obligations and Off-Balance Sheet Arrangements
A discussion of PECO’s contractual obligations, commercial commitments, and off-balance sheet arrangements is set forth under Contractual Obligations
and Off-Balance Sheet Arrangements in EXELON CORPORATION — Liquidity and Capital Resources of this Form 10-K.
Critical Accounting Policies and Estimates
See All Registrants — Critical Accounting Policies and Estimates above for a discussion of PECO’s critical accounting policies and estimates.
New Accounting Pronouncements
See Note 1 — Significant Accounting Policies of the Combined Notes to Consolidated Financial Statements for information regarding new accounting
pronouncements.
ITEM 7A.
QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK
PECO
PECO is exposed to market risks associated with credit and interest rates. These risks are described above under Quantitative and Qualitative Disclosures
about Market Risk—Exelon.
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ITEM 7.
MANAGEMENT’S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS
BGE
General
BGE operates in a single business segment and its operations consist of the purchase and regulated retail sale of electricity and the provision of distribution
and transmission services in central Maryland, including the City of Baltimore, and the purchase and regulated retail sale of natural gas and the provision of
distribution service in central Maryland, including the City of Baltimore. This segment is discussed in further detail in ITEM 1. BUSINESS—BGE of this Form
10-K.
Executive Overview
A discussion of items pertinent to BGE’s executive overview is set forth under EXELON CORPORATION — Executive Overview of this Form 10-K.
Results of Operations
Year Ended December 31, 2020 Compared to Year Ended December 31, 2019
A discussion of BGE’s results of operations for 2020 compared to 2019 is set forth under Results of Operations—BGE in EXELON CORPORATION —
Results of Operations of this Form 10-K.
Liquidity and Capital Resources
BGE’s business is capital intensive and requires considerable capital resources. BGE’s capital resources are primarily provided by internally generated cash
flows from operations and, to the extent necessary, external financing, including the issuance of long-term debt or commercial paper. BGE’s access to
external financing at reasonable terms is dependent on its credit ratings and general business conditions, as well as that of the utility industry in general. If
these conditions deteriorate to where BGE no longer has access to the capital markets at reasonable terms, BGE has access to a revolving credit facility. At
December 31, 2020, BGE had access to a revolving credit facility with aggregate bank commitments of $600 million.
See EXELON CORPORATION — Liquidity and Capital Resources and Note 17 — Debt and Credit Agreements of the Combined Notes to Consolidated
Financial Statements of this Form 10-K for additional information.
Capital resources are used primarily to fund BGE’s capital requirements, including construction expenditures, retire debt, pay dividends, fund pension and
OPEB obligations, and invest in new and existing ventures. BGE spends a significant amount of cash on capital improvements and construction projects that
have a long-term return on investment. Additionally, BGE operates in a rate-regulated environment in which the amount of new investment recovery may be
limited and where such recovery takes place over an extended period of time.
Cash Flows from Operating Activities
A discussion of items pertinent to BGE’s cash flows from operating activities is set forth under Cash Flows from Operating Activities in EXELON
CORPORATION — Liquidity and Capital Resources of this Form 10-K.
Cash Flows from Investing Activities
A discussion of items pertinent to BGE’s cash flows from investing activities is set forth under “Cash Flows from Investing Activities” in EXELON
CORPORATION — Liquidity and Capital Resources of this Form 10-K.
Cash Flows from Financing Activities
A discussion of items pertinent to BGE’s cash flows from financing activities is set forth under “Cash Flows from Financing Activities” in EXELON
CORPORATION — Liquidity and Capital Resources of this Form 10-K.
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Credit Matters
A discussion of credit matters pertinent to BGE is set forth under Credit Matters in EXELON CORPORATION — Liquidity and Capital Resources of this Form
10-K.
Contractual Obligations and Off-Balance Sheet Arrangements
A discussion of BGE’s contractual obligations, commercial commitments, and off-balance sheet arrangements is set forth under Contractual Obligations and
Off-Balance Sheet Arrangements in EXELON CORPORATION — Liquidity and Capital Resources of this Form 10-K.
Critical Accounting Policies and Estimates
See All Registrants — Critical Accounting Policies and Estimates above for a discussion of BGE’s critical accounting policies and estimates.
New Accounting Pronouncements
See Note 1 — Significant Accounting Policies of the Combined Notes to Consolidated Financial Statements for information regarding new accounting
pronouncements.
ITEM 7A.
QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK
BGE
BGE is exposed to market risks associated with credit and interest rates. These risks are described above under Quantitative and Qualitative Disclosures
about Market Risk—Exelon.
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ITEM 7.
MANAGEMENT’S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS
PHI
General
PHI has three reportable segments Pepco, DPL, and ACE. Its operations consist of the purchase and regulated retail sale of electricity and the provision of
distribution and transmission services, and to a lesser extent, the purchase and regulated retail sale and supply of natural gas in Delaware. This segment is
discussed in further detail in ITEM 1. BUSINESS — PHI of this Form 10-K.
Executive Overview
A discussion of items pertinent to PHI’s executive overview is set forth under EXELON CORPORATION — Executive Overview of this Form 10-K.
Results of Operations
Year Ended December 31, 2020 Compared to Year Ended December 31, 2019
A discussion of PHI’s results of operations for 2020 compared to 2019 is set forth under Results of Operations—PHI in EXELON CORPORATION — Results
of Operations of this Form 10-K.
Liquidity and Capital Resources
PHI’s business is capital intensive and requires considerable capital resources. PHI’s capital resources are primarily provided by internally generated cash
flows from operations and, to the extent necessary, external financing, including the issuance of long-term debt or commercial paper, borrowings from the
Exelon money pool, or capital contributions from Exelon. PHI’s access to external financing at reasonable terms is dependent on its credit ratings and
general business conditions, as well as that of the utility industry in general.
See EXELON CORPORATION — Liquidity and Capital Resources and Note 17 — Debt and Credit Agreements of the Combined Notes to Consolidated
Financial Statements of this Form 10-K for additional information.
Capital resources are used primarily to fund PHI’s capital requirements, including construction expenditures, retire debt, pay dividends, fund pension and
OPEB obligations, and invest in new and existing ventures. PHI spends a significant amount of cash on capital improvements and construction projects that
have a long-term return on investment.
Cash Flows from Operating Activities
A discussion of items pertinent to PHI’s cash flows from operating activities is set forth under Cash Flows from Operating Activities in EXELON
CORPORATION — Liquidity and Capital Resources of this Form 10-K.
Cash Flows from Investing Activities
A discussion of items pertinent to PHI’s cash flows from investing activities is set forth under “Cash Flows from Investing Activities” in EXELON
CORPORATION — Liquidity and Capital Resources of this Form 10-K.
Cash Flows from Financing Activities
A discussion of items pertinent to PHI’s cash flows from financing activities is set forth under “Cash Flows from Financing Activities” in EXELON
CORPORATION — Liquidity and Capital Resources of this Form 10-K.
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Credit Matters
A discussion of credit matters pertinent to PHI is set forth under Credit Matters in EXELON CORPORATION — Liquidity and Capital Resources of this Form
10-K.
Contractual Obligations and Off-Balance Sheet Arrangements
A discussion of PHI’s contractual obligations, commercial commitments, and off-balance sheet arrangements is set forth under Contractual Obligations and
Off-Balance Sheet Arrangements in EXELON CORPORATION — Liquidity and Capital Resources of this Form 10-K.
Critical Accounting Policies and Estimates
See All Registrants — Critical Accounting Policies and Estimates above for a discussion of PHI’s critical accounting policies and estimates.
New Accounting Pronouncements
See Note 1 — Significant Accounting Policies of the Combined Notes to Consolidated Financial Statements for information regarding new accounting
pronouncements.
ITEM 7A.
QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK
PHI
PHI is exposed to market risks associated with credit and interest rates. These risks are described above under Quantitative and Qualitative Disclosures
about Market Risk — Exelon.
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ITEM 7.
MANAGEMENT’S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS
Pepco
General
Pepco operates in a single business segment and its operations consist of the purchase and regulated retail sale of electricity and the provision of
distribution and transmission services to retail customers in District of Columbia and major portions of Prince George’s County and Montgomery County in
Maryland. This segment is discussed in further detail in ITEM 1. BUSINESS — Pepco of this Form 10-K.
Executive Overview
A discussion of items pertinent to Pepco’s executive overview is set forth under EXELON CORPORATION — Executive Overview of this Form 10-K.
Results of Operations
Year Ended December 31, 2020 Compared to Year Ended December 31, 2019
A discussion of Pepco’s results of operations for 2020 compared to 2019 is set forth under Results of Operations—Pepco in EXELON CORPORATION —
Results of Operations of this Form 10-K.
Liquidity and Capital Resources
Pepco’s business is capital intensive and requires considerable capital resources. Pepco’s capital resources are primarily provided by internally generated
cash flows from operations and, to the extent necessary, external financing, including the issuance of long-term debt, commercial paper, or credit facility
borrowings. Pepco’s access to external financing at reasonable terms is dependent on its credit ratings and general business conditions, as well as that of
the utility industry in general. At December 31, 2020, Pepco had access to a revolving credit facility with aggregate bank commitments of $300 million.
See EXELON CORPORATION — Liquidity and Capital Resources and Note 17 — Debt and Credit Agreements of the Combined Notes to Consolidated
Financial Statements of this Form 10-K for additional information.
Capital resources are used primarily to fund Pepco’s capital requirements, including construction expenditures, retire debt, pay dividends, fund pension and
OPEB obligations, and invest in new and existing ventures. Pepco spends a significant amount of cash on capital improvements and construction projects
that have a long-term return on investment. Additionally, Pepco operates in rate-regulated environments in which the amount of new investment recovery
may be limited and where such recovery takes place over an extended period of time.
Cash Flows from Operating Activities
A discussion of items pertinent to Pepco’s cash flows from operating activities is set forth under Cash Flows from Operating Activities in EXELON
CORPORATION — Liquidity and Capital Resources of this Form 10-K.
Cash Flows from Investing Activities
A discussion of items pertinent to Pepco’s cash flows from investing activities is set forth under Cash Flows from Investing Activities in EXELON
CORPORATION — Liquidity and Capital Resources of this Form 10-K.
Cash Flows from Financing Activities
A discussion of items pertinent to Pepco’s cash flows from financing activities is set forth under Cash Flows from Financing Activities in EXELON
CORPORATION — Liquidity and Capital Resources of this Form 10-K.
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Credit Matters
A discussion of credit matters pertinent to Pepco is set forth under Credit Matters in EXELON CORPORATION — Liquidity and Capital Resources of this
Form 10-K.
Contractual Obligations and Off-Balance Sheet Arrangements
A discussion of Pepco’s contractual obligations, commercial commitments, and off-balance sheet arrangements is set forth under Contractual Obligations
and Off-Balance Sheet Arrangements in EXELON CORPORATION — Liquidity and Capital Resources of this Form 10-K.
Critical Accounting Policies and Estimates
See All Registrants — Critical Accounting Policies and Estimates above for a discussion of Pepco’s critical accounting policies and estimates.
New Accounting Pronouncements
See Note 1 — Significant Accounting Policies of the Combined Notes to Consolidated Financial Statements for information regarding new accounting
pronouncements.
ITEM 7A.
QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK
Pepco
Pepco is exposed to market risks associated with credit and interest rates. These risks are described above under Quantitative and Qualitative Disclosures
about Market Risk— Exelon.
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ITEM 7.
MANAGEMENT’S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS
DPL
General
DPL operates in a single business segment and its operations consist of the purchase and regulated retail sale of electricity and the provision of distribution
and transmission services in portions of Maryland and Delaware, and the purchase and regulated retail sale and supply of natural gas in New Castle County,
Delaware. This segment is discussed in further detail in ITEM 1. BUSINESS — DPL of this Form 10-K.
Executive Overview
A discussion of items pertinent to DPL’s executive overview is set forth under EXELON CORPORATION — Executive Overview of this Form 10-K.
Results of Operations
Year Ended December 31, 2020 Compared to Year Ended December 31, 2019
A discussion of DPL’s results of operations for 2020 compared to 2019 is set forth under Results of Operations—DPL in EXELON CORPORATION —
Results of Operations of this Form 10-K.
Liquidity and Capital Resources
DPL’s business is capital intensive and requires considerable capital resources. DPL’s capital resources are primarily provided by internally generated cash
flows from operations and, to the extent necessary, external financing, including the issuance of long-term debt or commercial paper. DPL’s access to
external financing at reasonable terms is dependent on its credit ratings and general business conditions, as well as that of the utility industry in general. If
these conditions deteriorate to where DPL no longer has access to the capital markets at reasonable terms, DPL has access to a revolving credit facility. At
December 31, 2020, DPL had access to a revolving credit facility with aggregate bank commitments of $300 million.
See EXELON CORPORATION — Liquidity and Capital Resources and Note 17 — Debt and Credit Agreements of the Combined Notes to Consolidated
Financial Statements of this Form 10-K for additional information.
Capital resources are used primarily to fund DPL’s capital requirements, including construction expenditures, retire debt, pay dividends, fund pension and
OPEB obligations, and invest in new and existing ventures. DPL spends a significant amount of cash on capital improvements and construction projects that
have a long-term return on investment. Additionally, DPL operates in a rate-regulated environment in which the amount of new investment recovery may be
limited and where such recovery takes place over an extended period of time.
Cash Flows from Operating Activities
A discussion of items pertinent to DPL’s cash flows from operating activities is set forth under Cash Flows from Operating Activities in EXELON
CORPORATION — Liquidity and Capital Resources of this Form 10-K.
Cash Flows from Investing Activities
A discussion of items pertinent to DPL’s cash flows from investing activities is set forth under Cash Flows from Investing Activities in EXELON
CORPORATION — Liquidity and Capital Resources of this Form 10-K.
Cash Flows from Financing Activities
A discussion of items pertinent to DPL’s cash flows from financing activities is set forth under Cash Flows from Financing Activities in EXELON
CORPORATION — Liquidity and Capital Resources of this Form 10-K.
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Credit Matters
A discussion of credit matters pertinent to DPL is set forth under Credit Matters in EXELON CORPORATION — Liquidity and Capital Resources of this Form
10-K.
Contractual Obligations and Off-Balance Sheet Arrangements
A discussion of DPL’s contractual obligations, commercial commitments, and off-balance sheet arrangements is set forth under Contractual Obligations and
Off-Balance Sheet Arrangements in EXELON CORPORATION — Liquidity and Capital Resources of this Form 10-K.
Critical Accounting Policies and Estimates
See All Registrants — Critical Accounting Policies and Estimates above for a discussion of DPL’s critical accounting policies and estimates.
New Accounting Pronouncements
See Note 1 — Significant Accounting Policies of the Combined Notes to Consolidated Financial Statements for information regarding new accounting
pronouncements.
ITEM 7A.
QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK
DPL
DPL is exposed to market risks associated with credit and interest rates. These risks are described above under Quantitative and Qualitative Disclosures
about Market Risk—Exelon.
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ITEM 7.
MANAGEMENT’S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS
ACE
General
ACE operates in a single business segment and its operations consist of the purchase and regulated retail sale of electricity and the provision of distribution
and transmission services to retail customers in portions of southern New Jersey. This segment is discussed in further detail in ITEM 1. BUSINESS — ACE
of this Form 10-K.
Executive Overview
A discussion of items pertinent to ACE’s executive overview is set forth under EXELON CORPORATION — Executive Overview of this Form 10-K.
Results of Operations
Year Ended December 31, 2020 Compared to Year Ended December 31, 2019
A discussion of ACE’s results of operations for 2020 compared to 2019 is set forth under Results of Operations—ACE in EXELON CORPORATION —
Results of Operations of this Form 10-K.
Liquidity and Capital Resources
ACE’s business is capital intensive and requires considerable capital resources. ACE’s capital resources are primarily provided by internally generated cash
flows from operations and, to the extent necessary, external financing, including the issuance of long-term debt, commercial paper, or credit facility
borrowings. ACE’s access to external financing at reasonable terms is dependent on its credit ratings and general business conditions, as well as that of the
utility industry in general. At December 31, 2020, ACE had access to a revolving credit facility with aggregate bank commitments of $300 million.
See EXELON CORPORATION — Liquidity and Capital Resources and Note 17 — Debt and Credit Agreements of the Combined Notes to Consolidated
Financial Statements of this Form 10-K for additional information.
Capital resources are used primarily to fund ACE’s capital requirements, including construction expenditures, retire debt, pay dividends, fund pension and
OPEB obligations, and invest in new and existing ventures. ACE spends a significant amount of cash on capital improvements and construction projects that
have a long-term return on investment. Additionally, ACE operates in rate-regulated environments in which the amount of new investment recovery may be
limited and where such recovery takes place over an extended period of time.
Cash Flows from Operating Activities
A discussion of items pertinent to ACE’s cash flows from operating activities is set forth under Cash Flows from Operating Activities in EXELON
CORPORATION — Liquidity and Capital Resources of this Form 10-K.
Cash Flows from Investing Activities
A discussion of items pertinent to ACE’s cash flows from investing activities is set forth under Cash Flows from Investing Activities in EXELON
CORPORATION — Liquidity and Capital Resources of this Form 10-K.
Cash Flows from Financing Activities
A discussion of items pertinent to ACE’s cash flows from financing activities is set forth under Cash Flows from Financing Activities in EXELON
CORPORATION — Liquidity and Capital Resources of this Form 10-K.
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Credit Matters
A discussion of credit matters pertinent to ACE is set forth under Credit Matters in EXELON CORPORATION — Liquidity and Capital Resources of this Form
10-K.
Contractual Obligations and Off-Balance Sheet Arrangements
A discussion of ACE’s contractual obligations, commercial commitments, and off-balance sheet arrangements is set forth under Contractual Obligations and
Off-Balance Sheet Arrangements in EXELON CORPORATION — Liquidity and Capital Resources of this Form 10-K.
Critical Accounting Policies and Estimates
See All Registrants — Critical Accounting Policies and Estimates above for a discussion of ACE’s critical accounting policies and estimates.
New Accounting Pronouncements
See Note 1 — Significant Accounting Policies of the Combined Notes to Consolidated Financial Statements for information regarding new accounting
pronouncements.
ITEM 7A.
QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK
ACE
ACE is exposed to market risks associated with credit and interest rates. These risks are described above under Quantitative and Qualitative Disclosures
about Market Risk— Exelon.
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ITEM 8.
FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA
Management’s Report on Internal Control Over Financial Reporting
The management of Exelon Corporation (Exelon) is responsible for establishing and maintaining adequate internal control over financial reporting, as such
term is defined in Exchange Act Rule 13a-15(f). Internal control over financial reporting is a process designed to provide reasonable assurance regarding the
reliability of financial reporting and the preparation of financial statements for external purposes in accordance with generally accepted accounting principles.
Because of its inherent limitations, internal control over financial reporting may not prevent or detect misstatements. Also, projections of any evaluation of
effectiveness to future periods are subject to the risk that controls may become inadequate because of changes in conditions, or that the degree of
compliance with the policies or procedures may deteriorate.
Exelon’s management conducted an assessment of the effectiveness of Exelon’s internal control over financial reporting as of December 31, 2020. In
making this assessment, management used the criteria in Internal Control—Integrated Framework (2013) issued by the Committee of Sponsoring
Organizations of the Treadway Commission. Based on this assessment, Exelon’s management concluded that, as of December 31, 2020, Exelon’s internal
control over financial reporting was effective.
The effectiveness of Exelon’s internal control over financial reporting as of December 31, 2020, has been audited by PricewaterhouseCoopers LLP, an
independent registered public accounting firm, as stated in their report which appears herein.
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Management’s Report on Internal Control Over Financial Reporting
The management of Exelon Generation Company, LLC (Generation) is responsible for establishing and maintaining adequate internal control over financial
reporting, as such term is defined in Exchange Act Rule 13a-15(f). Internal control over financial reporting is a process designed to provide reasonable
assurance regarding the reliability of financial reporting and the preparation of financial statements for external purposes in accordance with generally
accepted accounting principles.
Because of its inherent limitations, internal control over financial reporting may not prevent or detect misstatements. Also, projections of any evaluation of
effectiveness to future periods are subject to the risk that controls may become inadequate because of changes in conditions, or that the degree of
compliance with the policies or procedures may deteriorate.
Generation’s management conducted an assessment of the effectiveness of Generation’s internal control over financial reporting as of December 31, 2020.
In making this assessment, management used the criteria in Internal Control—Integrated Framework (2013) issued by the Committee of Sponsoring
Organizations of the Treadway Commission. Based on this assessment, Generation’s management concluded that, as of December 31, 2020, Generation’s
internal control over financial reporting was effective.
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Management’s Report on Internal Control Over Financial Reporting
The management of Commonwealth Edison Company (ComEd) is responsible for establishing and maintaining adequate internal control over financial
reporting, as such term is defined in Exchange Act Rule 13a-15(f). Internal control over financial reporting is a process designed to provide reasonable
assurance regarding the reliability of financial reporting and the preparation of financial statements for external purposes in accordance with generally
accepted accounting principles.
Because of its inherent limitations, internal control over financial reporting may not prevent or detect misstatements. Also, projections of any evaluation of
effectiveness to future periods are subject to the risk that controls may become inadequate because of changes in conditions, or that the degree of
compliance with the policies or procedures may deteriorate.
ComEd’s management conducted an assessment of the effectiveness of ComEd’s internal control over financial reporting as of December 31, 2020. In
making this assessment, management used the criteria in Internal Control—Integrated Framework (2013) issued by the Committee of Sponsoring
Organizations of the Treadway Commission. Based on this assessment, ComEd’s management concluded that, as of December 31, 2020, ComEd’s internal
control over financial reporting was effective.
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Management’s Report on Internal Control Over Financial Reporting
The management of PECO Energy Company (PECO) is responsible for establishing and maintaining adequate internal control over financial reporting, as
such term is defined in Exchange Act Rule 13a-15(f). Internal control over financial reporting is a process designed to provide reasonable assurance
regarding the reliability of financial reporting and the preparation of financial statements for external purposes in accordance with generally accepted
accounting principles.
Because of its inherent limitations, internal control over financial reporting may not prevent or detect misstatements. Also, projections of any evaluation of
effectiveness to future periods are subject to the risk that controls may become inadequate because of changes in conditions, or that the degree of
compliance with the policies or procedures may deteriorate.
PECO’s management conducted an assessment of the effectiveness of PECO’s internal control over financial reporting as of December 31, 2020. In making
this assessment, management used the criteria in Internal Control—Integrated Framework (2013) issued by the Committee of Sponsoring Organizations of
the Treadway Commission. Based on this assessment, PECO’s management concluded that, as of December 31, 2020, PECO’s internal control over
financial reporting was effective.
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Management’s Report on Internal Control Over Financial Reporting
The management of Baltimore Gas and Electric Company (BGE) is responsible for establishing and maintaining adequate internal control over financial
reporting, as such term is defined in Exchange Act Rule 13a-15(f). Internal control over financial reporting is a process designed to provide reasonable
assurance regarding the reliability of financial reporting and the preparation of financial statements for external purposes in accordance with generally
accepted accounting principles.
Because of its inherent limitations, internal control over financial reporting may not prevent or detect misstatements. Also, projections of any evaluation of
effectiveness to future periods are subject to the risk that controls may become inadequate because of changes in conditions, or that the degree of
compliance with the policies or procedures may deteriorate.
BGE’s management conducted an assessment of the effectiveness of BGE’s internal control over financial reporting as of December 31, 2020. In making
this assessment, management used the criteria in Internal Control—Integrated Framework (2013) issued by the Committee of Sponsoring Organizations of
the Treadway Commission. Based on this assessment, BGE’s management concluded that, as of December 31, 2020, BGE’s internal control over financial
reporting was effective.
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Management’s Report on Internal Control Over Financial Reporting
The management of Pepco Holdings LLC (PHI) is responsible for establishing and maintaining adequate internal control over financial reporting, as such
term is defined in Exchange Act Rule 13a-15(f). Internal control over financial reporting is a process designed to provide reasonable assurance regarding the
reliability of financial reporting and the preparation of financial statements for external purposes in accordance with generally accepted accounting principles.
Because of its inherent limitations, internal control over financial reporting may not prevent or detect misstatements. Also, projections of any evaluation of
effectiveness to future periods are subject to the risk that controls may become inadequate because of changes in conditions, or that the degree of
compliance with the policies or procedures may deteriorate.
PHI’s management conducted an assessment of the effectiveness of PHI’s internal control over financial reporting as of December 31, 2020. In making this
assessment, management used the criteria in Internal Control—Integrated Framework (2013) issued by the Committee of Sponsoring Organizations of the
Treadway Commission. Based on this assessment, PHI’s management concluded that, as of December 31, 2020, PHI’s internal control over financial
reporting was effective.
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Management’s Report on Internal Control Over Financial Reporting
The management of Potomac Electric Power Company (Pepco) is responsible for establishing and maintaining adequate internal control over financial
reporting, as such term is defined in Exchange Act Rule 13a-15(f). Internal control over financial reporting is a process designed to provide reasonable
assurance regarding the reliability of financial reporting and the preparation of financial statements for external purposes in accordance with generally
accepted accounting principles.
Because of its inherent limitations, internal control over financial reporting may not prevent or detect misstatements. Also, projections of any evaluation of
effectiveness to future periods are subject to the risk that controls may become inadequate because of changes in conditions, or that the degree of
compliance with the policies or procedures may deteriorate.
Pepco’s management conducted an assessment of the effectiveness of Pepco’s internal control over financial reporting as of December 31, 2020. In making
this assessment, management used the criteria in Internal Control—Integrated Framework (2013) issued by the Committee of Sponsoring Organizations of
the Treadway Commission. Based on this assessment, Pepco’s management concluded that, as of December 31, 2020, Pepco’s internal control over
financial reporting was effective.
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Management’s Report on Internal Control Over Financial Reporting
The management of Delmarva Power & Light Company (DPL) is responsible for establishing and maintaining adequate internal control over financial
reporting, as such term is defined in Exchange Act Rule 13a-15(f). Internal control over financial reporting is a process designed to provide reasonable
assurance regarding the reliability of financial reporting and the preparation of financial statements for external purposes in accordance with generally
accepted accounting principles.
Because of its inherent limitations, internal control over financial reporting may not prevent or detect misstatements. Also, projections of any evaluation of
effectiveness to future periods are subject to the risk that controls may become inadequate because of changes in conditions, or that the degree of
compliance with the policies or procedures may deteriorate.
DPL’s management conducted an assessment of the effectiveness of DPL’s internal control over financial reporting as of December 31, 2020. In making this
assessment, management used the criteria in Internal Control—Integrated Framework (2013) issued by the Committee of Sponsoring Organizations of the
Treadway Commission. Based on this assessment, DPL’s management concluded that, as of December 31, 2020, DPL’s internal control over financial
reporting was effective.
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Management’s Report on Internal Control Over Financial Reporting
The management of Atlantic City Electric Company (ACE) is responsible for establishing and maintaining adequate internal control over financial reporting,
as such term is defined in Exchange Act Rule 13a-15(f). Internal control over financial reporting is a process designed to provide reasonable assurance
regarding the reliability of financial reporting and the preparation of financial statements for external purposes in accordance with generally accepted
accounting principles.
Because of its inherent limitations, internal control over financial reporting may not prevent or detect misstatements. Also, projections of any evaluation of
effectiveness to future periods are subject to the risk that controls may become inadequate because of changes in conditions, or that the degree of
compliance with the policies or procedures may deteriorate.
ACE’s management conducted an assessment of the effectiveness of ACE’s internal control over financial reporting as of December 31, 2020. In making this
assessment, management used the criteria in Internal Control—Integrated Framework (2013) issued by the Committee of Sponsoring Organizations of the
Treadway Commission. Based on this assessment, ACE’s management concluded that, as of December 31, 2020, ACE’s internal control over financial
reporting was effective.
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Report of Independent Registered Public Accounting Firm
To the Board of Directors and Shareholders of Exelon Corporation
Opinions on the Financial Statements and Internal Control over Financial Reporting
We have audited the consolidated financial statements, including the related notes, as listed in the index appearing under Item 15(a)(1)(i), and the financial
statement schedules listed in the index appearing under Item 15(a)(1)(ii), of Exelon Corporation and its subsidiaries (the “Company”) (collectively referred to
as the “consolidated financial statements”). We also have audited the Company's internal control over financial reporting as of December 31, 2020, based on
criteria established in Internal Control - Integrated Framework (2013) issued by the Committee of Sponsoring Organizations of the Treadway Commission
(COSO).
In our opinion, the consolidated financial statements referred to above present fairly, in all material respects, the financial position of the Company as of
December 31, 2020 and 2019, and the results of its operations and its cash flows for each of the three years in the period ended December 31, 2020 in
conformity with accounting principles generally accepted in the United States of America. Also in our opinion, the Company maintained, in all material
respects, effective internal control over financial reporting as of December 31, 2020, based on criteria established in Internal Control - Integrated Framework
(2013) issued by the COSO.
Change in Accounting Principle
As discussed in Note 1 to the consolidated financial statements, the Company changed the manner in which it accounts for leases in 2019.
Basis for Opinions
The Company's management is responsible for these consolidated financial statements, for maintaining effective internal control over financial reporting, and
for its assessment of the effectiveness of internal control over financial reporting, included in Management’s Report on Internal Control Over Financial
Reporting appearing under Item 8. Our responsibility is to express opinions on the Company’s consolidated financial statements and on the Company's
internal control over financial reporting based on our audits. We are a public accounting firm registered with the Public Company Accounting Oversight Board
(United States) (PCAOB) and are required to be independent with respect to the Company in accordance with the U.S. federal securities laws and the
applicable rules and regulations of the Securities and Exchange Commission and the PCAOB.
We conducted our audits in accordance with the standards of the PCAOB. Those standards require that we plan and perform the audits to obtain reasonable
assurance about whether the consolidated financial statements are free of material misstatement, whether due to error or fraud, and whether effective
internal control over financial reporting was maintained in all material respects.
Our audits of the consolidated financial statements included performing procedures to assess the risks of material misstatement of the consolidated financial
statements, whether due to error or fraud, and performing procedures that respond to those risks. Such procedures included examining, on a test basis,
evidence regarding the amounts and disclosures in the consolidated financial statements. Our audits also included evaluating the accounting principles used
and significant estimates made by management, as well as evaluating the overall presentation of the consolidated financial statements. Our audit of internal
control over financial reporting included obtaining an understanding of internal control over financial reporting, assessing the risk that a material weakness
exists, and testing and evaluating the design and operating effectiveness of internal control based on the assessed risk. Our audits also included performing
such other procedures as we considered necessary in the circumstances. We believe that our audits provide a reasonable basis for our opinions.
Definition and Limitations of Internal Control over Financial Reporting
A company’s internal control over financial reporting is a process designed to provide reasonable assurance regarding the reliability of financial reporting and
the preparation of financial statements for external purposes in accordance with generally accepted accounting principles. A company’s internal control over
financial reporting includes those policies and procedures that (i) pertain to the maintenance of records that, in reasonable detail, accurately and fairly reflect
the transactions and dispositions of the assets of the company; (ii) provide reasonable assurance that transactions are recorded as necessary to permit
preparation of financial statements in accordance with generally accepted accounting principles, and that receipts and expenditures of the company
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are being made only in accordance with authorizations of management and directors of the company; and (iii) provide reasonable assurance regarding
prevention or timely detection of unauthorized acquisition, use, or disposition of the company’s assets that could have a material effect on the financial
statements.
Because of its inherent limitations, internal control over financial reporting may not prevent or detect misstatements. Also, projections of any evaluation of
effectiveness to future periods are subject to the risk that controls may become inadequate because of changes in conditions, or that the degree of
compliance with the policies or procedures may deteriorate.
Critical Audit Matters
The critical audit matters communicated below are matters arising from the current period audit of the consolidated financial statements that were
communicated or required to be communicated to the audit committee and that (i) relate to accounts or disclosures that are material to the consolidated
financial statements and (ii) involved our especially challenging, subjective, or complex judgments. The communication of critical audit matters does not alter
in any way our opinion on the consolidated financial statements, taken as a whole, and we are not, by communicating the critical audit matters below,
providing separate opinions on the critical audit matters or on the accounts or disclosures to which they relate.
Annual Nuclear Decommissioning Asset Retirement Obligations (ARO) Assessment
As described in Notes 1 and 10 to the consolidated financial statements, the Company has a legal obligation to decommission its nuclear generation stations
following the expiration of their operating licenses. To estimate its decommissioning obligation related to its nuclear generating stations for financial
accounting and reporting purposes, management uses a probability-weighted cash flow model, which on a unit-by-unit basis, considers multiple scenarios
that include significant estimates and assumptions such as decommissioning cost studies, cost escalation rates, probabilistic cash flow models and discount
rates. Management 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. As of December 31, 2020, the nuclear decommissioning ARO
was approximately $11.9 billion.
The principal considerations for our determination that performing procedures relating to the Company’s annual ARO assessment is a critical audit matter
are the significant judgment by management when estimating its decommissioning obligation; this in turn led to a high degree of auditor judgment,
subjectivity, and effort in performing procedures and evaluating the reasonableness of management’s cash flow model and significant assumptions related to
decommissioning cost studies. In addition, the audit effort involved the use of professionals with specialized skill and knowledge.
Addressing the matter involved performing procedures and evaluating audit evidence in connection with forming our overall opinion on the consolidated
financial statements. These procedures included testing the effectiveness of controls relating to management’s development of the inputs, assumptions, and
model used in management’s ARO assessment. These procedures also included, among others, testing management’s process for developing the ARO
estimates by evaluating the appropriateness of the cash flow model, testing the completeness and accuracy of data used by management, and evaluating
the reasonableness of management’s significant assumptions related to decommissioning cost studies. Professionals with specialized skill and knowledge
were used to assist in evaluating the results of decommissioning cost studies.
Impairment Assessment of Long-Lived Generation Assets
As described in Notes 1 and 12 to the consolidated financial statements, the Company evaluates 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, or plans to dispose of
a long-lived asset significantly before the end of its useful life. Management determines if long-lived assets and 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 expected future cash flows include significant unobservable inputs including revenue and generation forecasts, projected capital and
maintenance expenditures and discount rates. As of December 31, 2020, the total carrying value of long-lived generation assets subject to this evaluation
was approximately $22.2 billion.
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The principal considerations for our determination that performing procedures relating to the Company’s impairment assessment of long-lived generation
assets is a critical audit matter are the significant judgment by management in assessing the recoverability of these asset groups; this in turn led to a high
degree of auditor judgment, subjectivity and effort in performing procedures and evaluating the reasonableness of management’s significant assumptions
related to revenue and generation forecasts. In addition, the audit effort involved the use of professionals with specialized skill and knowledge.
Addressing the matter involved performing procedures and evaluating audit evidence in connection with forming our overall opinion on the consolidated
financial statements. These procedures included testing the effectiveness of controls relating to management’s development of the inputs, assumptions, and
model used to estimate the recoverability and fair value of the Company’s long-lived generation asset groups. These procedures also included, among
others, testing management’s process for developing expected future cash flows for long-lived generation asset groups by evaluating the appropriateness of
the future cash flow model, testing the completeness and accuracy of the data used by management, and evaluating the reasonableness of management’s
significant assumptions related to revenue and generation forecasts. Professionals with specialized skill and knowledge were used to assist in evaluating the
reasonableness of revenue forecasts.
Accounting for the Effects of Rate Regulation
As described in Notes 1 and 3 to the consolidated financial statements, the Company applies the authoritative guidance for accounting for certain types of
regulation, which requires management to record in their consolidated financial statements the effects of cost-based rate regulation for entities with regulated
operations that meet the following criteria, (i) rates are established or approved by a third-party regulator; (ii) rates are designed to recover the entity’s cost of
providing services or products; and (iii) there is a reasonable expectation that rates designed to recover costs can be charged to and collected from
customers. The Company accounts for its regulated operations in accordance with regulatory and legislative guidance from the regulatory authorities having
jurisdiction under state public utility laws and the FERC under various Federal laws. Upon updates in material regulatory and legislative proceedings, where
applicable, management will record new regulatory assets or liabilities and will assess whether it is probable that its currently recorded regulatory assets and
liabilities will be recovered and settled, respectively, in future rates. As of December 31, 2020, there were approximately $10.0 billion of regulatory assets
and approximately $10.1 billion of regulatory liabilities.
The principal considerations for our determination that performing procedures relating to management’s accounting for the effects of rate regulation is a
critical audit matter are the high degree of audit effort to assess the impact of regulation on accounting for regulatory assets and liabilities and to evaluate the
complex audit evidence related to whether the regulatory assets and liabilities will be recovered and settled.
Addressing the matter involved performing procedures and evaluating audit evidence in connection with forming our overall opinion on the consolidated
financial statements. These procedures included testing the effectiveness of controls relating to accounting for regulatory matters and evaluation of existing
regulatory assets and liabilities. These procedures also included, among others, obtaining the Company’s correspondence with regulators, evaluating the
reasonableness of management’s judgments regarding regulatory guidance and proceedings and the related accounting implications, and calculating
regulatory assets and liabilities based on provisions outlined in rate orders and other correspondence with regulators.
/s/ PricewaterhouseCoopers LLP
Chicago, Illinois
February 24, 2021
We have served as the Company’s auditor since 2000.
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Report of Independent Registered Public Accounting Firm
To the Board of Directors and Member of Exelon Generation Company, LLC
Opinion on the Financial Statements
We have audited the consolidated financial statements, including the related notes, as listed in the index appearing under Item 15(a)(2)(i), and the financial
statement schedule listed in the index appearing under Item 15(a)(2)(ii), of Exelon Generation Company, LLC and its subsidiaries (the “Company”)
(collectively referred to as the “consolidated financial statements”). In our opinion, the consolidated financial statements present fairly, in all material
respects, the financial position of the Company as of December 31, 2020 and 2019, and the results of its operations and its cash flows for each of the three
years in the period ended December 31, 2020 in conformity with accounting principles generally accepted in the United States of America.
Change in Accounting Principle
As discussed in Note 1 to the consolidated financial statements, the Company changed the manner in which it accounts for leases in 2019.
Basis for Opinion
These consolidated financial statements are the responsibility of the Company’s management. Our responsibility is to express an opinion on the Company’s
consolidated financial statements based on our audits. We are a public accounting firm registered with the Public Company Accounting Oversight Board
(United States) (PCAOB) and are required to be independent with respect to the Company in accordance with the U.S. federal securities laws and the
applicable rules and regulations of the Securities and Exchange Commission and the PCAOB.
We conducted our audits of these consolidated financial statements in accordance with the standards of the PCAOB. Those standards require that we plan
and perform the audit to obtain reasonable assurance about whether the consolidated financial statements are free of material misstatement, whether due to
error or fraud. The Company is not required to have, nor were we engaged to perform, an audit of its internal control over financial reporting. As part of our
audits we are required to obtain an understanding of internal control over financial reporting but not for the purpose of expressing an opinion on the
effectiveness of the Company's internal control over financial reporting. Accordingly, we express no such opinion.
Our audits included performing procedures to assess the risks of material misstatement of the consolidated financial statements, whether due to error or
fraud, and performing procedures that respond to those risks. Such procedures included examining, on a test basis, evidence regarding the amounts and
disclosures in the consolidated financial statements. Our audits also included evaluating the accounting principles used and significant estimates made by
management, as well as evaluating the overall presentation of the consolidated financial statements. We believe that our audits provide a reasonable basis
for our opinion.
Critical Audit Matters
The critical audit matters communicated below are matters arising from the current period audit of the consolidated financial statements that were
communicated or required to be communicated to the audit committee and that (i) relate to accounts or disclosures that are material to the consolidated
financial statements and (ii) involved our especially challenging, subjective, or complex judgments. The communication of critical audit matters does not alter
in any way our opinion on the consolidated financial statements, taken as a whole, and we are not, by communicating the critical audit matters below,
providing separate opinions on the critical audit matters or on the accounts or disclosures to which they relate.
Annual Nuclear Decommissioning Asset Retirement Obligations (ARO) Assessment
As described in Notes 1 and 10 to the consolidated financial statements, the Company has a legal obligation to decommission its nuclear generation stations
following the expiration of their operating licenses. To estimate its decommissioning obligation related to its nuclear generating stations for financial
accounting and reporting purposes, management uses a probability-weighted cash flow model, which on a unit-by-unit basis, considers multiple scenarios
that include significant estimates and assumptions such as decommissioning cost studies, cost escalation rates, probabilistic cash flow models and discount
rates. Management updates its ARO annually
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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. As of December 31, 2020, the nuclear decommissioning ARO was approximately $11.9 billion.
The principal considerations for our determination that performing procedures relating to the Company’s annual ARO assessment is a critical audit matter
are the significant judgment by management when estimating its decommissioning obligation; this in turn led to a high degree of auditor judgment,
subjectivity, and effort in performing procedures and evaluating the reasonableness of management’s cash flow model and significant assumptions related to
decommissioning cost studies. In addition, the audit effort involved the use of professionals with specialized skill and knowledge.
Addressing the matter involved performing procedures and evaluating audit evidence in connection with forming our overall opinion on the consolidated
financial statements. These procedures included testing the effectiveness of controls relating to management’s development of the inputs, assumptions, and
model used in management’s ARO assessment. These procedures also included, among others, testing management’s process for developing the ARO
estimates by evaluating the appropriateness of the cash flow model, testing the completeness and accuracy of data used by management, and evaluating
the reasonableness of management’s significant assumptions related to decommissioning cost studies. Professionals with specialized skill and knowledge
were used to assist in evaluating the results of decommissioning cost studies.
Impairment Assessment of Long-Lived Generation Assets
As described in Notes 1 and 12 to the consolidated financial statements, the Company evaluates 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, or plans to dispose of
a long-lived asset significantly before the end of its useful life. Management determines if long-lived assets and 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 expected future cash flows include significant unobservable inputs including revenue and generation forecasts, projected capital and
maintenance expenditures and discount rates. As of December 31, 2020, the total carrying value of long-lived generation assets subject to this evaluation
was approximately $22.2 billion.
The principal considerations for our determination that performing procedures relating to the Company’s impairment assessment of long-lived generation
assets is a critical audit matter are the significant judgment by management in assessing the recoverability of these asset groups; this in turn led to a high
degree of auditor judgment, subjectivity and effort in performing procedures and evaluating the reasonableness of management’s significant assumptions
related to revenue and generation forecasts. In addition, the audit effort involved the use of professionals with specialized skill and knowledge.
Addressing the matter involved performing procedures and evaluating audit evidence in connection with forming our overall opinion on the consolidated
financial statements. These procedures included testing the effectiveness of controls relating to management’s development of the inputs, assumptions, and
model used to estimate the recoverability and fair value of the Company’s long-lived generation asset groups. These procedures also included, among
others, testing management’s process for developing expected future cash flows for long-lived generation asset groups by evaluating the appropriateness of
the future cash flow model, testing the completeness and accuracy of the data used by management, and evaluating the reasonableness of management’s
significant assumptions related to revenue and generation forecasts. Professionals with specialized skill and knowledge were used to assist in evaluating the
reasonableness of revenue forecasts.
/s/ PricewaterhouseCoopers LLP
Baltimore, Maryland
February 24, 2021
We have served as the Company's auditor since 2001.
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Report of Independent Registered Public Accounting Firm
To the Board of Directors and Shareholders of Commonwealth Edison Company
Opinion on the Financial Statements
We have audited the consolidated financial statements, including the related notes, as listed in the index appearing under Item 15(a)(3)(i), and the financial
statement schedule listed in the index appearing under Item 15(a)(3)(ii), of Commonwealth Edison Company and its subsidiaries (the “Company”)
(collectively referred to as the “consolidated financial statements”). In our opinion, the consolidated financial statements present fairly, in all material
respects, the financial position of the Company as of December 31, 2020 and 2019, and the results of its operations and its cash flows for each of the three
years in the period ended December 31, 2020 in conformity with accounting principles generally accepted in the United States of America.
Basis for Opinion
These consolidated financial statements are the responsibility of the Company’s management. Our responsibility is to express an opinion on the Company’s
consolidated financial statements based on our audits. We are a public accounting firm registered with the Public Company Accounting Oversight Board
(United States) (PCAOB) and are required to be independent with respect to the Company in accordance with the U.S. federal securities laws and the
applicable rules and regulations of the Securities and Exchange Commission and the PCAOB.
We conducted our audits of these consolidated financial statements in accordance with the standards of the PCAOB. Those standards require that we plan
and perform the audit to obtain reasonable assurance about whether the consolidated financial statements are free of material misstatement, whether due to
error or fraud. The Company is not required to have, nor were we engaged to perform, an audit of its internal control over financial reporting. As part of our
audits we are required to obtain an understanding of internal control over financial reporting but not for the purpose of expressing an opinion on the
effectiveness of the Company's internal control over financial reporting. Accordingly, we express no such opinion.
Our audits included performing procedures to assess the risks of material misstatement of the consolidated financial statements, whether due to error or
fraud, and performing procedures that respond to those risks. Such procedures included examining, on a test basis, evidence regarding the amounts and
disclosures in the consolidated financial statements. Our audits also included evaluating the accounting principles used and significant estimates made by
management, as well as evaluating the overall presentation of the consolidated financial statements. We believe that our audits provide a reasonable basis
for our opinion.
Critical Audit Matters
The critical audit matter communicated below is a matter arising from the current period audit of the consolidated financial statements that was
communicated or required to be communicated to the audit committee and that (i) relates to accounts or disclosures that are material to the consolidated
financial statements and (ii) involved our especially challenging, subjective, or complex judgments. The communication of critical audit matters does not alter
in any way our opinion on the consolidated financial statements, taken as a whole, and we are not, by communicating the critical audit matter below,
providing a separate opinion on the critical audit matter or on the accounts or disclosures to which it relates.
Accounting for the Effects of Rate Regulation
As described in Notes 1 and 3 to the consolidated financial statements, the Company applies the authoritative guidance for accounting for certain types of
regulation, which requires management to record in their consolidated financial statements the effects of cost-based rate regulation for entities with regulated
operations that meet the following criteria, (i) rates are established or approved by a third-party regulator; (ii) rates are designed to recover the entity’s cost of
providing services or products; and (iii) there is a reasonable expectation that rates designed to recover costs can be charged to and collected from
customers. The Company accounts for its regulated operations in accordance with regulatory and legislative guidance from the regulatory authorities having
jurisdiction under state public utility laws and the FERC under various Federal laws. Upon updates in material regulatory and legislative proceedings, where
applicable, management will record new regulatory assets or liabilities and will assess whether it is probable that its currently recorded regulatory assets and
liabilities will
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be recovered and settled, respectively, in future rates. As of December 31, 2020, there were approximately $2.0 billion of regulatory assets and
approximately $6.7 billion of regulatory liabilities.
The principal considerations for our determination that performing procedures relating to management’s accounting for the effects of rate regulation is a
critical audit matter are the high degree of audit effort to assess the impact of regulation on accounting for regulatory assets and liabilities and to evaluate the
complex audit evidence related to whether the regulatory assets and liabilities will be recovered and settled.
Addressing the matter involved performing procedures and evaluating audit evidence in connection with forming our overall opinion on the consolidated
financial statements. These procedures included testing the effectiveness of controls relating to accounting for regulatory matters and evaluation of existing
regulatory assets and liabilities. These procedures also included, among others, obtaining the Company’s correspondence with regulators, evaluating the
reasonableness of management’s judgments regarding regulatory guidance and proceedings and the related accounting implications, and calculating
regulatory assets and liabilities based on provisions outlined in rate orders and other correspondence with regulators.
/s/ PricewaterhouseCoopers LLP
Chicago, Illinois
February 24, 2021
We have served as the Company's auditor since 2000.
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Report of Independent Registered Public Accounting Firm
To the Board of Directors and Shareholder of PECO Energy Company
Opinion on the Financial Statements
We have audited the consolidated financial statements, including the related notes, as listed in the index appearing under Item 15(a)(4)(i), and the financial
statement schedule listed in the index appearing under Item 15(a)(4)(ii), of PECO Energy Company and its subsidiaries (the “Company”) (collectively
referred to as the “consolidated financial statements”). In our opinion, the consolidated financial statements present fairly, in all material respects, the
financial position of the Company as of December 31, 2020 and 2019, and the results of its operations and its cash flows for each of the three years in the
period ended December 31, 2020 in conformity with accounting principles generally accepted in the United States of America.
Basis for Opinion
These consolidated financial statements are the responsibility of the Company’s management. Our responsibility is to express an opinion on the Company’s
consolidated financial statements based on our audits. We are a public accounting firm registered with the Public Company Accounting Oversight Board
(United States) (PCAOB) and are required to be independent with respect to the Company in accordance with the U.S. federal securities laws and the
applicable rules and regulations of the Securities and Exchange Commission and the PCAOB.
We conducted our audits of these consolidated financial statements in accordance with the standards of the PCAOB. Those standards require that we plan
and perform the audit to obtain reasonable assurance about whether the consolidated financial statements are free of material misstatement, whether due to
error or fraud. The Company is not required to have, nor were we engaged to perform, an audit of its internal control over financial reporting. As part of our
audits we are required to obtain an understanding of internal control over financial reporting but not for the purpose of expressing an opinion on the
effectiveness of the Company's internal control over financial reporting. Accordingly, we express no such opinion.
Our audits included performing procedures to assess the risks of material misstatement of the consolidated financial statements, whether due to error or
fraud, and performing procedures that respond to those risks. Such procedures included examining, on a test basis, evidence regarding the amounts and
disclosures in the consolidated financial statements. Our audits also included evaluating the accounting principles used and significant estimates made by
management, as well as evaluating the overall presentation of the consolidated financial statements. We believe that our audits provide a reasonable basis
for our opinion.
Critical Audit Matters
The critical audit matter communicated below is a matter arising from the current period audit of the consolidated financial statements that was
communicated or required to be communicated to the audit committee and that (i) relates to accounts or disclosures that are material to the consolidated
financial statements and (ii) involved our especially challenging, subjective, or complex judgments. The communication of critical audit matters does not alter
in any way our opinion on the consolidated financial statements, taken as a whole, and we are not, by communicating the critical audit matter below,
providing a separate opinion on the critical audit matter or on the accounts or disclosures to which it relates.
Accounting for the Effects of Rate Regulation
As described in Notes 1 and 3 to the consolidated financial statements, the Company applies the authoritative guidance for accounting for certain types of
regulation, which requires management to record in their consolidated financial statements the effects of cost-based rate regulation for entities with regulated
operations that meet the following criteria, (i) rates are established or approved by a third-party regulator; (ii) rates are designed to recover the entity’s cost of
providing services or products; and (iii) there is a reasonable expectation that rates designed to recover costs can be charged to and collected from
customers. The Company accounts for its regulated operations in accordance with regulatory and legislative guidance from the regulatory authorities having
jurisdiction under state public utility laws and the FERC under various Federal laws. Upon updates in material regulatory and legislative proceedings, where
applicable, management will record new regulatory assets or liabilities and will assess whether it is probable that its currently recorded regulatory assets and
liabilities will
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be recovered and settled, respectively, in future rates. As of December 31, 2020, there were approximately $801 million of regulatory assets and
approximately $624 million of regulatory liabilities.
The principal considerations for our determination that performing procedures relating to management’s accounting for the effects of rate regulation is a
critical audit matter are the high degree of audit effort to assess the impact of regulation on accounting for regulatory assets and liabilities and to evaluate the
complex audit evidence related to whether the regulatory assets and liabilities will be recovered and settled.
Addressing the matter involved performing procedures and evaluating audit evidence in connection with forming our overall opinion on the consolidated
financial statements. These procedures included testing the effectiveness of controls relating to accounting for regulatory matters and evaluation of existing
regulatory assets and liabilities. These procedures also included, among others, obtaining the Company’s correspondence with regulators, evaluating the
reasonableness of management’s judgments regarding regulatory guidance and proceedings and the related accounting implications, and calculating
regulatory assets and liabilities based on provisions outlined in rate orders and other correspondence with regulators.
/s/ PricewaterhouseCoopers LLP
Philadelphia, Pennsylvania
February 24, 2021
We have served as the Company's auditor since 1932.
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Report of Independent Registered Public Accounting Firm
To the Board of Directors and Shareholder of Baltimore Gas and Electric Company
Opinion on the Financial Statements
We have audited the financial statements, including the related notes, as listed in the index appearing under Item 15(a)(5)(i), and the financial statement
schedule listed in the index appearing under Item 15(a)(5)(ii), of Baltimore Gas and Electric Company (the “Company”) (collectively referred to as the
“financial statements”). In our opinion, the financial statements present fairly, in all material respects, the financial position of the Company as of December
31, 2020 and 2019, and the results of its operations and its cash flows for each of the three years in the period ended December 31, 2020 in conformity with
accounting principles generally accepted in the United States of America.
Change in Accounting Principle
As discussed in Note 1 to the financial statements, the Company changed the manner in which it accounts for leases in 2019.
Basis for Opinion
These financial statements are the responsibility of the Company’s management. Our responsibility is to express an opinion on the Company’s financial
statements based on our audits. We are a public accounting firm registered with the Public Company Accounting Oversight Board (United States) (PCAOB)
and are required to be independent with respect to the Company in accordance with the U.S. federal securities laws and the applicable rules and regulations
of the Securities and Exchange Commission and the PCAOB.
We conducted our audits of these financial statements in accordance with the standards of the PCAOB. Those standards require that we plan and perform
the audit to obtain reasonable assurance about whether the financial statements are free of material misstatement, whether due to error or fraud. The
Company is not required to have, nor were we engaged to perform, an audit of its internal control over financial reporting. As part of our audits we are
required to obtain an understanding of internal control over financial reporting but not for the purpose of expressing an opinion on the effectiveness of the
Company's internal control over financial reporting. Accordingly, we express no such opinion.
Our audits included performing procedures to assess the risks of material misstatement of the financial statements, whether due to error or fraud, and
performing procedures that respond to those risks. Such procedures included examining, on a test basis, evidence regarding the amounts and disclosures in
the financial statements. Our audits also included evaluating the accounting principles used and significant estimates made by management, as well as
evaluating the overall presentation of the financial statements. We believe that our audits provide a reasonable basis for our opinion.
Critical Audit Matters
The critical audit matter communicated below is a matter arising from the current period audit of the financial statements that was communicated or required
to be communicated to the audit committee and that (i) relates to accounts or disclosures that are material to the financial statements and (ii) involved our
especially challenging, subjective, or complex judgments. The communication of critical audit matters does not alter in any way our opinion on the financial
statements, taken as a whole, and we are not, by communicating the critical audit matter below, providing a separate opinion on the critical audit matter or on
the accounts or disclosures to which it relates.
Accounting for the Effects of Rate Regulation
As described in Notes 1 and 3 to the financial statements, the Company applies the authoritative guidance for accounting for certain types of regulation,
which requires management to record in their financial statements the effects of cost-based rate regulation for entities with regulated operations that meet
the following criteria, (i) rates are established or approved by a third-party regulator; (ii) rates are designed to recover the entity’s cost of providing services or
products; and (iii) there is a reasonable expectation that rates designed to recover costs can be charged to and collected from customers. The Company
accounts for its regulated operations in
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accordance with regulatory and legislative guidance from the regulatory authorities having jurisdiction under state public utility laws and the FERC under
various Federal laws. Upon updates in material regulatory and legislative proceedings, where applicable, management will record new regulatory assets or
liabilities and will assess whether it is probable that its currently recorded regulatory assets and liabilities will be recovered and settled, respectively, in future
rates. As of December 31, 2020, there were approximately $649 million of regulatory assets and approximately $1,139 million of regulatory liabilities.
The principal considerations for our determination that performing procedures relating to management’s accounting for the effects of rate regulation is a
critical audit matter are the high degree of audit effort to assess the impact of regulation on accounting for regulatory assets and liabilities and to evaluate the
complex audit evidence related to whether the regulatory assets and liabilities will be recovered and settled.
Addressing the matter involved performing procedures and evaluating audit evidence in connection with forming our overall opinion on the financial
statements. These procedures included testing the effectiveness of controls relating to accounting for regulatory matters and evaluation of existing regulatory
assets and liabilities. These procedures also included, among others, obtaining the Company’s correspondence with regulators, evaluating the
reasonableness of management’s judgments regarding regulatory guidance and proceedings and the related accounting implications, and calculating
regulatory assets and liabilities based on provisions outlined in rate orders and other correspondence with regulators.
/s/ PricewaterhouseCoopers LLP
Baltimore, Maryland
February 24, 2021
We have served as the Company’s auditor since at least 1993. We have not been able to determine the specific year we began serving as auditor of the
Company.
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Report of Independent Registered Public Accounting Firm
To the Board of Directors and Member of Pepco Holdings LLC
Opinion on the Financial Statements
We have audited the consolidated financial statements, including the related notes, as listed in the index appearing under Item 15(a)(6)(i), and the financial
statement schedule listed in the index appearing under Item 15(a)(6)(ii), of Pepco Holdings LLC and its subsidiaries (the “Company”) (collectively referred to
as the “consolidated financial statements”). In our opinion, the consolidated financial statements present fairly, in all material respects, the financial position
of the Company as of December 31, 2020 and 2019, and the results of its operations and its cash flows for each of the three years in the period ended
December 31, 2020 in conformity with accounting principles generally accepted in the United States of America.
Change in Accounting Principle
As discussed in Note 1 to the consolidated financial statements, the Company changed the manner in which it accounts for leases in 2019.
Basis for Opinion
These consolidated financial statements are the responsibility of the Company’s management. Our responsibility is to express an opinion on the Company’s
consolidated financial statements based on our audits. We are a public accounting firm registered with the Public Company Accounting Oversight Board
(United States) (PCAOB) and are required to be independent with respect to the Company in accordance with the U.S. federal securities laws and the
applicable rules and regulations of the Securities and Exchange Commission and the PCAOB.
We conducted our audits of these consolidated financial statements in accordance with the standards of the PCAOB. Those standards require that we plan
and perform the audit to obtain reasonable assurance about whether the consolidated financial statements are free of material misstatement, whether due to
error or fraud. The Company is not required to have, nor were we engaged to perform, an audit of its internal control over financial reporting. As part of our
audits we are required to obtain an understanding of internal control over financial reporting but not for the purpose of expressing an opinion on the
effectiveness of the Company's internal control over financial reporting. Accordingly, we express no such opinion.
Our audits included performing procedures to assess the risks of material misstatement of the consolidated financial statements, whether due to error or
fraud, and performing procedures that respond to those risks. Such procedures included examining, on a test basis, evidence regarding the amounts and
disclosures in the consolidated financial statements. Our audits also included evaluating the accounting principles used and significant estimates made by
management, as well as evaluating the overall presentation of the consolidated financial statements. We believe that our audits provide a reasonable basis
for our opinion.
Critical Audit Matters
The critical audit matter communicated below is a matter arising from the current period audit of the consolidated financial statements that was
communicated or required to be communicated to the audit committee and that (i) relates to accounts or disclosures that are material to the consolidated
financial statements and (ii) involved our especially challenging, subjective, or complex judgments. The communication of critical audit matters does not alter
in any way our opinion on the consolidated financial statements, taken as a whole, and we are not, by communicating the critical audit matter below,
providing a separate opinion on the critical audit matter or on the accounts or disclosures to which it relates.
Accounting for the Effects of Rate Regulation
As described in Notes 1 and 3 to the consolidated financial statements, the Company applies the authoritative guidance for accounting for certain types of
regulation, which requires management to record in their consolidated financial statements the effects of cost-based rate regulation for entities with regulated
operations that meet the following criteria, (i) rates are established or approved by a third-party regulator; (ii) rates are designed to recover the entity’s cost of
providing services or products; and (iii) there is a reasonable expectation that rates designed to recover costs can be charged to and collected from
customers. The Company accounts for
171
Table of Contents
its regulated operations in accordance with regulatory and legislative guidance from the regulatory authorities having jurisdiction under state public utility
laws and the FERC under various Federal laws. Upon updates in material regulatory and legislative proceedings, where applicable, management will record
new regulatory assets or liabilities and will assess whether it is probable that its currently recorded regulatory assets and liabilities will be recovered and
settled, respectively, in future rates. As of December 31, 2020, there were approximately $2.4 billion of regulatory assets and approximately $1.6 billion of
regulatory liabilities.
The principal considerations for our determination that performing procedures relating to management’s accounting for the effects of rate regulation is a
critical audit matter are the high degree of audit effort to assess the impact of regulation on accounting for regulatory assets and liabilities and to evaluate the
complex audit evidence related to whether the regulatory assets and liabilities will be recovered and settled.
Addressing the matter involved performing procedures and evaluating audit evidence in connection with forming our overall opinion on the consolidated
financial statements. These procedures included testing the effectiveness of controls relating to accounting for regulatory matters and evaluation of existing
regulatory assets and liabilities. These procedures also included, among others, obtaining the Company’s correspondence with regulators, evaluating the
reasonableness of management’s judgments regarding regulatory guidance and proceedings and the related accounting implications, and calculating
regulatory assets and liabilities based on provisions outlined in rate orders and other correspondence with regulators.
/s/ PricewaterhouseCoopers LLP
Philadelphia, Pennsylvania
February 24, 2021
We have served as the Company's auditor since 2001.
172
Table of Contents
Report of Independent Registered Public Accounting Firm
To the Board of Directors and Shareholder of Potomac Electric Power Company
Opinion on the Financial Statements
We have audited the financial statements, including the related notes, as listed in the index appearing under Item 15(a)(7)(i), and the financial statement
schedule listed in the index appearing under Item 15(a)(7)(ii), of Potomac Electric Power Company (the “Company”) (collectively referred to as the “financial
statements”). In our opinion, the financial statements present fairly, in all material respects, the financial position of the Company as of December 31, 2020
and 2019, and the results of its operations and its cash flows for each of the three years in the period ended December 31, 2020 in conformity with
accounting principles generally accepted in the United States of America.
Change in Accounting Principle
As discussed in Note 1 to the financial statements, the Company changed the manner in which it accounts for leases in 2019.
Basis for Opinion
These financial statements are the responsibility of the Company’s management. Our responsibility is to express an opinion on the Company’s financial
statements based on our audits. We are a public accounting firm registered with the Public Company Accounting Oversight Board (United States) (PCAOB)
and are required to be independent with respect to the Company in accordance with the U.S. federal securities laws and the applicable rules and regulations
of the Securities and Exchange Commission and the PCAOB.
We conducted our audits of these financial statements in accordance with the standards of the PCAOB. Those standards require that we plan and perform
the audit to obtain reasonable assurance about whether the financial statements are free of material misstatement, whether due to error or fraud. The
Company is not required to have, nor were we engaged to perform, an audit of its internal control over financial reporting. As part of our audits we are
required to obtain an understanding of internal control over financial reporting but not for the purpose of expressing an opinion on the effectiveness of the
Company's internal control over financial reporting. Accordingly, we express no such opinion.
Our audits included performing procedures to assess the risks of material misstatement of the financial statements, whether due to error or fraud, and
performing procedures that respond to those risks. Such procedures included examining, on a test basis, evidence regarding the amounts and disclosures in
the financial statements. Our audits also included evaluating the accounting principles used and significant estimates made by management, as well as
evaluating the overall presentation of the financial statements. We believe that our audits provide a reasonable basis for our opinion.
Critical Audit Matters
The critical audit matter communicated below is a matter arising from the current period audit of the financial statements that was communicated or required
to be communicated to the audit committee and that (i) relates to accounts or disclosures that are material to the financial statements and (ii) involved our
especially challenging, subjective, or complex judgments. The communication of critical audit matters does not alter in any way our opinion on the financial
statements, taken as a whole, and we are not, by communicating the critical audit matter below, providing a separate opinion on the critical audit matter or on
the accounts or disclosures to which it relates.
Accounting for the Effects of Rate Regulation
As described in Notes 1 and 3 to the financial statements, the Company applies the authoritative guidance for accounting for certain types of regulation,
which requires management to record in their financial statements the effects of cost-based rate regulation for entities with regulated operations that meet
the following criteria, (i) rates are established or approved by a third-party regulator; (ii) rates are designed to recover the entity’s cost of providing services or
products; and (iii) there is a reasonable expectation that rates designed to recover costs can be charged to and collected from customers. The Company
accounts for its regulated operations in
173
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accordance with regulatory and legislative guidance from the regulatory authorities having jurisdiction under state public utility laws and the FERC under
various Federal laws. Upon updates in material regulatory and legislative proceedings, where applicable, management will record new regulatory assets or
liabilities and will assess whether it is probable that its currently recorded regulatory assets and liabilities will be recovered and settled, respectively, in future
rates. As of December 31, 2020, there were approximately $784 million of regulatory assets and approximately $690 million of regulatory liabilities.
The principal considerations for our determination that performing procedures relating to management’s accounting for the effects of rate regulation is a
critical audit matter are the high degree of audit effort to assess the impact of regulation on accounting for regulatory assets and liabilities and to evaluate the
complex audit evidence related to whether the regulatory assets and liabilities will be recovered and settled.
Addressing the matter involved performing procedures and evaluating audit evidence in connection with forming our overall opinion on the financial
statements. These procedures included testing the effectiveness of controls relating to accounting for regulatory matters and evaluation of existing regulatory
assets and liabilities. These procedures also included, among others, obtaining the Company’s correspondence with regulators, evaluating the
reasonableness of management’s judgments regarding regulatory guidance and proceedings and the related accounting implications, and calculating
regulatory assets and liabilities based on provisions outlined in rate orders and other correspondence with regulators.
/s/ PricewaterhouseCoopers LLP
Philadelphia, Pennsylvania
February 24, 2021
We have served as the Company's auditor since at least 1993. We have not been able to determine the specific year we began serving as auditor of the
Company.
174
Table of Contents
Report of Independent Registered Public Accounting Firm
To the Board of Directors and Shareholder of Delmarva Power & Light Company
Opinion on the Financial Statements
We have audited the financial statements, including the related notes, as listed in the index appearing under Item 15(a)(8)(i), and the financial statement
schedule listed in the index appearing under Item 15(a)(8)(ii), of Delmarva Power & Light Company (the “Company”) (collectively referred to as the “financial
statements”). In our opinion, the financial statements present fairly, in all material respects, the financial position of the Company as of December 31, 2020
and 2019, and the results of its operations and its cash flows for each of the three years in the period ended December 31, 2020 in conformity with
accounting principles generally accepted in the United States of America.
Change in Accounting Principle
As discussed in Note 1 to the financial statements, the Company changed the manner in which it accounts for leases in 2019.
Basis for Opinion
These financial statements are the responsibility of the Company’s management. Our responsibility is to express an opinion on the Company’s financial
statements based on our audits. We are a public accounting firm registered with the Public Company Accounting Oversight Board (United States) (PCAOB)
and are required to be independent with respect to the Company in accordance with the U.S. federal securities laws and the applicable rules and regulations
of the Securities and Exchange Commission and the PCAOB.
We conducted our audits of these financial statements in accordance with the standards of the PCAOB. Those standards require that we plan and perform
the audit to obtain reasonable assurance about whether the financial statements are free of material misstatement, whether due to error or fraud. The
Company is not required to have, nor were we engaged to perform, an audit of its internal control over financial reporting. As part of our audits we are
required to obtain an understanding of internal control over financial reporting but not for the purpose of expressing an opinion on the effectiveness of the
Company's internal control over financial reporting. Accordingly, we express no such opinion.
Our audits included performing procedures to assess the risks of material misstatement of the financial statements, whether due to error or fraud, and
performing procedures that respond to those risks. Such procedures included examining, on a test basis, evidence regarding the amounts and disclosures in
the financial statements. Our audits also included evaluating the accounting principles used and significant estimates made by management, as well as
evaluating the overall presentation of the financial statements. We believe that our audits provide a reasonable basis for our opinion.
Critical Audit Matters
The critical audit matter communicated below is a matter arising from the current period audit of the financial statements that was communicated or required
to be communicated to the audit committee and that (i) relates to accounts or disclosures that are material to the financial statements and (ii) involved our
especially challenging, subjective, or complex judgments. The communication of critical audit matters does not alter in any way our opinion on the financial
statements, taken as a whole, and we are not, by communicating the critical audit matter below, providing a separate opinion on the critical audit matter or on
the accounts or disclosures to which it relates.
Accounting for the Effects of Rate Regulation
As described in Notes 1 and 3 to the financial statements, the Company applies the authoritative guidance for accounting for certain types of regulation,
which requires management to record in their financial statements the effects of cost-based rate regulation for entities with regulated operations that meet
the following criteria, (i) rates are established or approved by a third-party regulator; (ii) rates are designed to recover the entity’s cost of providing services or
products; and (iii) there is a reasonable expectation that rates designed to recover costs can be charged to and collected from customers. The Company
accounts for its regulated operations in
175
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accordance with regulatory and legislative guidance from the regulatory authorities having jurisdiction under state public utility laws and the FERC under
various Federal laws. Upon updates in material regulatory and legislative proceedings, where applicable, management will record new regulatory assets or
liabilities and will assess whether it is probable that its currently recorded regulatory assets and liabilities will be recovered and settled, respectively, in future
rates. As of December 31, 2020, there were approximately $280 million of regulatory assets and approximately $540 million of regulatory liabilities.
The principal considerations for our determination that performing procedures relating to management’s accounting for the effects of rate regulation is a
critical audit matter are the high degree of audit effort to assess the impact of regulation on accounting for regulatory assets and liabilities and to evaluate the
complex audit evidence related to whether the regulatory assets and liabilities will be recovered and settled.
Addressing the matter involved performing procedures and evaluating audit evidence in connection with forming our overall opinion on the financial
statements. These procedures included testing the effectiveness of controls relating to accounting for regulatory matters and evaluation of existing regulatory
assets and liabilities. These procedures also included, among others, obtaining the Company’s correspondence with regulators, evaluating the
reasonableness of management’s judgments regarding regulatory guidance and proceedings and the related accounting implications, and calculating
regulatory assets and liabilities based on provisions outlined in rate orders and other correspondence with regulators.
/s/ PricewaterhouseCoopers LLP
Philadelphia, Pennsylvania
February 24, 2021
We have served as the Company's auditor since at least 1993. We have not been able to determine the specific year we began serving as auditor of the
Company.
176
Table of Contents
Report of Independent Registered Public Accounting Firm
To the Board of Directors and Shareholder of Atlantic City Electric Company
Opinion on the Financial Statements
We have audited the consolidated financial statements, including the related notes, as listed in the index appearing under Item 15(a)(9)(i), and the financial
statement schedule listed in the index appearing under Item 15(a)(9)(ii), of Atlantic City Electric Company and its subsidiary (the “Company”) (collectively
referred to as the “consolidated financial statements”). In our opinion, the consolidated financial statements present fairly, in all material respects, the
financial position of the Company as of December 31, 2020 and 2019, and the results of its operations and its cash flows for each of the three years in the
period ended December 31, 2020 in conformity with accounting principles generally accepted in the United States of America.
Change in Accounting Principle
As discussed in Note 1 to the consolidated financial statements, the Company changed the manner in which it accounts for leases in 2019.
Basis for Opinion
These consolidated financial statements are the responsibility of the Company’s management. Our responsibility is to express an opinion on the Company’s
consolidated financial statements based on our audits. We are a public accounting firm registered with the Public Company Accounting Oversight Board
(United States) (PCAOB) and are required to be independent with respect to the Company in accordance with the U.S. federal securities laws and the
applicable rules and regulations of the Securities and Exchange Commission and the PCAOB.
We conducted our audits of these consolidated financial statements in accordance with the standards of the PCAOB. Those standards require that we plan
and perform the audit to obtain reasonable assurance about whether the consolidated financial statements are free of material misstatement, whether due to
error or fraud. The Company is not required to have, nor were we engaged to perform, an audit of its internal control over financial reporting. As part of our
audits we are required to obtain an understanding of internal control over financial reporting but not for the purpose of expressing an opinion on the
effectiveness of the Company's internal control over financial reporting. Accordingly, we express no such opinion.
Our audits included performing procedures to assess the risks of material misstatement of the consolidated financial statements, whether due to error or
fraud, and performing procedures that respond to those risks. Such procedures included examining, on a test basis, evidence regarding the amounts and
disclosures in the consolidated financial statements. Our audits also included evaluating the accounting principles used and significant estimates made by
management, as well as evaluating the overall presentation of the consolidated financial statements. We believe that our audits provide a reasonable basis
for our opinion.
Critical Audit Matters
The critical audit matter communicated below is a matter arising from the current period audit of the consolidated financial statements that was
communicated or required to be communicated to the audit committee and that (i) relates to accounts or disclosures that are material to the consolidated
financial statements and (ii) involved our especially challenging, subjective, or complex judgments. The communication of critical audit matters does not alter
in any way our opinion on the consolidated financial statements, taken as a whole, and we are not, by communicating the critical audit matter below,
providing a separate opinion on the critical audit matter or on the accounts or disclosures to which it relates.
Accounting for the Effects of Rate Regulation
As described in Notes 1 and 3 to the consolidated financial statements, the Company applies the authoritative guidance for accounting for certain types of
regulation, which requires management to record in their consolidated financial statements the effects of cost-based rate regulation for entities with regulated
operations that meet the following criteria, (i) rates are established or approved by a third-party regulator; (ii) rates are designed to recover the entity’s cost of
providing services or products; and (iii) there is a reasonable expectation that rates designed to recover costs can be charged to and collected from
customers. The Company accounts for
177
Table of Contents
its regulated operations in accordance with regulatory and legislative guidance from the regulatory authorities having jurisdiction under state public utility
laws and the FERC under various Federal laws. Upon updates in material regulatory and legislative proceedings, where applicable, management will record
new regulatory assets or liabilities and will assess whether it is probable that its currently recorded regulatory assets and liabilities will be recovered and
settled, respectively, in future rates. As of December 31, 2020, there were approximately $470 million of regulatory assets and approximately $318 million of
regulatory liabilities.
The principal considerations for our determination that performing procedures relating to management’s accounting for the effects of rate regulation is a
critical audit matter are the high degree of audit effort to assess the impact of regulation on accounting for regulatory assets and liabilities and to evaluate the
complex audit evidence related to whether the regulatory assets and liabilities will be recovered and settled.
Addressing the matter involved performing procedures and evaluating audit evidence in connection with forming our overall opinion on the consolidated
financial statements. These procedures included testing the effectiveness of controls relating to accounting for regulatory matters and evaluation of existing
regulatory assets and liabilities. These procedures also included, among others, obtaining the Company’s correspondence with regulators, evaluating the
reasonableness of management’s judgments regarding regulatory guidance and proceedings and the related accounting implications, and calculating
regulatory assets and liabilities based on provisions outlined in rate orders and other correspondence with regulators.
/s/ PricewaterhouseCoopers LLP
Philadelphia, Pennsylvania
February 24, 2021
We have served as the Company's auditor since 1998.
178
Table of Contents
Exelon Corporation and Subsidiary Companies
Consolidated Statements of Operations and Comprehensive Income
(In millions, except per share data)
Operating revenues
Competitive businesses revenues
Rate-regulated utility revenues
Revenues from alternative revenue programs
Total operating revenues
Operating expenses
Competitive businesses purchased power and fuel
Rate-regulated utility purchased power and fuel
Operating and maintenance
Depreciation and amortization
Taxes other than income taxes
Total operating expenses
Gain on sales of assets and businesses
Gain on deconsolidation of business
Operating income
Other income and (deductions)
Interest expense, net
Interest expense to affiliates
Other, net
Total other (deductions)
Income before income taxes
Income taxes
Equity in losses of unconsolidated affiliates
Net income
Net (loss) income attributable to noncontrolling interests
Net income attributable to common shareholders
Comprehensive income, net of income taxes
Net income
Other comprehensive income (loss), net of income taxes
Pension and non-pension postretirement benefit plans:
Prior service benefit reclassified to periodic benefit cost
Actuarial loss reclassified to periodic benefit cost
Pension and non-pension postretirement benefit plan valuation adjustment
Unrealized (loss) gain on cash flow hedges
Unrealized gain on investments in unconsolidated affiliates
Unrealized gain (loss) on foreign currency translation
Other comprehensive income (loss)
Comprehensive income
Comprehensive (loss) income attributable to noncontrolling interests
Comprehensive income attributable to common shareholders
Average shares of common stock outstanding:
Basic
Assumed exercise and/or distributions of stock-based awards
Diluted
(a)
Earnings per average common share:
Basic
Diluted
For the Years Ended December 31,
2020
2019
2018
$
$
$
$
$
$
16,400
16,633
6
33,039
9,592
4,512
9,408
5,014
1,714
30,240
24
—
2,823
(1,610)
(25)
1,145
(490)
2,333
373
(6)
1,954
(9)
1,963
1,954
(40)
190
(357)
(3)
—
4
(206)
1,748
(9)
$
$
$
17,754
16,839
(155)
34,438
10,849
4,648
8,615
4,252
1,732
30,096
31
1
4,374
(1,591)
(25)
1,227
(389)
3,985
774
(183)
3,028
92
2,936
3,028
(65)
149
(289)
—
1
6
(198)
2,830
93
$
1,757
$
2,737
$
976
1
977
973
1
974
$
$
2.01
2.01
$
$
3.02
3.01
$
$
19,168
16,879
(69)
35,978
11,679
4,991
9,337
4,353
1,783
32,143
56
—
3,891
(1,529)
(25)
(112)
(1,666)
2,225
118
(28)
2,079
74
2,005
2,079
(66)
247
(143)
12
2
(10)
42
2,121
75
2,046
967
2
969
2.07
2.07
__________
(a)
The number of stock options not included in the calculation of diluted common shares outstanding due to their antidilutive effect was less than 1 million for the years ended
December 31, 2020 and December 31, 2019 and approximately 3 million for the year ended December 31, 2018.
See the Combined Notes to Consolidated Financial Statements
179
Table of Contents
Exelon Corporation and Subsidiary Companies
Consolidated Statements of Cash Flows
(In millions)
Cash flows from operating activities
Net income
Adjustments to reconcile net income to net cash flows provided by operating activities:
Depreciation, amortization, and accretion, including nuclear fuel and energy contract amortization
Asset impairments
Gain on sales of assets and businesses
Deferred income taxes and amortization of investment tax credits
Net fair value changes related to derivatives
Net realized and unrealized (gains) losses on NDT funds
Unrealized gain on equity investments
Other non-cash operating activities
Changes in assets and liabilities:
Accounts receivable
Inventories
Accounts payable and accrued expenses
Option premiums (paid), net
Collateral received (posted), net
Income taxes
Pension and non-pension postretirement benefit contributions
Other assets and liabilities
Net cash flows provided by operating activities
Cash flows from investing activities
Capital expenditures
Proceeds from NDT fund sales
Investment in NDT funds
Collection of DPP
Acquisitions of assets and businesses, net
Proceeds from sales of assets and businesses
Other investing activities
Net cash flows used in investing activities
Cash flows from financing activities
Changes in short-term borrowings
Proceeds from short-term borrowings with maturities greater than 90 days
Repayments on short-term borrowings with maturities greater than 90 days
Issuance of long-term debt
Retirement of long-term debt
Dividends paid on common stock
Proceeds from employee stock plans
Other financing activities
Net cash flows provided by (used in) financing activities
Increase (decrease) in cash, restricted cash, and cash equivalents
Cash, restricted cash, and cash equivalents at beginning of period
Cash, restricted cash, and cash equivalents at end of period
Supplemental cash flow information
Increase (decrease) in capital expenditures not paid
Increase in DPP
Increase (decrease) in PP&E related to ARO update
For the Years Ended December 31,
2020
2019
2018
$
1,954
$
3,028
$
2,079
6,527
591
(24)
309
(268)
(461)
(186)
592
697
(85)
(129)
(139)
494
140
(601)
(5,176)
4,235
(8,048)
3,341
(3,464)
3,771
—
46
18
(4,336)
161
500
—
7,507
(6,440)
(1,492)
45
(136)
145
44
1,122
1,166
194
4,441
850
$
$
5,780
201
(27)
681
222
(663)
—
613
(243)
(87)
(425)
(29)
(438)
(64)
(408)
(1,482)
6,659
(7,248)
10,051
(10,087)
—
(41)
53
12
(7,260)
781
—
(125)
1,951
(1,287)
(1,408)
112
(82)
(58)
(659)
1,781
1,122
(7)
—
968
$
$
5,971
50
(56)
(108)
294
303
—
1,131
(565)
(37)
551
(43)
82
340
(383)
(965)
8,644
(7,594)
8,762
(8,997)
—
(154)
91
58
(7,834)
(338)
126
(1)
3,115
(1,786)
(1,332)
105
(108)
(219)
591
1,190
1,781
(69)
—
(107)
$
$
See the Combined Notes to Consolidated Financial Statements
180
Table of Contents
Exelon Corporation and Subsidiary Companies
Consolidated Balance Sheets
(In millions)
Current assets
ASSETS
Cash and cash equivalents
Restricted cash and cash equivalents
Accounts receivable
Customer accounts receivable
Customer allowance for credit losses
Customer accounts receivable, net
Other accounts receivable
Other allowance for credit losses
Other accounts receivable, net
Mark-to-market derivative assets
Unamortized energy contract assets
Inventories, net
Fossil fuel and emission allowances
Materials and supplies
Regulatory assets
Renewable energy credits
Assets held for sale
Other
Total current assets
Property, plant, and equipment (net of accumulated depreciation and amortization of $26,727 and
$23,979 as of December 31, 2020 and 2019, respectively)
Deferred debits and other assets
Regulatory assets
Nuclear decommissioning trust funds
Investments
Goodwill
Mark-to-market derivative assets
Unamortized energy contract assets
Other
Total deferred debits and other assets
Total assets
(a)
$
3,597
(366)
1,469
(71)
December 31,
2020
2019
663 $
438
587
358
4,835
(243)
1,631
(48)
3,231
1,398
644
38
297
1,425
1,228
633
958
1,609
12,562
82,584
8,759
14,464
440
6,677
555
294
2,982
34,171
4,592
1,583
679
47
312
1,456
1,170
348
—
905
12,037
80,233
8,335
13,190
464
6,677
508
336
3,197
32,707
124,977
$
129,317 $
See the Combined Notes to Consolidated Financial Statements
181
Table of Contents
Exelon Corporation and Subsidiary Companies
Consolidated Balance Sheets
(In millions)
Current liabilities
LIABILITIES AND SHAREHOLDERS’ EQUITY
December 31,
2020
2019
Short-term borrowings
Long-term debt due within one year
Accounts payable
Accrued expenses
Payables to affiliates
Regulatory liabilities
Mark-to-market derivative liabilities
Unamortized energy contract liabilities
Renewable energy credit obligation
Liabilities held for sale
Other
Total current liabilities
Long-term debt
Long-term debt to financing trusts
Deferred credits and other liabilities
Deferred income taxes and unamortized investment tax credits
Asset retirement obligations
Pension obligations
Non-pension postretirement benefit obligations
Spent nuclear fuel obligation
Regulatory liabilities
Mark-to-market derivative liabilities
Unamortized energy contract liabilities
Other
Total deferred credits and other liabilities
Total liabilities
(a)
Commitments and contingencies
Shareholders’ equity
Common stock (No par value, 2,000 shares authorized, 976 shares and 973 shares outstanding at
December 31, 2020 and 2019, respectively)
Treasury stock, at cost (2 shares at December 31, 2020 and 2019)
Retained earnings
Accumulated other comprehensive loss, net
Total shareholders’ equity
Noncontrolling interests
Total equity
Total liabilities and shareholders' equity
$
2,031 $
1,819
3,562
2,078
5
581
295
100
661
375
1,264
12,771
35,093
390
13,035
12,300
4,503
2,011
1,208
9,485
473
238
2,942
46,195
94,449
19,373
(123)
16,735
(3,400)
32,585
2,283
34,868
$
129,317 $
1,370
4,710
3,560
1,981
5
406
247
132
443
—
1,331
14,185
31,329
390
12,351
10,846
4,247
2,076
1,199
9,986
393
338
3,064
44,500
90,404
19,274
(123)
16,267
(3,194)
32,224
2,349
34,573
124,977
__________
(a)
Exelon’s consolidated assets include $10,200 million and $9,532 million at December 31, 2020 and 2019, respectively, of certain VIEs that can only be used to settle the
liabilities of the VIE. Exelon’s consolidated liabilities include $3,598 million and $3,473 million at December 31, 2020 and 2019, respectively, of certain VIEs for which the
VIE creditors do not have recourse to Exelon. See Note 23–Variable Interest Entities for additional information.
See the Combined Notes to Consolidated Financial Statements
182
Table of Contents
Exelon Corporation and Subsidiary Companies
Consolidated Statements of Changes in Equity
Shareholders' Equity
Issued
Shares
Common
Stock
Treasury
Stock
Retained
Earnings
Accumulated
Other
Comprehensive
Loss
Noncontrolling
Interests
Total
Equity
$
965,168
—
3,534
1,318
—
—
—
—
$
18,964
—
41
105
6
—
—
—
—
970,020
—
$
—
19,116
—
$
3,111
1,285
—
—
—
—
974,416
—
1,570
1,480
—
—
40
112
6
—
—
$
$
—
19,274
—
40
56
3
—
—
—
—
977,466
$
—
19,373
$
(123)
—
—
—
—
—
—
—
—
(123)
—
—
—
—
—
—
—
(123)
—
—
—
—
—
—
—
(123)
$
$
$
$
14,063
2,005
—
—
—
—
(1,339)
—
14
14,743
2,936
$
—
—
—
—
(1,412)
—
16,267
1,963
—
—
—
—
(1,495)
$
—
16,735
$
$
$
(3,026)
—
—
—
—
—
—
41
(10)
(2,995)
—
$
—
—
—
—
—
$
(199)
(3,194)
—
—
—
—
—
—
(206)
(3,400)
$
$
2,291
74
—
—
—
(60)
—
1
—
2,306
92
$
—
—
—
(48)
—
(1)
2,349
(9)
—
—
—
(57)
$
—
—
2,283
$
32,169
2,079
41
105
6
(60)
(1,339)
42
4
33,047
3,028
40
112
6
(48)
(1,412)
(200)
34,573
1,954
40
56
3
(57)
(1,495)
(206)
34,868
(In millions, shares in thousands)
Balance, December 31, 2017
Net income
Long-term incentive plan activity
Employee stock purchase plan issuances
Sale of noncontrolling interests
Changes in equity of noncontrolling interests
Common stock dividends
($1.38/common share)
Other comprehensive income, net of income
taxes
Impact of adoption of Recognition and
Measurement of Financial Assets and
Liabilities standard
Balance, December 31, 2018
Net income
Long-term incentive plan
activity
Employee stock purchase
plan issuances
Sale of noncontrolling interests
Changes in equity of noncontrolling interests
Common stock dividends
($1.45/common share)
Other comprehensive income, net of income
taxes
Balance, December 31, 2019
Net income (loss)
Long-term incentive plan activity
Employee stock purchase plan issuances
Sale of noncontrolling interests
Changes in equity of noncontrolling interests
Common stock dividends
($1.53/common share)
Other comprehensive income, net of income
taxes
Balance, December 31, 2020
See the Combined Notes to Consolidated Financial Statements
183
Table of Contents
Exelon Generation Company, LLC and Subsidiary Companies
Consolidated Statements of Operations and Comprehensive Income
(In millions)
Operating revenues
Operating revenues
Operating revenues from affiliates
Total operating revenues
Operating expenses
Purchased power and fuel
Purchased power and fuel from affiliates
Operating and maintenance
Operating and maintenance from affiliates
Depreciation and amortization
Taxes other than income taxes
Total operating expenses
Gain on sales of assets and businesses
Operating income
Other income and (deductions)
Interest expense, net
Interest expense to affiliates
Other, net
Total other income and (deductions)
Income before income taxes
Income taxes
Equity in losses of unconsolidated affiliates
Net income
Net (loss) income attributable to noncontrolling interests
Net income attributable to membership interest
Comprehensive income, net of income taxes
Net income
Other comprehensive income (loss), net of income taxes
Unrealized (loss) gain on cash flow hedges
Unrealized gain on investments in unconsolidated affiliates
Unrealized gain (loss) on foreign currency translation
Other comprehensive income
Comprehensive income
Comprehensive (loss) income attributable to noncontrolling interests
Comprehensive income attributable to membership interest
For the Years Ended December 31,
2020
2019
2018
$
16,392 $
1,211
17,603
17,752 $
1,172
18,924
9,592
(7)
4,613
555
2,123
482
17,358
11
256
(328)
(29)
937
580
836
249
(8)
579
(10)
589 $
10,849
7
4,131
587
1,535
519
17,628
27
1,323
(394)
(35)
1,023
594
1,917
516
(184)
1,217
92
1,125 $
579 $
1,217 $
(2)
—
4
2
581 $
(10)
591 $
—
1
6
7
1,224 $
93
1,131 $
$
$
$
$
19,169
1,268
20,437
11,679
14
4,803
661
1,797
556
19,510
48
975
(396)
(36)
(178)
(610)
365
(108)
(30)
443
73
370
443
12
1
(10)
3
446
74
372
See the Combined Notes to Consolidated Financial Statements
184
Table of Contents
Exelon Generation Company, LLC and Subsidiary Companies
Consolidated Statements of Cash Flows
(In millions)
Cash flows from operating activities
Net income
Adjustments to reconcile net income to net cash flows provided by operating activities:
Depreciation, amortization, and accretion, including nuclear fuel and energy contract amortization
Asset impairments
Gain on sales of assets and businesses
Deferred income taxes and amortization of investment tax credits
Net fair value changes related to derivatives
Net realized and unrealized (gains) losses on NDT fund investments
Unrealized gain on equity investments
Other non-cash operating activities
Changes in assets and liabilities:
Accounts receivable
Receivables from and payables to affiliates, net
Inventories
Accounts payable and accrued expenses
Option premiums paid, net
Collateral received (posted), net
Income taxes
Pension and non-pension postretirement benefit contributions
Other assets and liabilities
Net cash flows provided by operating activities
Cash flows from investing activities
Capital expenditures
Proceeds from NDT fund sales
Investment in NDT funds
Collection of DPP
Proceeds from sales of assets and businesses
Acquisitions of assets and businesses, net
Other investing activities
Net cash flows provided by (used in) investing activities
Cash flows from financing activities
Change in short-term borrowings
Proceeds from short-term borrowings with maturities greater than 90 days
Issuance of long-term debt
Retirement of long-term debt
Retirement of long-term debt to affiliate
Changes in Exelon intercompany money pool
Distributions to member
Contributions from member
Other financing activities
Net cash flows used in financing activities
(Decrease) increase in cash, restricted cash, and cash equivalents
Cash, restricted cash, and cash equivalents at beginning of period
Cash, restricted cash, and cash equivalents at end of period
Supplemental cash flow information
Decrease in capital expenditures not paid
Increase in DPP
Increase (decrease) in PP&E related to ARO update
For the Years Ended December 31,
2020
2019
2018
$
579
$
1,217
$
443
3,636
563
(11)
78
(270)
(461)
(186)
18
1,125
24
(77)
(343)
(139)
479
186
(255)
(4,362)
584
(1,747)
3,341
(3,464)
3,771
46
—
11
1,958
20
500
3,155
(4,334)
(550)
285
(1,734)
64
(70)
(2,664)
(122)
449
3,063
201
(27)
361
228
(663)
—
(124)
(186)
(52)
(47)
(248)
(29)
(481)
302
(175)
(467)
2,873
(1,845)
10,051
(10,087)
—
52
(41)
3
(1,867)
320
—
42
(813)
—
(100)
(899)
41
(51)
(1,460)
(454)
903
$
$
327
$
449
$
$
(88)
4,441
850
$
(34)
—
959
3,415
50
(48)
(451)
307
303
—
298
(359)
8
(12)
376
(43)
64
(193)
(139)
(158)
3,861
(2,242)
8,762
(8,997)
—
90
(154)
10
(2,531)
—
—
15
(141)
—
46
(1,001)
155
(55)
(981)
349
554
903
(199)
—
(130)
See the Combined Notes to Consolidated Financial Statements
185
Table of Contents
Exelon Generation Company, LLC and Subsidiary Companies
Consolidated Balance Sheets
(In millions)
Current assets
ASSETS
Cash and cash equivalents
Restricted cash and cash equivalents
Accounts receivable
Customer accounts receivable
Customer allowance for credit losses
Customer accounts receivable, net
Other accounts receivable
Other accounts receivable, net
Mark-to-market derivative assets
Receivables from affiliates
Unamortized energy contract assets
Inventories, net
Fossil fuel and emission allowances
Materials and supplies
Renewable energy credits
Assets held for sale
Other
Total current assets
Property, plant, and equipment (net of accumulated depreciation and amortization of $13,370 and
$12,017 as of December 31, 2020 and 2019, respectively)
Deferred debits and other assets
Nuclear decommissioning trust funds
Investments
Goodwill
Mark-to-market derivative assets
Prepaid pension asset
Unamortized energy contract assets
Deferred income taxes
Other
Total deferred debits and other assets
Total assets
(a)
December 31,
2020
2019
226 $
89
303
146
2,973
(80)
619
1,298
352
644
153
38
233
978
621
958
1,357
6,947
22,214
14,464
184
47
555
1,558
293
6
1,826
18,933
48,094 $
2,893
619
675
190
47
236
1,026
336
—
605
7,076
24,193
13,190
235
47
508
1,438
336
12
1,960
17,726
48,995
$
1,330
(32)
352
$
See the Combined Notes to Consolidated Financial Statements
186
Table of Contents
Exelon Generation Company, LLC and Subsidiary Companies
Consolidated Balance Sheets
(In millions)
Current liabilities
LIABILITIES AND EQUITY
Short-term borrowings
Long-term debt due within one year
Long-term debt to affiliates due within one year
Accounts payable
Accrued expenses
Payables to affiliates
Borrowings from Exelon intercompany money pool
Mark-to-market derivative liabilities
Unamortized energy contract liabilities
Renewable energy credit obligation
Liabilities held for sale
Other
Total current liabilities
Long-term debt
Long-term debt to affiliates
Deferred credits and other liabilities
Deferred income taxes and unamortized investment tax credits
Asset retirement obligations
Non-pension postretirement benefit obligations
Spent nuclear fuel obligation
Payables to affiliates
Mark-to-market derivative liabilities
Unamortized energy contract liabilities
Other
Total deferred credits and other liabilities
Total liabilities
(a)
Commitments and contingencies
Equity
Member’s equity
Membership interest
Undistributed earnings
Accumulated other comprehensive loss, net
Total member’s equity
Noncontrolling interests
Total equity
Total liabilities and equity
December 31,
2020
2019
$
$
840 $
197
—
1,253
788
107
285
262
7
661
375
444
5,219
5,566
324
3,656
12,054
858
1,208
3,017
205
3
1,308
22,309
33,418
9,624
2,805
(30)
12,399
2,277
14,676
48,094 $
320
2,624
558
1,692
786
117
—
215
17
443
—
517
7,289
4,464
328
3,752
10,603
878
1,199
3,103
123
11
1,415
21,084
33,165
9,566
3,950
(32)
13,484
2,346
15,830
48,995
__________
(a) Generation’s consolidated assets include $10,182 million and $9,512 million at December 31, 2020 and 2019, respectively, of certain VIEs that can only be used to settle
the liabilities of the VIE. Generation’s consolidated liabilities include $3,572 million and $3,429 million at December 31, 2020 and 2019, respectively, of certain VIEs for
which the VIE creditors do not have recourse to Generation. See Note 23–Variable Interest Entities for additional information.
See the Combined Notes to Consolidated Financial Statements
187
Table of Contents
Exelon Generation Company, LLC and Subsidiary Companies
Consolidated Statements of Changes in Equity
(In millions)
Balance, December 31, 2017
Net income
Sale of noncontrolling interests
Changes in equity of noncontrolling interests
Distributions to member
Contributions from member
Other comprehensive income, net of income
taxes
Impact of adoption of Recognition and
Measurement of Financial Assets and Liabilities
standard
Balance, December 31, 2018
Net income
Sale of noncontrolling interests
Changes in equity of noncontrolling interests
Distributions to member
Contributions from member
Other comprehensive income (loss), net of
income taxes
Balance, December 31, 2019
Net income
Sale of noncontrolling interests
Changes in equity of noncontrolling interests
Distribution to member of deferred taxes
associated with net retirement benefit obligation
Distributions to member
Contributions from member
Other comprehensive income, net of income
taxes
Balance, December 31, 2020
$
$
$
$
Member’s Equity
Membership
Interest
Undistributed
Earnings
Accumulated
Other
Comprehensive
Loss, net
Noncontrolling
Interests
Total
Equity
9,357 $
—
6
—
—
155
4,349 $
370
—
—
(1,001)
—
—
—
—
9,518 $
—
7
—
—
41
—
9,566 $
—
3
—
(9)
—
64
6
3,724 $
1,125
—
—
(899)
—
—
3,950 $
589
—
—
—
(1,734)
—
—
9,624 $
—
2,805 $
(37) $
—
—
—
—
—
2
(3)
(38) $
—
—
—
—
—
6
(32) $
—
—
—
—
—
—
2
(30) $
2,290 $
73
—
(60)
—
—
1
—
2,304 $
92
—
(48)
—
—
(2)
2,346 $
(10)
—
(59)
—
—
—
—
2,277 $
15,959
443
6
(60)
(1,001)
155
3
3
15,508
1,217
7
(48)
(899)
41
4
15,830
579
3
(59)
(9)
(1,734)
64
2
14,676
See the Combined Notes to Consolidated Financial Statements
188
Table of Contents
Commonwealth Edison Company and Subsidiary Companies
Consolidated Statements of Operations and Comprehensive Income
(In millions)
Operating revenues
Electric operating revenues
Revenues from alternative revenue programs
Operating revenues from affiliates
Total operating revenues
Operating expenses
Purchased power
Purchased power from affiliates
Operating and maintenance
Operating and maintenance from affiliates
Depreciation and amortization
Taxes other than income taxes
Total operating expenses
Gain on sales of assets
Operating income
Other income and (deductions)
Interest expense, net
Interest expense to affiliates
Other, net
Total other income and (deductions)
Income before income taxes
Income taxes
Net income
Comprehensive income
For the Years Ended December 31,
2020
2019
2018
5,914 $
(47)
37
5,904
5,850 $
(133)
30
5,747
1,653
345
1,231
289
1,133
299
4,950
—
954
(369)
(13)
43
(339)
615
177
438 $
438 $
1,565
376
1,041
264
1,033
301
4,580
4
1,171
(346)
(13)
39
(320)
851
163
688 $
688 $
5,884
(29)
27
5,882
1,626
529
1,068
267
940
311
4,741
5
1,146
(334)
(13)
33
(314)
832
168
664
664
$
$
$
See the Combined Notes to Consolidated Financial Statements
189
Table of Contents
(In millions)
Cash flows from operating activities
Commonwealth Edison Company and Subsidiary Companies
Consolidated Statements of Cash Flows
For the Years Ended December 31,
2020
2019
2018
Net income
Adjustments to reconcile net income to net cash flows provided by operating activities:
$
438 $
688 $
Depreciation and amortization
Deferred income taxes and amortization of investment tax credits
Other non-cash operating activities
Changes in assets and liabilities:
Accounts receivable
Receivables from and payables to affiliates, net
Inventories
Accounts payable and accrued expenses
Counterparty received (posted), net
Income taxes
Pension and non-pension postretirement benefit contributions
Other assets and liabilities
Net cash flows provided by operating activities
Cash flows from investing activities
Capital expenditures
Other investing activities
Net cash flows used in investing activities
Cash flows from financing activities
Changes in short-term borrowings
Issuance of long-term debt
Retirement of long-term debt
Dividends paid on common stock
Contributions from parent
Other financing activities
Net cash flows provided by financing activities
Increase in cash, restricted cash, and cash equivalents
Cash, restricted cash, and cash equivalents at beginning of period
Cash, restricted cash, and cash equivalents at end of period
Supplemental cash flow information
Increase (decrease) in capital expenditures not paid
$
$
See the Combined Notes to Consolidated Financial Statements
190
1,133
228
202
(10)
(1)
(13)
63
14
8
(148)
(590)
1,324
(2,217)
2
(2,215)
193
1,000
(500)
(499)
712
(13)
893
2
403
405 $
1,033
109
265
(34)
(12)
(16)
(51)
48
95
(77)
(345)
1,703
(1,915)
29
(1,886)
130
700
(300)
(508)
250
(16)
256
73
330
403 $
664
940
259
242
(136)
26
1
70
11
62
(42)
(348)
1,749
(2,126)
29
(2,097)
—
1,350
(840)
(459)
500
(17)
534
186
144
330
109 $
(37) $
11
Table of Contents
Commonwealth Edison Company and Subsidiary Companies
Consolidated Balance Sheets
(In millions)
Current assets
ASSETS
Cash and cash equivalents
Restricted cash and cash equivalents
Accounts receivable
Customer accounts receivable
Customer allowance for credit losses
Customer accounts receivable, net
Other accounts receivable
Other allowance for credit losses
Other accounts receivable, net
Receivables from affiliates
Inventories, net
Regulatory assets
Other
Total current assets
Property, plant, and equipment (net of accumulated depreciation and amortization of $5,672 and
$5,168 as of December 31, 2020 and December 31, 2019, respectively)
Deferred debits and other assets
Regulatory assets
Investments
Goodwill
Receivables from affiliates
Prepaid pension asset
Other
Total deferred debits and other assets
Total assets
$
656
(97)
239
(21)
December 31,
2020
2019
83 $
279
604
(59)
306
(20)
559
218
22
170
279
49
1,659
24,557
1,749
6
2,625
2,541
1,022
307
8,250
$
34,466 $
90
150
545
286
28
159
281
44
1,583
23,107
1,480
6
2,625
2,622
995
347
8,075
32,765
See the Combined Notes to Consolidated Financial Statements
191
Table of Contents
Commonwealth Edison Company and Subsidiary Companies
Consolidated Balance Sheets
(In millions)
Current liabilities
LIABILITIES AND SHAREHOLDERS’ EQUITY
December 31,
2020
2019
Short-term borrowings
Long-term debt due within one year
Accounts payable
Accrued expenses
Payables to affiliates
Customer deposits
Regulatory liabilities
Mark-to-market derivative liabilities
Other
Total current liabilities
Long-term debt
Long-term debt to financing trusts
Deferred credits and other liabilities
Deferred income taxes and unamortized investment tax credits
Asset retirement obligations
Non-pension postretirement benefits obligations
Regulatory liabilities
Mark-to-market derivative liabilities
Other
Total deferred credits and other liabilities
Total liabilities
Commitments and contingencies
Shareholders’ equity
Common stock ($12.50 par value, 250 shares authorized, 127 shares outstanding at December 31,
2020 and 2019)
Other paid-in capital
Retained deficit unappropriated
Retained earnings appropriated
Total shareholders’ equity
Total liabilities and shareholders’ equity
$
$
323 $
350
683
390
96
86
289
33
143
2,393
8,633
205
4,341
126
173
6,403
268
595
11,906
23,137
1,588
8,285
(1,639)
3,095
11,329
34,466 $
130
500
527
385
103
118
200
32
122
2,117
7,991
205
4,021
128
180
6,542
269
635
11,775
22,088
1,588
7,572
(1,639)
3,156
10,677
32,765
See the Combined Notes to Consolidated Financial Statements
192
Table of Contents
(In millions)
Balance, December 31, 2017
Net income
Appropriation of retained earnings for future
dividends
Common stock dividends
Contributions from parent
Balance, December 31, 2018
Net income
Appropriation of retained earnings for future
dividends
Common stock dividends
Contributions from parent
Balance, December 31, 2019
Net income
Appropriation of retained earnings for future
dividends
Common stock dividends
Contributions from parent
Balance, December 31, 2020
Commonwealth Edison Company and Subsidiary Companies
Consolidated Statements of Changes in Shareholders’ Equity
Common
Stock
Other
Paid-In
Capital
Retained Deficit
Unappropriated
Retained
Earnings
Appropriated
Total
Shareholders’
Equity
$
$
$
$
1,588 $
—
—
—
—
1,588 $
—
—
—
—
1,588 $
—
—
—
—
1,588 $
6,822 $
—
—
—
500
7,322 $
—
—
—
250
7,572 $
—
—
—
713
8,285 $
(1,639) $
664
(664)
—
—
(1,639) $
688
(688)
—
—
(1,639) $
438
(438)
—
—
(1,639) $
2,771 $
—
664
(459)
—
2,976 $
—
688
(508)
—
3,156 $
—
438
(499)
—
3,095 $
9,542
664
—
(459)
500
10,247
688
—
(508)
250
10,677
438
—
(499)
713
11,329
See the Combined Notes to Consolidated Financial Statements
193
Table of Contents
PECO Energy Company and Subsidiary Companies
Consolidated Statements of Operations and Comprehensive Income
(In millions)
Operating revenues
Electric operating revenues
Natural gas operating revenues
Revenues from alternative revenue programs
Operating revenues from affiliates
Total operating revenues
Operating expenses
Purchased power
Purchased fuel
Purchased power from affiliates
Operating and maintenance
Operating and maintenance from affiliates
Depreciation and amortization
Taxes other than income taxes
Total operating expenses
Gain on sales of assets
Operating income
Other income and (deductions)
Interest expense, net
Interest expense to affiliates, net
Other, net
Total other income and (deductions)
Income before income taxes
Income taxes
Net income
Comprehensive income
For the Years Ended December 31,
2020
2019
2018
2,519 $
514
16
9
3,058
2,505 $
610
(21)
6
3,100
645
185
188
816
159
347
172
2,512
—
546
(136)
(11)
18
(129)
417
(30)
447 $
447 $
610
262
157
707
154
333
165
2,388
1
713
(124)
(12)
16
(120)
593
65
528 $
528 $
2,469
568
(7)
8
3,038
734
230
126
742
156
301
163
2,452
1
587
(115)
(14)
8
(121)
466
6
460
460
$
$
$
See the Combined Notes to Consolidated Financial Statements
194
Table of Contents
PECO Energy Company and Subsidiary Companies
Consolidated Statements of Cash Flows
(In millions)
Cash flows from operating activities
Net income
Adjustments to reconcile net income to net cash flows provided by
operating activities:
Depreciation and amortization
Gain on sale of assets
Deferred income taxes and amortization of investment tax
credits
Other non-cash operating activities
Changes in assets and liabilities:
Accounts receivable
Receivables from and payables to affiliates, net
Inventories
Accounts payable and accrued expenses
Income taxes
Pension and non-pension postretirement benefit contributions
Other assets and liabilities
Net cash flows provided by operating activities
Cash flows from investing activities
Capital expenditures
Changes in Exelon intercompany money pool
Other investing activities
Net cash flows used in investing activities
Cash flows from financing activities
Issuance of long-term debt
Retirement of long-term debt
Dividends paid on common stock
Contributions from parent
Changes in Exelon intercompany money pool
Other financing activities
Net cash flows provided by (used in) financing activities
Decrease in cash, restricted cash, and cash equivalents
Cash, restricted cash, and cash equivalents at beginning of period
Cash, restricted cash, and cash equivalents at end of period
Supplemental cash flow information
Increase (decrease) in capital expenditures not paid
$
$
See the Combined Notes to Consolidated Financial Statements
195
For the Years Ended December 31,
2020
2019
2018
$
447 $
528 $
460
347
—
(23)
24
(88)
(6)
(1)
63
31
(18)
1
777
(1,147)
68
7
(1,072)
350
—
(340)
248
40
(4)
294
(1)
27
26 $
333
(1)
20
38
(29)
(5)
4
(11)
(34)
(28)
(64)
751
(939)
(68)
(1)
(1,008)
325
—
(358)
188
—
(6)
149
(108)
135
27 $
301
—
(5)
51
(74)
7
(14)
(3)
15
(28)
29
739
(849)
—
9
(840)
700
(500)
(306)
89
—
(22)
(39)
(140)
275
135
55 $
40 $
(12)
Table of Contents
PECO Energy Company and Subsidiary Companies
Consolidated Balance Sheets
(In millions)
Current assets
ASSETS
Cash and cash equivalents
Restricted cash and cash equivalents
Accounts receivable
Customer accounts receivable
Customer allowance for credit losses
Customer accounts receivable, net
Other accounts receivable
Other allowance for credit losses
Other accounts receivable, net
Receivables from affiliates
Receivable from Exelon intercompany money pool
Inventories, net
Fossil fuel
Materials and supplies
Regulatory assets
Other
Total current assets
Property, plant, and equipment (net of accumulated depreciation and amortization of $3,843 and
$3,718 as of December 31, 2020 and 2019, respectively)
Deferred debits and other assets
Regulatory assets
Investments
Receivables from affiliates
Prepaid pension asset
Other
Total deferred debits and other assets
Total assets
$
511
(116)
130
(8)
December 31,
2020
2019
19 $
7
412
(55)
145
(7)
395
122
2
—
33
38
25
21
662
10,181
776
30
475
375
32
1,688
$
12,531 $
21
6
357
138
1
68
36
35
41
19
722
9,292
554
27
480
365
29
1,455
11,469
See the Combined Notes to Consolidated Financial Statements
196
Table of Contents
PECO Energy Company and Subsidiary Companies
Consolidated Balance Sheets
(In millions)
Current liabilities
LIABILITIES AND SHAREHOLDER'S EQUITY
Long-term debt due within one year
Accounts payable
Accrued expenses
Payables to affiliates
Borrowings from Exelon intercompany money pool
Customer deposits
Regulatory liabilities
Other
Total current liabilities
Long-term debt
Long-term debt to financing trusts
Deferred credits and other liabilities
Deferred income taxes and unamortized investment tax credits
Asset retirement obligations
Non-pension postretirement benefits obligations
Regulatory liabilities
Other
Total deferred credits and other liabilities
Total liabilities
Commitments and contingencies
Shareholder's equity
Common stock (No par value, 500 shares authorized, 170 shares outstanding at December 31, 2020
and 2019)
Retained earnings
Total shareholder's equity
Total liabilities and shareholder's equity
December 31,
2020
2019
$
300 $
479
129
50
40
59
121
30
1,208
3,453
184
2,242
29
286
503
93
3,153
7,998
3,014
1,519
4,533
$
12,531 $
—
387
101
55
—
69
91
19
722
3,405
184
2,080
28
288
510
74
2,980
7,291
2,766
1,412
4,178
11,469
See the Combined Notes to Consolidated Financial Statements
197
Table of Contents
PECO Energy Company and Subsidiary Companies
Consolidated Statements of Changes in Shareholder's Equity
(In millions)
Balance, December 31, 2017
Net income
Common stock dividends
Contributions from parent
Impact of adoption of Recognition and Measurement of
Financial Assets and Liabilities standard
Balance, December 31, 2018
Net income
Common stock dividends
Contributions from parent
Balance, December 31, 2019
Net income
Common stock dividends
Contributions from parent
Balance, December 31, 2020
$
$
$
$
Common
Stock
Retained
Earnings
Accumulated
Other
Comprehensive
Income
Total
Shareholder's
Equity
2,489 $
—
—
89
—
2,578 $
—
—
188
2,766 $
—
—
248
3,014 $
1,087 $
460
(306)
—
1
1,242 $
528
(358)
—
1,412 $
447
(340)
—
1,519 $
1 $
—
—
—
(1)
— $
—
—
—
— $
—
—
—
— $
3,577
460
(306)
89
—
3,820
528
(358)
188
4,178
447
(340)
248
4,533
See the Combined Notes to Consolidated Financial Statements
198
Table of Contents
Baltimore Gas and Electric Company
Statements of Operations and Comprehensive Income
(In millions)
Operating revenues
Electric operating revenues
Natural gas operating revenues
Revenues from alternative revenue programs
Operating revenues from affiliates
Total operating revenues
Operating expenses
Purchased power
Purchased fuel
Purchased power and fuel from affiliates
Operating and maintenance
Operating and maintenance from affiliates
Depreciation and amortization
Taxes other than income taxes
Total operating expenses
Gain on sales of assets
Operating income
Other income and (deductions)
Interest expense, net
Other, net
Total other income and (deductions)
Income before income taxes
Income taxes
Net income
Comprehensive income
For the Years Ended December 31,
2020
2019
2018
$
2,323 $
739
16
20
3,098
2,368 $
700
12
26
3,106
509
171
311
617
172
550
268
2,598
—
500
(133)
23
(110)
390
41
585
181
286
600
160
502
260
2,574
—
532
(121)
28
(93)
439
79
$
$
349 $
349 $
360 $
360 $
2,428
738
(26)
29
3,169
671
254
257
615
162
483
254
2,696
1
474
(106)
19
(87)
387
74
313
313
See the Combined Notes to Consolidated Financial Statements
199
Table of Contents
(In millions)
Cash flows from operating activities
Baltimore Gas and Electric Company
Statements of Cash Flows
For the Years Ended December 31,
2020
2019
2018
Net income
Adjustments to reconcile net income to net cash flows provided by operating activities:
$
349 $
360 $
Depreciation and amortization
Deferred income taxes and amortization of investment tax credits
Other non-cash operating activities
Changes in assets and liabilities:
Accounts receivable
Receivables from and payables to affiliates, net
Inventories
Accounts payable and accrued expenses
Collateral (posted) received, net
Income taxes
Pension and non-pension postretirement benefit contributions
Other assets and liabilities
Net cash flows provided by operating activities
Cash flows from investing activities
Capital expenditures
Other investing activities
Net cash flows used in investing activities
Cash flows from financing activities
Changes in short-term borrowings
Issuance of long-term debt
Dividends paid on common stock
Contributions from parent
Other financing activities
Net cash flows provided by financing activities
Increase (decrease) in cash, restricted cash, and cash equivalents
Cash, restricted cash, and cash equivalents at beginning of period
Cash, restricted cash, and cash equivalents at end of period
Supplemental cash flow information
Increase in capital expenditures not paid
$
$
See the Combined Notes to Consolidated Financial Statements
200
550
37
97
(165)
(8)
10
102
—
60
(78)
(70)
884
(1,247)
2
(1,245)
(76)
400
(246)
411
(8)
481
120
25
145 $
502
130
85
25
1
(1)
(43)
(4)
(67)
(48)
(192)
748
(1,145)
8
(1,137)
40
400
(224)
193
(8)
401
12
13
25 $
313
483
76
58
8
12
2
(1)
4
(20)
(54)
(92)
789
(959)
9
(950)
(42)
300
(209)
109
(2)
156
(5)
18
13
53 $
6 $
50
Table of Contents
Baltimore Gas and Electric Company
Balance Sheets
(In millions)
Current assets
ASSETS
Cash and cash equivalents
Restricted cash and cash equivalents
Accounts receivable
Customer accounts receivable
Customer allowance for credit losses
Customer accounts receivable, net
Other accounts receivable
Other allowance for credit losses
Other accounts receivable, net
Receivables from affiliates
Inventories, net
Fossil fuel
Materials and supplies
Prepaid utility taxes
Regulatory assets
Other
Total current assets
Property, plant, and equipment (net of accumulated depreciation and amortization of $4,034 and
$3,834 as of December 31, 2020 and 2019, respectively)
Deferred debits and other assets
Regulatory assets
Investments
Prepaid pension asset
Other
Total deferred debits and other assets
Total assets
December 31,
2020
2019
144 $
1
329
(12)
152
(5)
452
108
3
25
41
—
168
6
948
9,872
481
10
270
69
830
11,650 $
24
1
317
147
1
30
46
78
183
6
833
8,990
454
7
264
86
811
10,634
$
487
(35)
117
(9)
$
See the Combined Notes to Consolidated Financial Statements
201
Table of Contents
Baltimore Gas and Electric Company
Balance Sheets
(In millions)
Current liabilities
LIABILITIES AND SHAREHOLDER'S EQUITY
Short-term borrowings
Long-term debt due within one year
Accounts payable
Accrued expenses
Payables to affiliates
Customer deposits
Regulatory liabilities
Other
Total current liabilities
Long-term debt
Deferred credits and other liabilities
Deferred income taxes and unamortized investment tax credits
Asset retirement obligations
Non-pension postretirement benefits obligations
Regulatory liabilities
Other
Total deferred credits and other liabilities
Total liabilities
Commitments and contingencies
Shareholder's equity
Common stock (No par value, 0 shares authorized, 0 shares outstanding at December 31, 2020 and
2019)
Retained earnings
(a)
(a)
Total shareholder's equity
Total liabilities and shareholder's equity
December 31,
2020
2019
$
— $
300
346
205
61
110
30
91
1,143
3,364
1,521
23
189
1,109
104
2,946
7,453
2,318
1,879
4,197
11,650 $
$
76
—
243
152
66
120
33
63
753
3,270
1,396
22
199
1,195
116
2,928
6,951
1,907
1,776
3,683
10,634
_____________
(a)
In millions, shares round to zero. Number of shares is 1,500 authorized and 1,000 outstanding at December 31, 2020 and 2019.
See the Combined Notes to Consolidated Financial Statements
202
Table of Contents
(In millions)
Balance, December 31, 2017
Net income
Common stock dividends
Contributions from parent
Balance, December 31, 2018
Net income
Common stock dividends
Contributions from parent
Balance, December 31, 2019
Net income
Common stock dividends
Contributions from parent
Balance, December 31, 2020
Baltimore Gas and Electric Company
Statements of Changes in Shareholder's Equity
Common
Stock
Retained
Earnings
Total
Shareholder's
Equity
$
$
$
$
1,605 $
—
—
109
1,714 $
—
—
193
1,907 $
—
—
411
2,318 $
1,536 $
313
(209)
—
1,640 $
360
(224)
—
1,776 $
349
(246)
—
1,879 $
3,141
313
(209)
109
3,354
360
(224)
193
3,683
349
(246)
411
4,197
See the Combined Notes to Consolidated Financial Statements
203
Table of Contents
Pepco Holdings LLC and Subsidiary Companies
Consolidated Statements of Operations and Comprehensive Income
(In millions)
Operating revenues
Electric operating revenues
Natural gas operating revenues
Revenues from alternative revenue programs
Operating revenues from affiliates
Total operating revenues
Operating expenses
Purchased power
Purchased fuel
Purchased power from affiliates
Operating and maintenance
Operating and maintenance from affiliates
Depreciation and amortization
Taxes other than income taxes
Total operating expenses
Gain on sales of assets
Operating income
Other income and (deductions)
Interest expense, net
Other, net
Total other income and (deductions)
Income before income taxes
Income taxes
Equity in earnings of unconsolidated affiliate
Net income
Comprehensive income
For the Years Ended December 31,
2020
2019
2018
4,463 $
162
21
17
4,663
1,279
69
366
940
159
782
450
4,045
11
629
(268)
57
(211)
418
(77)
—
495 $
495 $
4,639 $
167
(14)
14
4,806
1,371
75
352
939
143
754
450
4,084
—
722
(263)
55
(208)
514
38
1
477 $
477 $
4,609
181
(7)
15
4,798
1,387
89
355
978
152
740
455
4,156
1
643
(261)
43
(218)
425
33
1
393
393
$
$
$
See the Combined Notes to Consolidated Financial Statements
204
Table of Contents
Pepco Holdings LLC and Subsidiary Companies
Consolidated Statements of Cash Flows
(In millions)
Cash flows from operating activities
Net income
Adjustments to reconcile net income to net cash from operating activities:
Depreciation and amortization
Deferred income taxes and amortization of investment tax credits
Other non-cash operating activities
Changes in assets and liabilities:
Accounts receivable
Receivables from and payables to affiliates, net
Inventories
Accounts payable and accrued expenses
Income taxes
Pension and non-pension postretirement benefit contributions
Other assets and liabilities
Net cash flows provided by operating activities
Cash flows from investing activities
Capital expenditures
Other investing activities
Net cash flows used in investing activities
Cash flows from financing activities
Changes in short-term borrowings
Proceeds from short-term borrowings with maturities greater than 90 days
Repayments of short-term borrowings with maturities greater than 90 days
Issuance of long-term debt
Retirement of long-term debt
Change in Exelon intercompany money pool
Distributions to member
Contributions from member
Other financing activities
Net cash flows provided by financing activities
(Decrease) increase in cash, restricted cash, and cash equivalents
Cash, restricted cash, and cash equivalents at beginning of period
Cash, restricted cash, and cash equivalents at end of period
Supplemental cash flow information
Increase in capital expenditures not paid
For the Years Ended
December 31,
2020
2019
2018
$
495
$
477
$
782
(97)
103
(159)
3
(6)
49
(25)
(39)
(104)
1,002
(1,604)
7
(1,597)
160
—
—
602
(128)
9
(553)
494
(10)
574
(21)
181
160
$
754
(7)
161
(39)
3
(27)
(17)
16
(25)
(179)
1,117
(1,355)
(3)
(1,358)
154
—
(125)
485
(157)
12
(526)
398
(5)
236
(5)
186
181
$
393
740
30
150
(2)
8
(14)
45
34
(74)
(178)
1,132
(1,375)
4
(1,371)
(296)
125
—
750
(299)
—
(326)
385
(9)
330
91
95
186
$
$
54
$
2
$
93
See the Combined Notes to Consolidated Financial Statements
205
Table of Contents
Pepco Holdings LLC and Subsidiary Companies
Consolidated Balance Sheets
(In millions)
Current assets
ASSETS
Cash and cash equivalents
Restricted cash and cash equivalents
Accounts receivable
Customer accounts receivable
Customer allowance for credit losses
Customer accounts receivable, net
Other accounts receivable
Other allowance for credit losses
Other accounts receivable, net
Receivable from affiliates
Inventories, net
Fossil fuel
Materials and supplies
Regulatory assets
Other
Total current assets
Property, plant, and equipment (net of accumulated depreciation and amortization of $1,811 and
$1,213 as of December 31, 2020 and 2019, respectively)
Deferred debits and other assets
Regulatory assets
Investments
Goodwill
Prepaid pension asset
Deferred income taxes
Other
Total deferred debits and other assets
Total assets
(a)
$
611
(86)
260
(33)
December 31,
2020
2019
111 $
39
516
(37)
190
(16)
525
227
8
6
198
440
45
1,599
15,377
1,933
140
4,005
365
10
307
6,760
$
23,736 $
131
36
479
174
1
8
190
412
49
1,480
14,296
2,061
135
4,005
406
13
323
6,943
22,719
See the Combined Notes to Consolidated Financial Statements
206
Table of Contents
Pepco Holdings LLC and Subsidiary Companies
Consolidated Balance Sheets
(In millions)
Current liabilities
LIABILITIES AND EQUITY
Short-term borrowings
Long-term debt due within one year
Accounts payable
Accrued expenses
Payables to affiliates
Borrowings from Exelon intercompany money pool
Customer deposits
Regulatory liabilities
Unamortized energy contract liabilities
Other
Total current liabilities
Long-term debt
Deferred credits and other liabilities
Deferred income taxes and unamortized investment tax credits
Asset retirement obligations
Non-pension postretirement benefit obligations
Regulatory liabilities
Unamortized energy contract liabilities
Other
Total deferred credits and other liabilities
Total liabilities
(a)
Commitments and contingencies
Member's equity
Membership interest
Undistributed (losses) gains
Total member's equity
Total liabilities and member's equity
December 31,
2020
2019
$
$
368 $
347
539
299
104
21
106
137
92
141
2,154
6,659
2,439
59
86
1,438
235
622
4,879
13,692
10,112
(68)
10,044
23,736 $
208
103
462
296
98
12
117
70
115
131
1,612
6,460
2,278
57
93
1,707
327
577
5,039
13,111
9,618
(10)
9,608
22,719
_____________
(a)
PHI’s consolidated total assets include $18 million and $20 million at December 31, 2020 and 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 $26 million and $44 million at December 31, 2020 and 2019, respectively, of PHI's consolidated VIE for
which the VIE creditors do not have recourse to PHI. See Note 23 - Variable Interest Entities for additional information.
See the Combined Notes to Consolidated Financial Statements
207
Table of Contents
(In millions)
Balance, December 31, 2017
Net income
Distribution to member
Contributions from member
Balance, December 31, 2018
Net Income
Distribution to member
Contributions from member
Balance, December 31, 2019
Net income
Distribution to member
Contributions from member
Balance, December 31, 2020
Pepco Holdings LLC and Subsidiary Companies
Consolidated Statements of Changes in Equity
Membership Interest
Undistributed
(Losses)/Gains
Total
Member's Equity
$
$
$
$
8,835 $
—
—
385
9,220 $
—
—
398
9,618 $
—
—
494
10,112 $
(28) $
393
(326)
—
39 $
477
(526)
—
(10) $
495
(553)
—
(68) $
8,807
393
(326)
385
9,259
477
(526)
398
9,608
495
(553)
494
10,044
See the Combined Notes to Consolidated Financial Statements
208
Table of Contents
Potomac Electric Power Company
Statements of Operations and Comprehensive Income
(In millions)
Operating revenues
Electric operating revenues
Revenues from alternative revenue programs
Operating revenues from affiliates
Total operating revenues
Operating expenses
Purchased power
Purchased power from affiliate
Operating and maintenance
Operating and maintenance from affiliates
Depreciation and amortization
Taxes other than income taxes
Total operating expenses
Gain on sales of assets
Operating income
Other income and (deductions)
Interest expense, net
Other, net
Total other income and (deductions)
Income before income taxes
Income taxes
Net income
Comprehensive income
For the Years Ended December 31,
2020
2019
2018
2,102 $
40
7
2,149
2,258 $
(3)
5
2,260
324
278
248
205
377
367
1,799
9
359
(138)
38
(100)
259
(7)
266 $
266 $
401
264
273
209
374
378
1,899
—
361
(133)
31
(102)
259
16
243 $
243 $
2,233
(7)
6
2,232
448
206
275
226
385
379
1,919
—
313
(128)
31
(97)
216
11
205
205
$
$
$
See the Combined Notes to Consolidated Financial Statements
209
Table of Contents
(In millions)
Cash flows from operating activities
Potomac Electric Power Company
Statements of Cash Flows
For the Years Ended December 31,
2020
2019
2018
Net income
Adjustments to reconcile net income to net cash flows provided by operating activities:
$
266 $
243 $
Depreciation and amortization
Deferred income taxes and amortization of investment tax credits
Other non-cash operating activities
Changes in assets and liabilities:
Accounts receivable
Receivables from and payables to affiliates, net
Inventories
Accounts payable and accrued expenses
Income taxes
Pension and non-pension postretirement benefit contributions
Other assets and liabilities
Net cash flows provided by operating activities
Cash flows from investing activities
Capital expenditures
Other investing activities
Net cash flows used in investing activities
Cash flows from financing activities
Changes in short-term borrowings
Issuance of long-term debt
Retirement of long-term debt
Dividends paid on common stock
Contributions from parent
Other financing activities
Net cash flows provided by financing activities
Increase in cash, restricted cash, and cash equivalents
Cash, restricted cash, and cash equivalents at beginning of period
Cash, restricted cash, and cash equivalents at end of period
Supplemental cash flow information
Increase in capital expenditures not paid
$
$
See the Combined Notes to Consolidated Financial Statements
210
377
(46)
(23)
(67)
(12)
1
41
(1)
(11)
(24)
501
(773)
—
(773)
(47)
300
(3)
(232)
262
(6)
274
2
63
65 $
374
1
56
(22)
5
(19)
(39)
9
(14)
(82)
512
(626)
3
(623)
42
260
(125)
(213)
160
(3)
121
10
53
63 $
205
385
(20)
67
(5)
(17)
(6)
59
(13)
(17)
(164)
474
(656)
2
(654)
14
200
(14)
(169)
166
(4)
193
13
40
53
1 $
39 $
20
Table of Contents
(In millions)
Current assets
ASSETS
Cash and cash equivalents
Restricted cash and cash equivalents
Accounts receivable
Customer accounts receivable
Customer allowance for credit losses
Customer accounts receivable, net
Other accounts receivable
Other allowance for credit losses
Other accounts receivable, net
Receivables from affiliates
Inventories, net
Regulatory assets
Other
Total current assets
Potomac Electric Power Company
Balance Sheets
December 31,
2020
2019
$
279
(32)
131
(13)
$
30 $
35
244
(13)
98
(7)
247
118
2
111
214
13
770
7,456
570
115
284
69
1,038
9,264 $
30
33
231
91
—
112
188
11
696
6,909
584
110
296
66
1,056
8,661
Property, plant, and equipment (net of accumulated depreciation and amortization of $3,697 and
$3,517 as of December 31, 2020 and 2019, respectively)
Deferred debits and other assets
Regulatory assets
Investments
Prepaid pension asset
Other
Total deferred debits and other assets
Total assets
See the Combined Notes to Consolidated Financial Statements
211
Table of Contents
Potomac Electric Power Company
Balance Sheets
(In millions)
Current liabilities
LIABILITIES AND SHAREHOLDER'S EQUITY
Short-term borrowings
Long-term debt due within one year
Accounts payable
Accrued expenses
Payables to affiliates
Customer deposits
Regulatory liabilities
Merger related obligation
Current portion of DC PLUG obligation
Other
Total current liabilities
Long-term debt
Deferred credits and other liabilities
Deferred income taxes and unamortized investment tax credits
Asset retirement obligations
Non-pension postretirement benefit obligations
Regulatory liabilities
Other
Total deferred credits and other liabilities
Total liabilities
Commitments and contingencies
Shareholder's equity
December 31,
2020
2019
$
35 $
3
226
164
55
51
46
33
30
31
674
3,162
1,189
39
13
644
340
2,225
6,061
Common stock ($0.01 par value, 200 shares authorized, 0 shares outstanding at December 31, 2020
and 2019)
Retained earnings
(a)
Total shareholder's equity
Total liabilities and shareholder's equity
_____________
(a)
In millions, shares round to zero. Number of shares is 100 outstanding at December 31, 2020 and 2019.
2,058
1,145
3,203
9,264 $
$
82
2
195
156
66
57
8
39
30
22
657
2,862
1,131
41
20
746
297
2,235
5,754
1,796
1,111
2,907
8,661
See the Combined Notes to Consolidated Financial Statements
212
Table of Contents
(In millions)
Balance, December 31, 2017
Net income
Common stock dividends
Contributions from parent
Balance, December 31, 2018
Net income
Common stock dividends
Contributions from parent
Balance, December 31, 2019
Net income
Common stock dividends
Contributions from parent
Balance, December 31, 2020
Potomac Electric Power Company
Statements of Changes in Shareholder's Equity
Common Stock
Retained Earnings
Total Shareholder's Equity
$
$
$
$
1,470 $
—
—
166
1,636 $
—
—
160
1,796 $
—
—
262
2,058 $
1,045 $
205
(169)
—
1,081 $
243
(213)
—
1,111 $
266
(232)
—
1,145 $
2,515
205
(169)
166
2,717
243
(213)
160
2,907
266
(232)
262
3,203
See the Combined Notes to Consolidated Financial Statements
213
Table of Contents
Delmarva Power & Light Company
Statements of Operations and Comprehensive Income
(In millions)
Operating revenues
Electric operating revenues
Natural gas operating revenues
Revenues from alternative revenue programs
Operating revenues from affiliates
Total operating revenues
Operating expenses
Purchased power
Purchased fuel
Purchased power from affiliates
Operating and maintenance
Operating and maintenance from affiliates
Depreciation and amortization
Taxes other than income taxes
Total operating expenses
Gain on sales of assets
Operating income
Other income and (deductions)
Interest expense, net
Other, net
Total other income and (deductions)
Income before income taxes
Income taxes
Net income
Comprehensive income
For the Years Ended December 31,
2020
2019
2018
1,107 $
162
(7)
9
1,271
1,143 $
167
(11)
7
1,306
359
69
75
208
153
191
65
1,120
—
151
(61)
10
(51)
100
(25)
125 $
125 $
381
75
70
171
152
184
56
1,089
—
217
(61)
13
(48)
169
22
147 $
147 $
1,139
181
4
8
1,332
352
89
120
182
162
182
56
1,143
1
190
(58)
10
(48)
142
22
120
120
$
$
$
See the Combined Notes to Consolidated Financial Statements
214
Table of Contents
(In millions)
Cash flows from operating activities
Delmarva Power & Light Company
Statements of Cash Flows
For the Years Ended December 31,
2020
2019
g
2018
Net income
Adjustments to reconcile net income to net cash flows provided by operating activities:
$
125 $
147
$
Depreciation and amortization
Deferred income taxes and amortization of investment tax credits
Other non-cash operating activities
Changes in assets and liabilities:
Accounts receivable
Receivables from and payables to affiliates, net
Inventories
Accounts payable and accrued expenses
Income taxes
Pension and non-pension postretirement benefit contributions
Other assets and liabilities
Net cash flows provided by operating activities
Cash flows from investing activities
Capital expenditures
Other investing activities
Net cash flows used in investing activities
Cash flows from financing activities
Change in short-term borrowings
Issuance of long-term debt
Retirement of long-term debt
Dividends paid on common stock
Contributions from parent
Other financing activities
Net cash flows provided by financing activities
Increase (decrease) in cash and cash equivalents
Cash and cash equivalents at beginning of period
Cash and cash equivalents at end of period
Supplemental cash flow information
Increase (decrease) in capital expenditures not paid
$
$
See the Combined Notes to Consolidated Financial Statements
215
191
(13)
51
(34)
8
(5)
4
(25)
—
(30)
272
(424)
(3)
(427)
90
178
(80)
(141)
112
(2)
157
2
13
15 $
184
(7)
27
(5)
(5)
(6)
3
12
(1)
(55)
294
(348)
1
(347)
56
75
(12)
(139)
63
(1)
42
(11)
24
13
$
120
182
24
24
8
(9)
(3)
11
2
—
(7)
352
(364)
2
(362)
(216)
200
(4)
(96)
150
(2)
32
22
2
24
20 $
(4)
$
22
Delmarva Power & Light Company
Balance Sheets
Table of Contents
(In millions)
Current assets
ASSETS
Cash and cash equivalents
Accounts receivable
Customer accounts receivable
Customer allowance for credit losses
Customer accounts receivable, net
Other accounts receivable
Other allowance for credit losses
Other accounts receivable, net
Receivables from affiliates
Inventories, net
Fossil fuel
Materials and supplies
Prepaid utility taxes
Regulatory assets
Renewable energy credits
Other
Total current assets
Property, plant, and equipment, (net of accumulated depreciation and amortization of $1,533 and
$1,425 as of December 31, 2020 and 2019, respectively)
Deferred debits and other assets
Regulatory assets
Goodwill
Prepaid pension asset
Other
Total deferred debits and other assets
Total assets
December 31,
2020
2019
15 $
13
152
(11)
42
(4)
154
59
1
6
51
11
58
10
3
368
4,314
222
8
162
66
458
5,140 $
141
38
—
8
44
18
52
9
2
325
4,035
222
8
171
69
470
4,830
$
176
(22)
68
(9)
$
See the Combined Notes to Consolidated Financial Statements
216
Table of Contents
Delmarva Power & Light Company
Balance Sheets
(In millions)
Current liabilities
LIABILITIES AND SHAREHOLDER'S EQUITY
Short-term borrowings
Long-term debt due within one year
Accounts payable
Accrued expenses
Payables to affiliates
Customer deposits
Regulatory liabilities
Other
Total current liabilities
Long-term debt
Deferred credits and other liabilities
Deferred income taxes and unamortized investment tax credits
Asset retirement obligations
Non-pension postretirement benefit obligations
Regulatory liabilities
Other
Total deferred credits and other liabilities
Total liabilities
Commitments and contingencies
Shareholder's equity
Common stock ($2.25 par value, 0 shares authorized, 0 shares outstanding at December 31, 2020 and
2019, respectively)
(a)
(a)
Retained earnings
Total shareholder's equity
Total liabilities and shareholder's equity
December 31,
2020
2019
$
146 $
82
126
46
36
32
47
20
535
1,595
715
14
15
493
97
1,334
3,464
1,089
587
1,676
5,140 $
$
56
80
112
46
32
36
37
15
414
1,487
655
12
16
574
92
1,349
3,250
977
603
1,580
4,830
_____________
(a)
In millions, shares round to zero. Number of shares is 1,000 authorized and 1,000 outstanding at December 31, 2020 and 2019.
See the Combined Notes to Consolidated Financial Statements
217
Table of Contents
(In millions)
Balance, December 31, 2017
Net income
Common stock dividends
Contributions from parent
Balance, December 31, 2018
Net income
Common stock dividends
Contributions from parent
Balance, December 31, 2019
Net income
Common stock dividends
Contributions from parent
Balance, December 31, 2020
Delmarva Power & Light Company
Statements of Changes in Shareholder's Equity
Common Stock
Retained Earnings
Total Shareholder's Equity
$
$
$
$
764 $
—
—
150
914 $
—
—
63
977 $
—
—
112
1,089 $
571 $
120
(96)
—
595 $
147
(139)
—
603 $
125
(141)
—
587 $
1,335
120
(96)
150
1,509
147
(139)
63
1,580
125
(141)
112
1,676
See the Combined Notes to Consolidated Financial Statements
218
Table of Contents
Atlantic City Electric Company and Subsidiary Company
Consolidated Statements of Operations and Comprehensive Income
(In millions)
Operating revenues
Electric operating revenues
Revenues from alternative revenue programs
Operating revenues from affiliates
Total operating revenues
Operating expenses
Purchased power
Purchased power from affiliate
Operating and maintenance
Operating and maintenance from affiliates
Depreciation and amortization
Taxes other than income taxes
Total operating expenses
Gain on sale of assets
Operating income
Other income and (deductions)
Interest expense, net
Other, net
Total other income and (deductions)
Income before income taxes
Income taxes
Net income
Comprehensive income
For the Years Ended December 31,
2020
2019
2018
1,253 $
(12)
4
1,245
1,237 $
—
3
1,240
596
13
192
134
180
8
1,123
2
124
(59)
6
(53)
71
(41)
112 $
112 $
589
19
187
133
157
4
1,089
—
151
(58)
6
(52)
99
—
99 $
99 $
1,237
(4)
3
1,236
587
29
188
142
136
5
1,087
—
149
(64)
2
(62)
87
12
75
75
$
$
$
See the Combined Notes to Consolidated Financial Statements
219
Table of Contents
Atlantic City Electric Company and Subsidiary Company
Consolidated Statements of Cash Flows
(In millions)
Cash flows from operating activities
Net income
Adjustments to reconcile net income to net cash from operating activities:
Depreciation and amortization
Deferred income taxes and amortization of investment tax credits
Other non-cash operating activities
Changes in assets and liabilities:
Accounts receivable
Receivables from and payables to affiliates, net
Inventories
Accounts payable and accrued expenses
Income taxes
Pension and non-pension postretirement benefit contributions
Other assets and liabilities
Net cash flows provided by operating activities
Cash flows from investing activities
Capital expenditures
Other investing activities
Net cash flows used in investing activities
Cash flows from financing activities
Change in short-term borrowings
Proceeds from short-term borrowings with maturities greater than 90 days
Repayments of short-term borrowings with maturities greater than 90 days
Issuance of long-term debt
Retirement of long-term debt
Dividends paid on common stock
Contributions from parent
Other financing activities
Net cash flows provided by financing activities
Increase (decrease) in cash, restricted cash, and cash equivalents
Cash, restricted cash, and cash equivalents at beginning of period
Cash, restricted cash, and cash equivalents at end of period
Supplemental cash flow information
Increase (decrease) in capital expenditures not paid
For the Years Ended December 31,
2020
2019
2018
$
112 $
99 $
180
(37)
36
(55)
6
(3)
5
(1)
(2)
(42)
199
(401)
6
(395)
117
—
—
123
(44)
(114)
117
(1)
198
2
28
30 $
157
3
22
(13)
(6)
(1)
26
2
(1)
(27)
261
(375)
(1)
(376)
56
—
(125)
150
(18)
(124)
175
(1)
113
(2)
30
28 $
75
136
25
24
(8)
1
(4)
(7)
(2)
(6)
(6)
228
(335)
1
(334)
(94)
125
—
350
(281)
(59)
67
(3)
105
(1)
31
30
$
$
33 $
(29) $
46
See the Combined Notes to Consolidated Financial Statements
220
Table of Contents
Atlantic City Electric Company and Subsidiary Company
Consolidated Balance Sheets
(In millions)
Current assets
ASSETS
Cash and cash equivalents
Restricted cash and cash equivalents
Accounts receivable
Customer accounts receivable
Customer allowance for credit losses
Customer accounts receivable, net
Other accounts receivable
Other allowance for credit losses
Other accounts receivable, net
Receivables from affiliates
Inventories, net
Regulatory assets
Other
Total current assets
Property, plant, and equipment, (net of accumulated depreciation and amortization of $1,303 and
$1,210 as of December 31, 2020 and 2019, respectively)
Deferred debits and other assets
Regulatory assets
Prepaid pension asset
Other
Total deferred debits and other assets
Total assets
(a)
December 31,
2020
2019
$
156
(32)
72
(11)
$
17 $
3
121
(13)
53
(5)
124
61
6
37
75
3
326
3,475
395
40
50
485
4,286 $
12
2
108
48
4
34
57
5
270
3,190
368
52
53
473
3,933
See the Combined Notes to Consolidated Financial Statements
221
Table of Contents
Atlantic City Electric Company and Subsidiary Company
Consolidated Balance Sheets
(In millions)
Current liabilities
LIABILITIES AND SHAREHOLDER'S EQUITY
December 31,
2020
2019
Short-term borrowings
Long-term debt due within one year
Accounts payable
Accrued expenses
Payables to affiliates
Customer deposits
Regulatory liabilities
Other
Total current liabilities
Long-term debt
Deferred credits and other liabilities
Deferred income taxes and unamortized investment tax credits
Non-pension postretirement benefit obligations
Regulatory liabilities
Other
Total deferred credits and other liabilities
Total liabilities
(a)
Commitments and contingencies
Shareholder's equity
Common stock ($3 par value, 25 shares authorized, 9 shares outstanding at December 31, 2020 and
2019)
Retained earnings
Total shareholder's equity
Total liabilities and shareholder's equity
$
$
187 $
261
177
46
31
23
44
11
780
1,152
624
17
274
48
963
2,895
1,271
120
1,391
4,286 $
70
20
144
42
25
25
25
9
360
1,307
577
17
357
39
990
2,657
1,154
122
1,276
3,933
_____________
(a)
ACE’s consolidated assets include $13 million and $17 million at December 31, 2020 and 2019, respectively, of ACE’s consolidated VIE that can only be used to settle the
liabilities of the VIE. ACE’s consolidated liabilities include $21 million and $41 million at December 31, 2020 and 2019, respectively, of ACE’s consolidated VIE for which
the VIE creditors do not have recourse to ACE. See Note 23 - Variable Interest Entities for additional information.
See the Combined Notes to Consolidated Financial Statements
222
Table of Contents
(In millions)
Balance, December 31, 2017
Net income
Common stock dividends
Contributions from parent
Balance, December 31, 2018
Net income
Common stock dividends
Contributions from parent
Balance, December 31, 2019
Net income
Common stock dividends
Contributions from parent
Balance, December 31, 2020
Atlantic City Electric Company and Subsidiary Company
Consolidated Statements of Changes in Shareholder's Equity
Common Stock
Retained Earnings
Total Shareholder's Equity
$
$
$
$
912 $
—
—
67
979 $
—
—
175
1,154 $
—
—
117
1,271 $
131 $
75
(59)
—
147 $
99
(124)
—
122 $
112
(114)
—
120 $
1,043
75
(59)
67
1,126
99
(124)
175
1,276
112
(114)
117
1,391
See the Combined Notes to Consolidated Financial Statements
223
Table of Contents
Combined Notes to Consolidated Financial Statements
(Dollars in millions, except per share data unless otherwise noted)
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 Registrant
Exelon Generation
Company, LLC
Commonwealth Edison
Company
Business
Service Territories
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
Purchase and regulated retail sale of electricity
Northern Illinois, including the City of Chicago
PECO Energy Company
Purchase and regulated retail sale of electricity and natural gas
Transmission and distribution of electricity to retail customers
Transmission and distribution of electricity and distribution of natural gas to retail
customers
Purchase and regulated retail sale of electricity and natural gas
Transmission and distribution of electricity and distribution of natural gas to retail
customers
Utility services holding company engaged, through its reportable segments Pepco,
DPL, and ACE
Southeastern Pennsylvania, including the City of Philadelphia
(electricity)
Pennsylvania counties surrounding the City of Philadelphia (natural gas)
Central Maryland, including the City of Baltimore (electricity and natural
gas)
Service Territories of Pepco, DPL, and ACE
Purchase and regulated retail sale of electricity
Transmission and distribution of electricity to retail customers
District of Columbia, and major portions of Montgomery and Prince
George’s Counties, Maryland.
Purchase and regulated retail sale of electricity and natural gas
Portions of Delaware and Maryland (electricity)
Baltimore Gas and Electric
Company
Pepco Holdings LLC
Potomac Electric
Power Company
Delmarva Power & Light
Company
Atlantic City Electric Company
Purchase and regulated retail sale of electricity
Transmission and distribution of electricity to retail customers
Portions of Southern New Jersey
Transmission and distribution of electricity and distribution of natural gas to retail
customers
Portions of New Castle County, Delaware (natural gas)
Basis of Presentation (All Registrants)
This is a combined annual 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.
Exelon owns 100% of Generation, PECO, BGE, and PHI and more than 99% of ComEd. PHI owns 100% of Pepco, DPL, and ACE. Generation owns 100%
of its significant consolidated subsidiaries, either directly or
224
Table of Contents
Combined Notes to Consolidated Financial Statements
(Dollars in millions, except per share data unless otherwise noted)
Note 1 — Significant Accounting Policies
indirectly, except for certain consolidated VIEs, including CENG and EGRP, of which Generation holds a 50.01% and 51% interest, respectively. The
remaining interests in these consolidated VIEs are included in noncontrolling interests on Exelon’s and Generation’s Consolidated Balance Sheets. See Note
23 — Variable Interest Entities for additional information of Exelon’s and Generation’s consolidated VIEs.
The Registrants consolidate the accounts of entities in which a Registrant has a controlling financial interest, after the elimination of intercompany
transactions. Where the Registrants do not have a controlling financial interest in an entity, proportionate consolidation, equity method accounting, or
accounting for investments in equity securities with or without readily determinable fair value is applied. The Registrants apply proportionate consolidation
when they have an undivided interest in an asset and are proportionately liable for their share of each liability associated with the asset. The Registrants
proportionately consolidate their undivided ownership interests in jointly owned electric plants and transmission facilities. Under proportionate consolidation,
the Registrants separately record their proportionate share of the assets, liabilities, revenues, and expenses related to the undivided interest in the asset.
The Registrants apply equity method accounting when they have significant influence over an investee through an ownership in common stock, which
generally approximates a 20% to 50% voting interest. The Registrants apply equity method accounting to certain investments and joint ventures. Under
equity method accounting, the Registrants report their interest in the entity as an investment and the Registrants’ percentage share of the earnings from the
entity as single line items in their financial statements. The Registrants use accounting for investments in equity securities with or without readily
determinable fair values if they lack significant influence, which generally results when they hold less than 20% of the common stock of an entity. Under
accounting for investments in equity securities with readily determinable fair values, the Registrants report their investment values based on quoted prices in
active markets and realized and unrealized gains and losses are included in earnings. Under accounting for investments in equity securities without readily
determinable fair values, the Registrants report their investments at cost adjusted for changes from observable transactions for identical or similar
investments of the same issuer, less impairment, and changes in measurement are reported in earnings.
The accompanying consolidated financial statements have been prepared in accordance with GAAP for annual financial statements and in accordance with
the instructions to Form 10-K and Regulation S-X promulgated by the SEC.
COVID-19 (All Registrants)
The Registrants have taken steps to mitigate the potential risks posed by the global outbreak (pandemic) of the 2019 novel coronavirus (COVID-19). The
Registrants provide a critical service to their customers and have taken measures to keep employees who operate the business safe and minimize
unnecessary risk of exposure to the virus, including extra precautions for employees who work in the field. The Registrants have implemented work from
home policies where appropriate 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 of the date of the financial statements and accompanying notes, 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, including, but not limited to, the Registrants' allowance for credit losses and the carrying value of goodwill and other long-lived assets, in context
with the information reasonably available to the Registrants and the unknown future impacts of COVID-19 as of December 31, 2020 and through the date of
this report. The Registrants' future assessment of their current expectations of the magnitude and duration of COVID-19, as well as other factors, could
result in material impacts to their consolidated financial statements in future reporting periods.
Use of Estimates (All Registrants)
The preparation of financial statements of each of the Registrants in conformity with GAAP requires management to make estimates and assumptions that
affect the amounts reported in the financial statements and accompanying notes. Areas in which significant estimates have been made include, but are not
limited to, the accounting for nuclear decommissioning costs and other AROs, pension and OPEB, inventory reserves, allowance for credit losses, goodwill
and asset impairment assessments, derivative instruments, unamortized
225
Table of Contents
Combined Notes to Consolidated Financial Statements
(Dollars in millions, except per share data unless otherwise noted)
Note 1 — Significant Accounting Policies
energy contracts, fixed asset depreciation, environmental costs and other loss contingencies, taxes, and unbilled energy revenues. Actual results could differ
from those estimates.
Accounting for the Effects of Regulation (Exelon and the Utility Registrants)
For their regulated electric and gas operations, Exelon and the Utility Registrants reflect the effects of cost-based rate regulation in their financial statements,
which is required for entities with regulated operations that meet the following criteria: 1) rates are established or approved by a third-party regulator;
(2) rates are designed to recover the entities’ cost of providing services or products; and (3) there is a reasonable expectation that rates designed to recover
costs can be charged to and collected from customers. Exelon and the Utility Registrants account for their regulated operations in accordance with
regulatory and legislative guidance from the regulatory authorities having jurisdiction, principally the ICC, PAPUC, MDPSC, DCPSC, DPSC, and NJBPU,
under state public utility laws and the FERC under various Federal laws. Regulatory assets and liabilities are amortized and the related expense or revenue
is recognized in the Consolidated Statements of Operations consistent with the recovery or refund included in customer rates. Exelon's regulatory assets
and liabilities as of the balance sheet date are probable of being recovered or settled in future rates. If a separable portion of the Registrants' business was
no longer able to meet the criteria discussed above, the affected entities would be required to eliminate from their consolidated financial statements the
effects of regulation for that portion, which could have a material impact on their financial statements. See Note 3 — Regulatory Matters for additional
information.
With the exception of income tax-related regulatory assets and liabilities, Exelon and the Utility Registrants classify regulatory assets and liabilities with a
recovery or settlement period greater than one year as both current and non-current in their Consolidated Balance Sheets, with the current portion
representing the amount expected to be recovered from or refunded to customers over the next twelve-month period as of the balance sheet date. Income
tax-related regulatory assets and liabilities are classified entirely as non-current in Exelon's and the Utility Registrants’ Consolidated Balance Sheets to align
with the classification of the related deferred income tax balances.
Exelon and the Utility Registrants treat the impacts of a final rate order received after the balance sheet date but prior to the issuance of the financial
statements as a non-recognized subsequent event, as the receipt of a final rate order is a separate and distinct event that has future impacts on the parties
affected by the order.
Revenues (All Registrants)
Operating Revenues. The Registrants’ operating revenues generally consist of revenues from contracts with customers involving the sale and delivery of
energy commodities and related products and services, utility revenues from ARP, and realized and unrealized revenues recognized under mark-to-market
energy commodity derivative contracts. The Registrants recognize revenue from contracts with customers to depict the transfer of goods or services to
customers in 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 natural gas tariff sales, distribution, and transmission services. At the end of each month, the Registrants accrue an estimate for the
unbilled amount of energy delivered or services provided to customers.
ComEd records ARP revenue for its best estimate of the electric distribution, energy efficiency, and transmission revenue impacts resulting from future
changes in rates that ComEd believes are probable of approval by the ICC and FERC in accordance with its formula rate mechanisms. BGE, Pepco, and
DPL record ARP revenue for their best estimate of the electric and natural gas distribution revenue impacts resulting from future changes in rates that they
believe are probable of approval by the MDPSC and/or DCPSC in accordance with their revenue decoupling mechanisms. PECO, BGE, Pepco, DPL, and
ACE record ARP revenue for their best estimate of the transmission revenue impacts resulting from future changes in rates that they believe are probable of
approval by FERC in accordance with their formula rate mechanisms. See Note 3 — Regulatory Matters for additional information.
Option Contracts, Swaps, and Commodity Derivatives. Certain option contracts and swap arrangements that meet the definition of derivative instruments
are recorded at fair value with subsequent changes in fair value recognized as revenue or expense. The classification of revenue or expense is based on the
intent of the transaction. To the extent a Utility Registrant receives full cost recovery for energy procurement and related costs from retail customers, it
records the fair value of its energy swap contracts with unaffiliated suppliers as well as
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Note 1 — Significant Accounting Policies
an offsetting regulatory asset or liability in its Consolidated Balance Sheets. See Note 3 — Regulatory Matters and Note 16 — Derivative Financial
Instruments for additional information.
Taxes Directly Imposed on Revenue-Producing Transactions. The Registrants collect certain taxes from customers such as sales and gross receipts
taxes, along with other taxes, surcharges, and fees, that are levied by state or local governments on the sale or distribution of electricity and gas. Some of
these taxes are imposed on the customer, but paid by the Registrants, while others are imposed on the Registrants. Where these taxes are imposed on the
customer, such as sales taxes, they are reported on a net basis with no impact to the Consolidated Statements of Operations and Comprehensive Income.
However, where these taxes are imposed on the Registrants, such as gross receipts taxes or other surcharges or fees, they are reported on a gross basis.
Accordingly, revenues are recognized for the taxes collected from customers along with an offsetting expense. See Note 24 — Supplemental Financial
Information for Generation’s and the Utility Registrants' utility taxes that are presented on a gross basis.
Leases (All Registrants)
The Registrants adopted new accounting guidance issued by the FASB related to leases as of January 1, 2019. The Registrants recognize a ROU asset and
lease liability for operating and finance leases with a term of greater than one year. Operating lease ROU assets are included in Other deferred debits and
other assets and operating lease liabilities are included in Other current liabilities and Other deferred credits and other liabilities on the Consolidated Balance
Sheets. Finance lease ROU assets are included in Plant, property, and equipment, net and finance lease liabilities are included in Long-term debt due within
one year and Long-term debt on the Consolidated Balance Sheets. The ROU asset is measured as the sum of (1) the present value of all remaining fixed
and in-substance fixed payments using each Registrant’s incremental borrowing rate, (2) any lease payments made at or before the commencement date
(less any lease incentives received), and (3) any initial direct costs incurred. The lease liability is measured the same as the ROU asset, but excludes any
payments made before the commencement date and initial direct costs incurred. Lease terms include options to extend or terminate the lease if it is
reasonably certain they will be exercised. The Registrants include non-lease components for most asset classes, which are service-related costs that are not
integral to the use of the asset, in the measurement of the ROU asset and lease liability.
Expense for operating leases and leases with a term of one year or less is recognized on a straight-line basis over the term of the lease, unless another
systematic and rational basis is more representative of the derivation of benefit from use of the leased property. Variable lease payments are recognized in
the period in which the related obligation is incurred and consist primarily of payments for purchases of electricity under contracted generation and are based
on the electricity produced by those generating assets. Operating lease expense and variable lease payments are recorded to Purchased power and fuel
expense for contracted generation or Operating and maintenance expense for all other lease agreements on the Registrants’ Statements of Operations and
Comprehensive Income. Expense for finance leases is primarily recorded to Operating and maintenance on the Utility Registrants’ Statements of Operations
and Comprehensive Income.
Income from operating leases, including subleases, is recognized on a straight-line basis over the term of the lease, unless another systematic and rational
basis is more representative of the pattern in which income is earned over the term of the lease. Variable lease payments are recognized in the period in
which the related obligation is performed and consist primarily of payments received from sales of electricity under contracted generation and are based on
the electricity produced by those generating assets. Operating lease income and variable lease payments are recorded to Operating revenues on the
Registrants’ Statements of Operations and Comprehensive Income.
The Registrants’ operating and finance leases consist primarily of contracted generation, real estate including office buildings, and vehicles and equipment.
The Registrants generally account for contracted generation in which the generating asset is not renewable as a lease if the customer has dispatch rights
and obtains substantially all of the economic benefits. For new agreements entered after January 1, 2019, the Registrants generally do not account for
contracted generation in which the generating asset is renewable as a lease if the customer does not design the generating asset. The Registrants account
for land right arrangements that provide for exclusive use as leases while shared use land arrangements are generally not leases. The Registrants do not
account for secondary use pole attachments as leases.
See Note 11 — Leases for additional information.
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(Dollars in millions, except per share data unless otherwise noted)
Note 1 — Significant Accounting Policies
Income Taxes (All Registrants)
Deferred Federal and state income taxes are recorded on significant temporary differences between the book and tax basis of assets and liabilities and for
tax benefits carried forward. Investment tax credits have been deferred in the Registrants’ Consolidated Balance Sheets and are recognized in book income
over the life of the related property. The Registrants account for uncertain income tax positions using a benefit recognition model with a two-step approach; a
more-likely-than-not recognition criterion; and a measurement approach that measures the position as the largest amount of tax benefit that is greater than
50% likely of being realized upon ultimate settlement. If it is not more-likely-than-not that the benefit of the tax position will be sustained on its technical
merits, no benefit is recorded. Uncertain tax positions that relate only to timing of when an item is included on a tax return are considered to have met the
recognition threshold. The Registrants recognize accrued interest related to unrecognized tax benefits in Interest expense, net or Other, net (interest income)
and recognize penalties related to unrecognized tax benefits in Other, net in their Consolidated Statements of Operations and Comprehensive Income.
Cash and Cash Equivalents (All Registrants)
The Registrants consider investments purchased with an original maturity of three months or less to be cash equivalents.
Restricted Cash and Cash Equivalents (All Registrants)
Restricted cash and cash equivalents represent funds that are restricted to satisfy designated current liabilities. As of December 31, 2020 and 2019, the
Registrants' restricted cash and cash equivalents primarily represented the following items:
Registrant
Exelon
Generation
ComEd
PECO
BGE
PHI
Pepco
DPL
ACE
Description
Payment of medical, dental, vision, and long-term disability benefits, in addition to the items listed for Generation and the Utility Registrants.
Project-specific nonrecourse financing structures for debt service and financing of operations of the underlying entities.
Collateral held from suppliers associated with energy and REC procurement contracts, any over-recovered RPS costs and alternative compliance
payments received from RES pursuant to FEJA, and costs for the remediation of an MGP site.
Proceeds from the sales of assets that were subject to PECO’s mortgage indenture.
Proceeds from the loan program for the completion of certain energy efficiency measures and collateral held from energy suppliers.
Payment of merger commitments, collateral held from its energy suppliers associated with procurement contracts, and repayment of Transition
Bonds.
Payment of merger commitments and collateral held from energy suppliers.
Collateral held from energy suppliers.
Repayment of Transition Bonds and collateral held from energy suppliers.
Restricted cash and cash equivalents not available to satisfy current liabilities are classified as noncurrent assets. As of December 31, 2020 and 2019, the
Registrants' noncurrent restricted cash and cash equivalents primarily represented ComEd’s over-recovered RPS costs and alternative compliance
payments received from RES pursuant to FEJA and costs for the remediation of an MGP site, and ACE’s repayment of Transition Bonds.
See Note 24 — Supplemental Financial Information for additional information.
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
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Note 1 — Significant Accounting Policies
exercise of collateral calls. The allowance for credit losses for Generation wholesale customers 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 recorded in Operating and maintenance expense
on Generation’s Consolidated Statements of Operations and Comprehensive Income.
The allowance for credit losses for the Utility Registrants’ customers is developed by applying loss rates for each Utility Registrant, based on historical loss
experience, current conditions, and forward-looking risk factors, to the outstanding receivable balance by customer risk segment. Utility Registrants'
customer accounts are written off consistent with approved regulatory requirements. Adjustments to the allowance for credit losses are primarily recorded to
Operating and maintenance expense on the Utility Registrants' Consolidated Statements of Operations and Comprehensive Income or Regulatory assets
and liabilities on the Utility Registrants' Consolidated Balance Sheets. See Note 3 - Regulatory Matters for additional information regarding the regulatory
recovery of credit losses on customer accounts receivable.
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.
Variable Interest Entities (Exelon, Generation, PHI, and ACE)
Exelon accounts for its investments in and arrangements with VIEs based on the following specific requirements:
•
•
•
requires an entity to qualitatively assess whether it should consolidate a VIE based on whether the entity has a controlling financial interest,
requires an ongoing reconsideration of this assessment instead of only upon certain triggering events, and
requires the entity that consolidates a VIE (the primary beneficiary) to disclose (1) the assets of the consolidated VIE, if they can be used to only
settle specific obligations of the consolidated VIE, and (2) the liabilities of a consolidated VIE for which creditors do not have recourse to the general
credit of the primary beneficiary.
See Note 23 — Variable Interest Entities for additional information.
Inventories (All Registrants)
Inventory is recorded at the lower of weighted average cost or net realizable value. Provisions are recorded for excess and obsolete inventory. Fossil fuel,
materials and supplies, and emissions allowances are generally included in inventory when purchased. Fossil fuel and emissions allowances are expensed
to purchased power and fuel expense when used or sold. Materials and supplies generally includes transmission, distribution, and generating plant materials
and are expensed to operating and maintenance or capitalized to property, plant, and equipment, as appropriate, when installed or used.
Debt and Equity Security Investments (Exelon and Generation)
Debt Security Investments. Debt securities are reported at fair value and classified as available-for-sale securities. Unrealized gains and losses, net of tax,
are reported in OCI.
Equity Security Investments without Readily Determinable Fair Values. Exelon has certain equity securities without readily determinable fair
values. Exelon has elected to use the practicability exception to measure these investments, defined as cost adjusted for changes from observable
transactions for identical or similar investments of the same issuer, less impairment. Changes in measurement are reported in earnings.
Equity Security Investments with Readily Determinable Fair Values. Exelon has certain equity securities with readily determinable fair values. For equity
securities held in NDT funds, realized and unrealized gains and losses, net of tax, on Generation’s NDT funds associated with the Regulatory Agreement
Units are included in regulatory liabilities at Exelon, ComEd, and PECO, in Noncurrent payables to affiliates at Generation and in
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Note 1 — Significant Accounting Policies
Noncurrent receivables from affiliates at ComEd and PECO. Realized and unrealized gains and losses, net of tax, on Generation’s NDT funds associated
with the Non-Regulatory Agreement Units are included in earnings at Exelon and Generation. Exelon's and Generation's NDT funds are classified as current
or noncurrent assets, depending on the timing of the decommissioning activities and income taxes on trust earnings. For all other equity securities with
readily determinable fair values, realized and unrealized gains and losses are included in earnings at Exelon and Generation. See Note 3 — Regulatory
Matters for additional information regarding ComEd’s and PECO’s regulatory assets and liabilities and Note 18 — Fair Value of Financial Assets and
Liabilities and Note 10 — Asset Retirement Obligations for additional information.
Property, Plant, and Equipment (All Registrants)
Property, plant, and equipment is recorded at original cost. Original cost includes construction-related direct labor and material costs. The Utility Registrants
also include indirect construction costs including labor and related costs of departments associated with supporting construction activities. When appropriate,
original cost also includes capitalized interest for Generation, Exelon Corporate, and PHI and AFUDC for regulated property at the Utility Registrants. The
cost of repairs and maintenance, including planned major maintenance activities and minor replacements of property, is charged to Operating and
maintenance expense as incurred.
Third parties reimburse the Utility Registrants for all or a portion of expenditures for certain capital projects. Such contributions in aid of construction costs
(CIAC) are recorded as a reduction to Property, plant, and equipment, net. DOE SGIG and other funds reimbursed to the Utility Registrants have been
accounted for as CIAC.
For Generation, upon retirement, the cost of property is generally charged to accumulated depreciation in accordance with the composite and group
methods of depreciation. Upon replacement of an asset, the costs to remove the asset, net of salvage, are capitalized to gross plant when incurred as part of
the cost of the newly-installed asset and recorded to depreciation expense over the life of the new asset. Removal costs, net of salvage, incurred for property
that will not be replaced is charged to Operating and maintenance expense as incurred.
For the Utility Registrants, upon retirement, the cost of property, net of salvage, is charged to accumulated depreciation consistent with the composite and
group methods of depreciation. Depreciation expense at ComEd, BGE, Pepco, DPL, and ACE includes the estimated cost of dismantling and removing plant
from service upon retirement. Actual incurred removal costs are applied against a related regulatory liability or recorded to a regulatory asset if in excess of
previously collected removal costs. PECO’s removal costs are capitalized to accumulated depreciation when incurred and recorded to depreciation expense
over the life of the new asset constructed consistent with PECO’s regulatory recovery method.
Capitalized Software. Certain costs, such as design, coding, and testing incurred during the application development stage of software projects that are
internally developed or purchased for operational use are capitalized within Property, plant, and equipment. Similar costs incurred for cloud-based solutions
treated as service arrangements are capitalized within Other Current Assets and Deferred Debits and Other Assets. Such capitalized amounts are amortized
ratably over the expected lives of the projects when they become operational, generally not to exceed five years. Certain other capitalized software costs are
being amortized over longer lives based on the expected life or pursuant to prescribed regulatory requirements.
Capitalized Interest and AFUDC. During construction, Exelon and Generation capitalize the costs of debt funds used to finance non-regulated construction
projects. Capitalization of debt funds is recorded as a charge to construction work in progress and as a non-cash credit to interest expense.
AFUDC is the cost, during the period of construction, of debt and equity funds used to finance construction projects for regulated operations. AFUDC is
recorded to construction work in progress and as a non-cash credit to an allowance that is included in interest expense for debt-related funds and other
income and deductions for equity-related funds. The rates used for capitalizing AFUDC are computed under a method prescribed by regulatory authorities.
See Note 8 — Property, Plant, and Equipment, Note 9 — Jointly Owned Electric Utility Plant and Note 24 — Supplemental Financial Information for
additional information regarding property, plant and equipment.
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Note 1 — Significant Accounting Policies
Nuclear Fuel (Exelon and Generation)
The cost of nuclear fuel is capitalized within Property, plant, and equipment and charged to fuel expense using the unit-of-production method. Any potential
future SNF disposal fees will be expensed through fuel expense. Additionally, certain on-site SNF storage costs are being reimbursed by the DOE since a
DOE (or government-owned) long-term storage facility has not been completed. See Note 19 — Commitments and Contingencies for additional information
regarding the cost of SNF storage and disposal.
Nuclear Outage Costs (Exelon and Generation)
Costs associated with nuclear outages, including planned major maintenance activities, are expensed to Operating and maintenance expense or capitalized
to Property, plant, and equipment (based on the nature of the activities) in the period incurred.
Depreciation and Amortization (All Registrants)
Except for the amortization of nuclear fuel, depreciation is generally recorded over the estimated service lives of property, plant, and equipment on a straight-
line basis using the group, composite or unitary methods of depreciation. The group approach is typically for groups of similar assets that have
approximately the same useful lives and the composite approach is used for dissimilar assets that have different lives. Under both methods, a reporting
entity depreciates the assets over the average life of the assets in the group. ComEd, BGE, Pepco, DPL, and ACE's depreciation expense includes the
estimated cost of dismantling and removing plant from service upon retirement, which is consistent with each utility's regulatory recovery method. PECO's
removal costs are capitalized to accumulated depreciation when incurred, and recorded to depreciation expense over the life of the new asset constructed
consistent with PECO's regulatory recovery method. The estimated service lives for the Registrants are based on a combination of depreciation studies,
historical retirements, site licenses, and management estimates of operating costs and expected future energy market conditions. See Note 7 — Early Plant
Retirements for additional information on the impacts of early plant retirements.
See Note 8 — Property, Plant, and Equipment for additional information regarding depreciation.
Amortization of regulatory assets and liabilities are recorded over the recovery or refund period specified in the related legislation or regulatory order or
agreement. When the recovery or refund period is less than one year, amortization is recorded to the line item in which the deferred cost or income would
have originally been recorded in the Utility Registrants’ Consolidated Statements of Operations and Comprehensive Income. Amortization of ComEd’s
electric distribution and energy efficiency formula rate regulatory assets and the Utility Registrants' transmission formula rate regulatory assets is recorded to
Operating revenues.
Amortization of income tax related regulatory assets and liabilities is generally recorded to Income tax expense. With the exception of the regulatory assets
and liabilities discussed above, when the recovery period is more than one year, the amortization is generally recorded to Depreciation and amortization in
the Registrants’ Consolidated Statements of Operations and Comprehensive Income.
See Note 3 — Regulatory Matters and Note 24 — Supplemental Financial Information for additional information regarding Generation’s nuclear fuel and
ARC, and the amortization of the Utility Registrants' regulatory assets.
Asset Retirement Obligations (All Registrants)
Generation estimates and recognizes a liability for its legal obligation to perform asset retirement activities even though the timing and/or methods of
settlement may be conditional on future events. Generation generally updates its nuclear decommissioning ARO annually, unless circumstances warrant
more frequent updates, based on its annual evaluation of cost escalation factors and probabilities assigned to the multiple outcome scenarios within its
probability-weighted discounted cash flow models. Generation’s multiple outcome scenarios are generally based on decommissioning cost studies which are
updated, on a rotational basis, for each of Generation’s nuclear units at least every five years, unless circumstances warrant more frequent updates. AROs
are accreted throughout each year to reflect the time value of money for these present value obligations through a charge to Operating and maintenance
expense in the Consolidated Statements of Operations and Comprehensive Income for Non-Regulatory Agreement Units and through a decrease to
regulatory liabilities for Regulatory Agreement Units or, in the case of the Utility Registrants' accretion, through an increase to regulatory assets. See Note 10
— Asset Retirement Obligations for additional information.
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Note 1 — Significant Accounting Policies
Guarantees (All Registrants)
If necessary, the Registrants recognize a liability at the time of issuance of a guarantee for the fair market value of the obligations they have undertaken by
issuing the guarantee. The liability is reduced or eliminated as the Registrants are released from risk under the guarantee. Depending on the nature of the
guarantee, the release from risk of the Registrant may be recognized only upon the expiration or settlement of the guarantee or by a systematic and rational
amortization method over the term of the guarantee. See Note 19 — Commitments and Contingencies for additional information.
Asset Impairments
Long-Lived Assets (All Registrants). The Registrants regularly monitor and evaluate the carrying value of long-lived assets and asset groups for
recoverability whenever events or changes in circumstances indicate that the carrying value of those assets may not be recoverable. Indicators of
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 and 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. See Note 12 — Asset Impairments for additional information.
Goodwill (Exelon, ComEd, and PHI). Goodwill represents the excess of the purchase price paid over the estimated fair value of the net assets acquired
and liabilities assumed in the acquisition of a business. Goodwill is not amortized, but is assessed for impairment at least annually or on an interim basis if an
event occurs or circumstances change that would more likely than not reduce the fair value of a reporting unit below its carrying value. See Note 13 —
Intangible Assets for additional information.
Equity Method Investments (Exelon and Generation). Exelon and Generation regularly monitor and evaluate equity method investments to determine
whether they are impaired. An impairment is recorded when the investment has experienced a decline in value that is other-than-temporary in nature.
Additionally, if the entity in which Generation holds an investment recognizes an impairment loss, Exelon and Generation would record their proportionate
share of that impairment loss and evaluate the investment for an other-than-temporary decline in value.
Debt Security Investments (Exelon and Generation). Declines in the fair value of debt security investments below the cost basis are reviewed
to determine if such declines are other-than-temporary. If the decline is determined to be other-than-temporary, the amount of the impairment loss is included
in earnings.
Equity Security Investments (Exelon and Generation). Equity investments with readily determinable fair values are measured and recorded at fair value
with any changes in fair value recorded through earnings. Investments in equity securities without readily determinable fair values are qualitatively assessed
for impairment each reporting period. If it is determined that the equity security is impaired on the basis of the qualitative assessment, an impairment loss will
be recognized in earnings to the amount by which the security’s carrying amount exceeds its fair value.
Derivative Financial Instruments (All Registrants)
All derivatives are recognized on the balance sheet at their fair value unless they qualify for certain exceptions, including the NPNS. For derivatives intended
to serve as economic hedges, changes in fair value are recognized in earnings each period. Amounts classified in earnings are included in Operating
revenue, Purchased power and fuel, Interest expense, or Other, net in the Consolidated Statements of Operations and Comprehensive Income based on the
activity the transaction is economically hedging. While the majority of the derivatives serve as economic hedges, there are also derivatives entered into for
proprietary trading purposes, subject to Exelon’s Risk Management Policy, and changes in the fair value of those derivatives are recorded in revenue in the
Consolidated Statements of Operations and Comprehensive Income. At the Utility Registrants, changes in fair value may be recorded as a regulatory asset
or liability if there is an ability to recover or return the associated costs. Cash inflows and outflows related to derivative instruments are included as a
component of operating, investing, or financing cash flows in the Consolidated Statements of Cash Flows, depending on the nature of each transaction. On
July 1, 2018, Exelon and Generation de-designated its fair value and cash flow
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Note 1 — Significant Accounting Policies
hedges. See Note 3 — Regulatory Matters and Note 16 — Derivative Financial Instruments for additional information.
As part of Generation’s energy marketing business, Generation enters into contracts to buy and sell energy to meet the requirements of its customers. These
contracts include short-term and long-term commitments to purchase and sell energy and energy-related products in the energy markets with the intent and
ability to deliver or take delivery of the underlying physical commodity. NPNS are contracts where physical delivery is probable, quantities are expected to be
used or sold in the normal course of business over a reasonable period of time and will not be financially settled. Revenues and expenses on derivative
contracts that qualify, and are designated, as NPNS are recognized when the underlying physical transaction is completed. While these contracts are
considered derivative financial instruments, they are not required to be recorded at fair value, but rather are recorded on an accrual basis of accounting. See
Note 16 — Derivative Financial Instruments for additional information.
Retirement Benefits (All Registrants)
Exelon sponsors defined benefit pension plans and OPEB plans for essentially all current employees.
The plan obligations and costs of providing benefits under these plans are measured as of December 31. The measurement involves various factors,
assumptions, and accounting elections. The impact of assumption changes or experience different from that assumed on pension and OPEB obligations is
recognized over time rather than immediately recognized in the Consolidated Statements of Operations and Comprehensive Income. Gains or losses in
excess of the greater of ten percent of the projected benefit obligation or the MRV of plan assets are amortized over the expected average remaining service
period of plan participants. See Note 15 — Retirement Benefits for additional information.
New Accounting Standards (All Registrants)
New Accounting Standards Adopted in 2020: In 2020, the Registrants adopted the following new authoritative accounting guidance issued by the FASB.
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 is primarily applicable to Generation's and the Utility Registrants'
trade accounts receivables balances. The 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 impairment assessment
model, 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 assessment). Entities will continue to have the option to perform a qualitative assessment to determine if a quantitative impairment assessment
is necessary. The standard was effective January 1, 2020 and must be applied on a prospective basis. Exelon, ComEd, and PHI adopted the new guidance
in 2020. The new guidance did not impact Exelon's, ComEd's, and PHI's 2020 annual goodwill impairment assessments as they performed a qualitative
assessment.
2. 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 an 82% undivided ownership
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Combined Notes to Consolidated Financial Statements
(Dollars in millions, except per share data unless otherwise noted)
Note 2 — Mergers, Acquisitions, and Dispositions
interest in Nine Mile Point Unit 2. CENG is 100% consolidated in Exelon's and Generation's financial statements. See Note 23 — 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 amended 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 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. 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.
Under the terms of the Put Option Agreement, 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 obligations
under the LLC Operating Agreement and Employee Matters Agreement including but not limited to Generation’s rights with respect to any unpaid aggregate
preferred distributions and the related return. As of December 31, 2020, the total unpaid aggregate preferred distributions and related return owed to
Generation is $619 million. At this time, Generation cannot reasonably predict the ultimate purchase price that will be paid to EDF for its interest in CENG.
The transaction will require approval by the NYPSC and the FERC. The FERC approval was obtained on July 30, 2020. The process and regulatory
approvals are expected to close in the second half of 2021.
Agreement for Sale of Generation’s Solar Business (Exelon and Generation)
On December 8, 2020, Generation entered into an agreement with an affiliate of Brookfield Renewable, for the sale of a significant portion of Generation’s
solar business, including 360 megawatts of generation in operation or under construction across more than 600 sites across the United States. Under the
terms of the transaction, the purchase price is $810 million, subject to certain working capital and other post-closing adjustments. Generation will retain
certain solar assets not included in this agreement, primarily Antelope Valley.
As a result of the transaction, in the fourth quarter of 2020, Exelon and Generation reclassified the solar assets and liabilities on Exelon’s and Generation’s
Consolidated Balance Sheets as held for sale. The transaction is expected to result in an estimated pre-tax gain ranging from $75 million to $125 million.
The gain will be recorded in Gain on sales of assets and businesses in Exelon’s and Generation’s Consolidated Statements of Operations and
Comprehensive Income upon completion of the transaction. Completion of the transaction contemplated by the sale agreement is subject to the satisfaction
of several closing conditions and is expected to occur in the first half of 2021. See Note 17 — Debt and Credit Agreements for additional information on the
SolGen nonrecourse debt included as part of the transaction.
Disposition of Oyster Creek (Exelon and Generation)
On July 31, 2018, Generation entered into an agreement with Holtec and its indirect wholly owned subsidiary, OCEP, for the sale and decommissioning of
Oyster Creek located in Forked River, New Jersey, which permanently ceased generation operations on September 17, 2018. Completion of the transaction
contemplated by the sale agreement was subject to the satisfaction of several closing conditions, including approval of the license transfer from the NRC and
other regulatory approvals, and a private letter ruling from the IRS, which were satisfied in the second quarter 2019. The sale was completed on July 1,
2019. Exelon and Generation recognized a loss on the sale in the third quarter of 2019, which was immaterial.
Under the terms of the transaction, Generation transferred to OCEP substantially all the assets associated with Oyster Creek, including assets held in NDT
funds, along with the assumption of liability for all responsibility for the site, including full decommissioning and ongoing management of spent fuel until the
spent fuel is moved offsite. The terms of the transaction also include various forms of performance assurance for the obligations of OCEP to timely complete
the required decommissioning, including a parental guaranty from Holtec for all performance and payment obligations of OCEP, and a requirement for Holtec
to deliver a letter of credit to Generation upon the occurrence of specified events.
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Combined Notes to Consolidated Financial Statements
(Dollars in millions, except per share data unless otherwise noted)
Note 2 — Mergers, Acquisitions, and Dispositions
Upon remeasurement of the Oyster Creek ARO, Exelon and Generation recognized an $84 million and a $9 million pre-tax charge to Operating and
maintenance expense in 2018 and in 2019, respectively. See Note 10 — Asset Retirement Obligations for additional information.
Disposition of Electrical Contracting Business (Exelon and Generation)
On February 28, 2018, Generation completed the sale of its interest in an electrical contracting business that primarily installs, maintains, and repairs
underground and high-voltage cable transmission and distribution systems for $87 million, resulting in a pre-tax gain which is included within Gain on sales
of assets and businesses in Exelon's and Generation's Consolidated Statements of Operations and Comprehensive Income for the year ended December
31, 2018.
3. Regulatory Matters (All Registrants)
The following matters below discuss the status of material regulatory and legislative proceedings of the Registrants.
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.
Completed Distribution Base Rate Case Proceedings
Registrant/Jurisdiction
Filing Date
Service
Requested
Revenue
Requirement
(Decrease)
Increase
Approved Revenue
Requirement
(Decrease)
Increase
ComEd - Illinois
(a)
April 8, 2019
Electric
$
(6) $
ComEd - Illinois
(a)
April 16, 2020
Electric
BGE - Maryland
(b)
DPL - Maryland
DPL - Delaware
May 15, 2020
(amended September
11, 2020)
Electric
Natural Gas
December 5, 2019
(amended April 23,
2020)
February 21, 2020
(amended October 9,
2020)
Electric
Natural Gas
(11)
137
91
17
7
Approved ROE
Approval Date
8.91 % December 4, 2019
8.38 % December 9, 2020
9.50 %
9.65 %
December 16, 2020
Rate Effective
Date
January 1,
2020
January 1,
2021
January 1,
2021
9.60 %
July 14, 2020
July 16, 2020
(17)
(14)
81
21
12
2
9.60 % January 6, 2021
September
21, 2020
__________
(a) Pursuant to EIMA and FEJA, ComEd’s electric distribution rates are established through a performance-based formula, which sunsets at the end of 2022. The electric
distribution formula rate includes decoupling provisions and, as a result, ComEd's electric distribution formula rate revenues are not impacted by abnormal weather, usage
per customer, or number of customers. ComEd is required to file an annual update to its electric distribution formula rate on or before May 1 , with resulting rates effective
in January of the following year. ComEd’s annual electric distribution formula rate update is based on prior year actual costs and current year projected capital additions
(initial year revenue requirement). The update also reconciles any differences between the revenue requirement in effect for the prior year and actual costs incurred from
the year (annual reconciliation).
st
ComEd’s 2020 approved revenue requirement above reflects an increase of $51 million for the initial year revenue requirement for 2020 and a decrease of $68 million
related to the annual reconciliation for 2018. The revenue requirement for 2020 and the revenue requirement for 2018 provides for a weighted average debt and equity
return on distribution rate
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Combined Notes to Consolidated Financial Statements
(Dollars in millions, except per share data unless otherwise noted)
Note 3 — Regulatory Matters
base of 6.51% inclusive of an allowed ROE of 8.91%, reflecting the monthly average yields for 30-year treasury bonds plus 580 basis points.
ComEd’s 2021 approved revenue requirement above 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. See
table below for ComEd's regulatory assets associated with its electric distribution formula rate.
(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 in 2021, 2022, and 2023, respectively, and natural gas revenue requirement increases of $53 million, $11 million, and $10 million in 2021, 2022, and 2023,
respectively. However, the MDPSC utilized certain tax benefits to fully offset the increases in 2021 so 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 revenue requirement increases in 2022 and 2023 and BGE cannot predict the outcome.
Pending Distribution Base Rate Case Proceedings
Registrant/Jurisdiction
Filing Date
Service
Requested Revenue Requirement
Increase
PECO - Pennsylvania
Pepco - District of Columbia
(a)
Pepco - Maryland
(b)
DPL - Delaware
(c)
ACE - New Jersey
(d)
September 30, 2020
May 30, 2019 (amended
June 1, 2020)
October 26, 2020
March 6, 2020 (amended
February 2, 2021)
December 9, 2020
Natural Gas
$
Electric
Electric
Electric
Electric
69
136
110
23
67
Requested ROE
Expected Approval Timing
10.95 %
Second quarter of 2021
9.7 %
Second quarter of 2021
10.2 %
Second quarter of 2021
10.3 %
Third quarter of 2021
10.3 %
Fourth quarter of 2021
_________
(a) 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 for 2020 through
2022 and requested revenue requirement increases of $73 million in 2022 and $63 million in 2023, to recover capital investments made during 2018 through 2020 and
planned capital investments through the end of 2022.
(b) Reflects a three-year cumulative multi-year plan for April 1, 2021 through March 31, 2024 and total requested revenue requirement increases of $56 million effective April
1, 2023 and $54 million effective April 1, 2024 to recover capital investments made in 2019 and 2020 and planned capital investments through March 31, 2024.
(c) The rates went into effect on October 6, 2020, subject to refund.
(d) Requested increases are before New Jersey sales and use tax. ACE intends to put rates into effect on September 8, 2021, subject to refund.
Transmission Formula Rates (Exelon, PHI, and the Utility Registrants)
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 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).
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Combined Notes to Consolidated Financial Statements
(Dollars in millions, except per share data unless otherwise noted)
Note 3 — Regulatory Matters
For 2020, the following total increases/(decreases) were included in the Utility Registrants' electric transmission formula rate updates:
Registrant
(a)
Initial Revenue
Requirement
Increase/(Decrease)
$
ComEd
PECO
BGE
Pepco
DPL
ACE
Annual Reconciliation
Decrease
Total Revenue Requirement
Increase/(Decrease)
(b)
Allowed Return on Rate
Base
(c)
Allowed ROE
(d)
18 $
5
16
2
(4)
5
(4) $
(28)
(3)
(46)
(40)
(25)
14
(23)
4
(44)
(44)
(20)
8.17 %
7.47 %
7.26 %
7.81 %
7.20 %
7.40 %
11.50 %
10.35 %
10.50 %
10.50 %
10.50 %
10.50 %
__________
(a) All rates are effective June 30, 2020 - May 31, 2021, subject to review by interested parties pursuant to review protocols of each Utility Registrant's tariff.
(b) 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 increase 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.
(c) Represents the weighted average debt and equity return on transmission rate bases.
(d) As part of the FERC-approved settlement 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.
Other State Regulatory Matters
Illinois Regulatory Matters
Energy Efficiency Formula Rate (Exelon and ComEd). FEJA allows ComEd to defer energy efficiency costs (except for any voltage optimization costs
which are recovered through the electric distribution formula rate) as a separate regulatory asset that is recovered through the energy efficiency formula rate
over the weighted average useful life, as approved by the ICC, of the related energy efficiency measures. ComEd earns a return on the energy efficiency
regulatory asset at a rate equal to its weighted average cost of capital, which is based on a year-end capital structure and calculated using the same
methodology applicable to ComEd’s electric distribution formula rate. Beginning January 1, 2018 through December 31, 2030, the ROE that ComEd earns
on its energy efficiency regulatory asset is subject to a maximum downward or upward adjustment of 200 basis points if ComEd’s cumulative persisting
annual MWh savings falls short of or exceeds specified percentage benchmarks of its annual incremental savings goal. ComEd is required to file an update
to its energy efficiency formula rate on or before June 1 each year, with resulting rates effective in January of the following year. The annual update is
based on projected current year energy efficiency costs, PJM capacity revenues, and the projected year-end regulatory asset balance less any related
deferred income taxes (initial year revenue requirement). The update also reconciles any differences between the revenue requirement in effect for the prior
year and actual costs incurred from the year (annual reconciliation). The approved energy efficiency formula rate also provides for revenue decoupling
provisions similar to those in ComEd’s electric distribution formula rate.
st
During 2020, the ICC approved the following total increases in ComEd's requested energy efficiency revenue requirement:
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Combined Notes to Consolidated Financial Statements
(Dollars in millions, except per share data unless otherwise noted)
Note 3 — Regulatory Matters
Filing Date
Requested Revenue
Requirement Increase
Approved Revenue
Requirement Increase
Approved ROE
Approval Date
May 21, 2020
$
48 $
48
(a)
8.38 %
December 2, 2020
Rate Effective Date
January 1, 2021
_________
(a) ComEd’s 2021 approved revenue requirement above reflects an increase of $45 million for the initial year revenue requirement for 2021 and an increase of $3 million
related to the annual reconciliation for 2019. The revenue requirement for 2021 provides for a weighted average debt and equity return on the energy efficiency regulatory
asset and 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. The revenue
requirement for 2019 provides for a weighted average debt and equity return on the energy efficiency regulatory asset and rate base of 6.56% inclusive of an allowed ROE
of 8.96%, which includes an upward performance adjustment that can either increase or decrease the ROE. See table below for ComEd's regulatory assets associated with
its energy efficiency formula rate.
Maryland Regulatory Matters
The Maryland Strategic Infrastructure Development and Enhancement Program (Exelon and BGE). On December 1, 2017 (as amended on January
22, 2018), BGE filed an application with the MDPSC seeking approval for a new gas infrastructure replacement plan and associated surcharge, effective for
the five-year period from 2019 through 2023. On May 30, 2018, the MDPSC approved with modifications a new infrastructure plan and associated
surcharge, subject to BGE's acceptance of the Order. On June 1, 2018, BGE accepted the MDPSC Order and the associated surcharge became effective
January 2019. The five-year plan calls for capital expenditures over the 2019-2023 timeframe of $732 million with an associated revenue requirement of
$200 million.
Cash Working Capital Order (Exelon and BGE). On November 17, 2016, the MDPSC rendered a decision in the proceeding to review BGE’s request to
recover its cash working capital (CWC) requirement for its POLR service, also known as SOS, as well as other components that make up the Administrative
Charge, the mechanism that enables BGE to recover its SOS-related costs. The Administrative Charge is comprised of five components: CWC,
uncollectibles, incremental costs, return, and an administrative adjustment, which acts as a proxy for retail suppliers’ costs. The MDPSC accepted BGE's
positions on recovery of CWC and pass-through recovery of BGE’s actual uncollectibles and incremental costs. The order also grants BGE a return on the
SOS. Subsequently, the MDPSC Staff and residential consumer advocate sought clarification and appealed the amount of return awarded to BGE on the
SOS. On July 27, 2020, the Maryland Court of Special Appeals affirmed the circuit court’s judgment affirming the MDPSC’s decision. No party appealed the
decision to the Maryland Court of Appeals. Also, in BGE’s 2019 electric and gas distribution base rate proceeding, the MDPSC established a normalized
administrative adjustment. However, a group of electric suppliers appealed the MDPSC’s decision to the Circuit Court for Baltimore City. BGE cannot predict
the outcome of this appeal.
New Jersey Regulatory Matters
ACE Infrastructure Investment Program Filing (Exelon, PHI, and ACE). On February 28, 2018, ACE filed with the NJBPU the company’s IIP proposing to
seek recovery of a series of investments through a new rider mechanism, totaling $338 million, between 2019-2022 to provide safe and reliable service for
its customers. The IIP will allow for more timely recovery of investments made to modernize and enhance ACE’s electric system. On April 15, 2019, ACE
entered into a settlement agreement with other parties, which allows for a recovery totaling $96 million of reliability related capital investments from July 1,
2019 through June 30, 2023. On April 18, 2019, the NJBPU approved the settlement agreement.
Advanced Metering Infrastructure Filing (Exelon, PHI, and ACE). On August 26, 2020, ACE filed 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 consists 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 requisite communications facilities and data management systems. ACE is
seeking authority to recover these estimated investments through a combination of the ACE IIP rider mechanism and future distribution base rates. ACE
currently expects a decision in this matter in the third quarter of 2021 but cannot predict if the NJBPU will approve the application as filed.
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Combined Notes to Consolidated Financial Statements
(Dollars in millions, except per share data unless otherwise noted)
Note 3 — Regulatory Matters
New Jersey Clean Energy Legislation (Exelon, PHI, and ACE). On May 23, 2018, New Jersey enacted legislation that established and modified New
Jersey’s clean energy and energy efficiency programs and solar and RPS. On the same day, 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. Electric distribution utilities in New
Jersey, including ACE, began collecting from retail distribution customers, through a non-bypassable charge, all costs associated with the utility’s
procurement of the ZECs effective April 18, 2019. See Generation Regulatory Matters below for additional information.
Other Federal Regulatory Matters
Transmission-Related Income Tax Regulatory Assets (Exelon, ComEd, BGE, PHI, Pepco, DPL, and ACE). 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, FERC issued an order rejecting
BGE’s proposed revisions to its transmission formula rate to recover these transmission-related income tax regulatory assets. In the fourth quarter of 2017,
ComEd, BGE, Pepco, DPL, and ACE fully impaired their associated transmission-related income tax regulatory assets for the portion of the income tax
regulatory assets that would have been previously amortized.
On February 23, 2018 (as amended on July 9, 2018), ComEd, Pepco, DPL, 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.
On September 7, 2018, FERC issued orders rejecting 1) BGE’s rehearing request of FERC's November 16, 2017 order and 2) the 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 U.S. Court of Appeals for the D.C. Circuit. On March 27, 2020, the
U.S. Court of Appeals for the D.C. Circuit Court denied BGE’s November 2, 2018 appeal.
On October 1, 2018, ComEd, BGE, Pepco, DPL, and ACE submitted filings to recover 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, which
FERC approved on September 24, 2020. The settlement agreement provides for the recovery of ongoing transmission-related income tax regulatory assets
and establishes the amount and amortization period for excess deferred income taxes resulting from TCJA. The settlement resulted in a reduction to
Operating revenues and an offsetting reduction to Income tax expense in the second quarter of 2020.
Regulatory Assets and Liabilities
Regulatory assets represent incurred costs that have been deferred because of their probable future recovery from customers through regulated rates.
Regulatory liabilities represent the excess recovery of costs or accrued credits that have been deferred because it is probable such amounts will be returned
to customers through future regulated rates or represent billings in advance of expenditures for approved regulatory programs.
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Combined Notes to Consolidated Financial Statements
(Dollars in millions, except per share data unless otherwise noted)
Note 3 — Regulatory Matters
The following tables provide information about the regulatory assets and liabilities of Exelon, ComEd, PECO, BGE, PHI, Pepco, DPL, and ACE as of
December 31, 2020 and December 31, 2019:
December 31, 2020
Regulatory assets
Pension and OPEB
Pension and OPEB - merger related
1,014
Exelon
ComEd
PECO
BGE
PHI
Pepco
DPL
ACE
$
3,010 $
— $
— $
— $
— $
— $
— $
Deferred income taxes
AMI programs - deployment costs
AMI programs - legacy meters
Electric distribution formula rate annual
reconciliations
Electric distribution formula rate significant
one-time events
Energy efficiency costs
Fair value of long-term debt
Fair value of PHI's unamortized energy
contracts
Asset retirement obligations
MGP remediation costs
Renewable energy
Electric energy and natural gas costs
Transmission formula rate annual
reconciliations
Energy efficiency and demand response
programs
Under-recovered revenue decoupling
Stranded costs
Removal costs
DC PLUG charge
Deferred storm costs
COVID-19
Under-recovered credit loss expense
Other
Total regulatory assets
Less: current portion
715
174
219
(14)
117
982
598
328
135
285
301
95
5
572
113
25
701
100
50
81
107
274
—
—
—
90
(14)
117
982
—
—
92
271
301
—
—
—
—
—
—
—
—
22
89
78
—
705
—
—
—
—
—
—
—
21
10
—
—
—
—
—
—
—
—
—
38
—
27
9,987
1,228
2,028
279
801
25
—
—
109
37
—
—
—
—
—
18
4
—
23
2
289
20
—
107
—
—
10
—
30
649
168
—
10
65
92
—
—
—
478
328
4
—
—
72
3
283
93
25
594
100
50
11
18
147
2,373
440
—
10
35
68
—
—
—
—
—
3
—
—
37
—
203
93
—
151
100
5
7
—
72
784
214
—
—
30
24
—
—
—
—
—
—
—
—
5
2
80
—
—
105
—
4
4
—
26
280
58
Total noncurrent regulatory assets
$
8,759 $
1,749 $
776 $
481 $
1,933 $
570 $
222 $
240
—
—
—
—
—
—
—
—
—
—
1
—
—
30
1
—
—
25
339
—
41
—
18
15
470
75
395
Table of Contents
Combined Notes to Consolidated Financial Statements
(Dollars in millions, except per share data unless otherwise noted)
December 31, 2020
Regulatory liabilities
Deferred income taxes
Nuclear decommissioning
Removal costs
Electric energy and natural gas costs
Transmission formula rate annual
reconciliations
Renewable portfolio standards costs
Stranded costs
Other
Total regulatory liabilities
Less: current portion
Note 3 — Regulatory Matters
Exelon
ComEd
PECO
BGE
PHI
Pepco
DPL
ACE
$
4,502 $
2,205 $
— $
1,001 $
1,296 $
621 $
404 $
271
3,016
1,649
175
52
427
24
221
10,066
581
2,541
1,482
34
2
427
—
1
6,692
289
475
—
97
12
—
—
40
624
121
—
47
6
—
—
—
85
1,139
30
—
120
38
38
—
24
59
1,575
137
—
20
24
23
—
—
2
690
46
—
100
10
9
—
—
17
540
47
—
—
4
6
—
24
13
318
44
274
Total noncurrent regulatory liabilities
$
9,485 $
6,403 $
503 $
1,109 $
1,438 $
644 $
493 $
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December 31, 2019
Regulatory assets
Combined Notes to Consolidated Financial Statements
(Dollars in millions, except per share data unless otherwise noted)
Note 3 — Regulatory Matters
Exelon
ComEd
PECO
BGE
PHI
Pepco
DPL
ACE
Pension and OPEB
Pension and OPEB - merger related
$
2,784 $
1,138
— $
—
— $
—
— $
—
— $
—
— $
—
— $
—
Deferred income taxes
AMI programs - deployment costs
AMI programs - legacy meters
Electric distribution formula rate annual
reconciliations
Electric distribution formula rate significant
one-time events
Energy efficiency costs
Fair value of long-term debt
Fair value of PHI's unamortized energy
contracts
Asset retirement obligations
MGP remediation costs
Renewable energy
Electric energy and natural gas costs
Transmission formula rate annual
reconciliations
Energy efficiency and demand response
programs
Merger integration costs
Under-recovered revenue decoupling
Stranded costs
Removal costs
DC PLUG charge
Other
Total regulatory assets
Less: current portion
528
207
276
34
66
746
650
443
127
302
301
110
11
572
32
37
37
641
126
337
9,505
1,170
—
—
113
34
66
746
—
—
85
287
301
—
—
—
—
—
—
—
—
129
1,761
281
518
—
12
—
—
—
—
—
23
11
—
6
—
—
—
—
—
—
—
25
595
41
—
129
45
—
—
—
—
—
16
4
—
36
1
303
2
8
—
67
—
26
637
183
10
78
106
—
—
—
523
443
3
—
—
68
10
269
30
29
37
574
126
167
2,473
412
10
43
79
—
—
—
—
—
2
—
—
43
1
196
15
29
—
152
126
76
772
188
—
35
27
—
—
—
—
—
—
—
—
5
2
73
8
—
—
100
—
24
274
52
Total noncurrent regulatory assets
$
8,335 $
1,480 $
554 $
454 $
2,061 $
584 $
222 $
—
—
—
—
—
—
—
—
—
—
1
—
—
20
7
—
7
—
37
324
—
29
425
57
368
December 31, 2019
Regulatory liabilities
Deferred income taxes
Nuclear decommissioning
Removal costs
Electric energy and natural gas costs
Transmission formula rate annual
reconciliations
Other
Total regulatory liabilities
Less: current portion
Exelon
ComEd
PECO
BGE
PHI
Pepco
DPL
ACE
$
4,944 $
2,297 $
— $
1,089 $
1,558 $
725 $
477 $
356
3,102
1,621
109
34
582
10,392
406
2,622
1,435
45
6
337
6,742
200
480
—
56
28
37
601
91
—
58
—
—
81
1,228
33
—
128
8
—
83
1,777
70
—
20
—
—
9
754
8
—
108
8
—
18
611
37
—
—
—
—
26
382
25
357
Total noncurrent regulatory liabilities
$
9,986 $
6,542 $
510 $
1,195 $
1,707 $
746 $
574 $
242
Table of Contents
Combined Notes to Consolidated Financial Statements
(Dollars in millions, except per share data unless otherwise noted)
Note 3 — Regulatory Matters
Descriptions of the regulatory assets and liabilities included in the tables above are summarized below, including their recovery and amortization periods.
Line Item
Description
End Date of Remaining
Recovery/Refund Period
Return
Pension and OPEB
Primarily reflects the Utility Registrants' portion of deferred
costs, including unamortized actuarial losses (gains) and prior
service costs (credits), associated with Exelon's pension and
OPEB plans, which are recovered through customer rates
once amortized through net periodic benefit cost. Also,
includes the Utility Registrants' non–service cost components
capitalized in Property, plant and equipment, net on their
Consolidated Balance Sheets.
Pension and OPEB - merger
related
The deferred costs are amortized over the plan participants'
average remaining service periods subject to applicable
pension and OPEB cost recognition policies. See Note 15 —
Retirement Benefits for additional information. The capitalized
non–service cost components are amortized over the lives of
the underlying assets.
Deferred income taxes
Deferred income taxes that are recoverable or refundable
through customer rates, primarily associated with accelerated
depreciation, the equity component of AFUDC, and the
effects of income tax rate changes, including those resulting
from the TCJA. These amounts include transmission-related
regulatory liabilities that require FERC approval separate from
the transmission formula rate. See Transmission-Related
Income Tax Regulatory Assets section above for additional
information.
The deferred costs are
amortized over the plan
participants' average
remaining service periods
subject to applicable pension
and OPEB cost recognition
policies. See Note 15 —
Retirement Benefits for
additional information. The
capitalized non–service cost
components are amortized
over the lives of the underlying
assets.
Legacy Constellation - 2038
Legacy PHI - 2032
Over the period in which the
related deferred income taxes
reverse, which is generally
based on the expected life of
the underlying assets. For
TCJA, generally refunded over
the remaining depreciable life
of the underlying assets,
except in certain jurisdictions
where the commissions have
approved a shorter refund
period for certain assets not
subject to IRS normalization
rules.
No
No
No
243
Table of Contents
Combined Notes to Consolidated Financial Statements
(Dollars in millions, except per share data unless otherwise noted)
Note 3 — Regulatory Matters
Line Item
Description
End Date of Remaining
Recovery/Refund Period
Return
AMI programs - deployment
costs
Installation costs of new smart meters, including
implementation costs at Pepco and DPL of dynamic pricing
for energy usage resulting from smart meters.
AMI programs - legacy meters Early retirement costs of legacy meters.
BGE - 2026
Pepco - 2027
DPL - 2030
ComEd - 2028
BGE - 2026
Pepco - 2027
DPL - 2030
Yes
ComEd, Pepco (District of
Columbia), DPL (Delaware) -
Yes
BGE, Pepco (Maryland), DPL
(Maryland) - No
Electric distribution formula
rate annual reconciliations
Electric distribution formula
rate significant one-time
events
Under/(Over)-recoveries related to electric distribution service
costs recoverable through ComEd's performance-based
formula rate, which is updated annually with rates effective on
st
January 1 .
Deferred distribution service costs related to ComEd's
significant one-time events (e.g., storm costs), which are
recovered over 5 years from date of the event.
2022
2024
Energy efficiency costs
Fair value of long-term debt
Fair value of PHI’s
unamortized energy contracts
ComEd's costs recovered through the energy efficiency
formula rate tariff and the reconciliation of the difference of
the revenue requirement in effect for the prior year and the
revenue requirement based on actual prior year costs.
Deferred energy efficiency costs are recovered over the
weighted average useful life of the related energy measure.
Represents the difference between the carrying value and fair
value of long-term debt of PHI and BGE of $478 million and
$120 million, respectively, as of December 31, 2020 and
$523 million and $127 million, respectively, as of
December 31, 2019, as of the PHI and Constellation merger
dates.
2031
BGE - 2036
PHI - 2045
Represents the regulatory assets recorded at Exelon and PHI
offsetting the fair value adjustment related to Pepco's, DPL's,
and ACE's electricity and natural gas energy supply contracts
recorded at PHI as of the PHI merger date.
2036
Yes
Yes
Yes
No
No
Asset retirement obligations
Future legally required removal costs associated with existing
AROs.
Over the life of the related
assets.
Yes, once the removal
activities have been
performed.
MGP remediation costs
Environmental remediation costs for MGP sites recorded at
ComEd, PECO, and BGE.
Over the expected remediation
period. See Note 19 —
Commitments and
Contingencies for additional
information.
No
244
Table of Contents
Combined Notes to Consolidated Financial Statements
(Dollars in millions, except per share data unless otherwise noted)
Note 3 — Regulatory Matters
Line Item
Description
End Date of Remaining
Recovery/Refund Period
Return
Renewable energy
Represents the change in fair value of ComEd‘s 20-year
floating-to-fixed long-term renewable energy swap contracts.
2032
No
Electric energy and natural
gas costs
Under (over)-recoveries related to energy and gas supply
related costs recoverable (refundable) under approved rate
riders.
2025
Transmission formula rate
annual reconciliations
Under (over)-recoveries related to transmission service costs
recoverable through the Utility Registrants’ FERC formula
rates, which are updated annually with rates effective each
st
June 1 .
2022
DPL (Delaware), ACE - Yes
ComEd, PECO, BGE, Pepco,
DPL (Maryland) - No
Yes
Energy efficiency and demand
response programs
Includes under (over)-recoveries of costs incurred related to
energy efficiency programs and demand response programs
and recoverable costs associated with customer direct load
control and energy efficiency and conservation programs that
are being recovered from customers.
PECO - 2021
BGE - 2025
Pepco, DPL - 2035
BGE, Pepco, DPL - Yes
PECO - Yes on capital
investment recovered through
this mechanism
Merger integration costs
Integration costs to achieve distribution synergies related to
the Constellation merger and PHI acquisition. Costs for
Pepco (Maryland) and Pepco (District of Columbia) were
$3 million and $9 million, respectively as of December 31,
2020, which are included in Other in the table above, and
$6 million and $9 million, respectively as of December 31,
2019.
BGE - 2021
Pepco - 2021
DPL- 2026
ACE - 2022
BGE, Pepco (Maryland), DPL -
Yes
Pepco (District of Columbia),
ACE - No
Under (over)-recovered
revenue decoupling
Electric and / or gas distribution costs recoverable from or
(refundable) to customers under decoupling mechanisms.
BGE and DPL - 2021
Pepco (Maryland) - $16 million
- 2021
Pepco (District of Columbia) -
$31 million - 2021; $46 million
to be determined by the
DCPSC
BGE, Pepco, DPL - No
Stranded costs
The regulatory asset represents certain stranded costs
associated with ACE's former electricity generation business.
The regulatory liability represents overcollection of a
customer surcharge collected by ACE to fund principal and
interest payments on Transition Bonds of ACE Transition
Funding that securitized such costs.
Stranded costs - 2022
Overcollection - To be
determined by NJBPU
Stranded costs - Yes
Overcollection - No
245
Table of Contents
Combined Notes to Consolidated Financial Statements
(Dollars in millions, except per share data unless otherwise noted)
Note 3 — Regulatory Matters
Line Item
Description
End Date of Remaining
Recovery/Refund Period
Return
Removal costs
DC PLUG charge
For BGE, Pepco, DPL, and ACE, the regulatory asset
represents costs incurred to remove property, plant and
equipment in excess of amounts received from customers
through depreciation rates. For ComEd, BGE, Pepco, and
DPL, the regulatory liability represents amounts received from
customers through depreciation rates to cover the future non–
legally required cost to remove property, plant and equipment,
which reduces rate base for ratemaking purposes.
Costs associated with DC PLUG, which is a projected six
year, $500 million project to place underground some of the
District of Columbia’s most outage-prone power lines with
$250 million of the project costs funded by Pepco and
$250 million funded by the District of Columbia. Rates for the
DC PLUG initiative went into effect on February 7, 2018.
Deferred storm costs
For Pepco, DPL, and ACE amounts represent total
incremental storm restoration costs incurred due to major
storm events recoverable from customers in the Maryland
and New Jersey jurisdictions.
BGE, Pepco, DPL, and ACE -
Asset is generally recovered
over the life of the underlying
assets.
Yes
ComEd, BGE, Pepco, and
DPL - Liability is reduced as
costs are incurred.
2021 - $30 million
$70 million to be determined
based on future biennial plans
filed with the DCPSC.
Pepco - 2024
DPL - $2 million - 2025;
$2 million not currently being
recovered
ACE - $5 million - 2021;
$36 million not currently being
recovered
Portion of asset funded by
Pepco-Yes
Pepco, DPL - Yes
ACE - No
Nuclear decommissioning
Estimated future decommissioning costs for the Regulatory
Agreement Units that are less than the associated NDT fund
assets. See Note 10 — Asset Retirement Obligations for
additional information.
Not currently being refunded. No
COVID-19
See COVID-19 section below for detail on the COVID-19
regulatory asset.
ComEd - 2024
BGE - 2025
PECO, Pepco, DPL, and ACE
- Not currently being
recovered.
ComEd and BGE - Yes
PECO, Pepco, DPL, and ACE
- No
246
Table of Contents
Combined Notes to Consolidated Financial Statements
(Dollars in millions, except per share data unless otherwise noted)
Note 3 — Regulatory Matters
Line Item
Description
End Date of Remaining
Recovery/Refund Period
Return
Under (over) -recovered credit
loss expense
Renewable portfolio standards
costs
For ComEd and ACE, amounts represent the difference
between annual credit loss expense and revenues collected
in rates through ICC and NJBPU-approved riders. The
difference between net credit loss expense and revenues
collected through the rider each calendar year for ComEd is
recovered or refunded over a twelve-month period beginning
in June of the following calendar year. ACE intends to
recover/refund from June through May of each respective
year, subject to approval of the NJBPU.
Represents an overcollection of funds from both ComEd
customers and alternative retail electricity suppliers to be
spent on future renewable energy procurements. Costs were
$320 million as of December 31, 2019, which are included in
Other in the 2019 table above.
ComEd - 2023
ACE - To be determined by
NJBPU.
No
To be determined by the IPA
and ICC.
No
COVID-19 (Exelon and the Utility Registrants). Starting in March of 2020, the Utility Registrants 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. The duration and extent of these measures varies by jurisdiction. While these measures are no longer in place for some jurisdictions as of
December 31, 2020, they are expected to continue through the first quarter of 2021 in other jurisdictions. Typically, the Utility Registrants recover credit loss
expense through regulatory required programs or distribution base rate cases. ComEd and ACE have existing mechanisms for recovery of credit loss
expense. For those jurisdictions without an existing regulatory required program to recover credit loss expense, the Utility Registrants are pursuing strategies
to recover incremental costs being incurred as a result of COVID-19:
•
•
In the period of April to 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.
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.
The Utility Registrants have also incurred direct costs related to COVID-19 consisting primarily of costs to acquire personal protective equipment, costs for
cleaning supplies and services, and costs to hire healthcare professionals to monitor the health of their employees.
The Utility Registrants have recorded regulatory assets for the impacts of COVID-19 reflecting primarily incremental credit losses and direct costs, partially
offset by a decrease in travel costs at BGE and PHI. Refer to the Regulatory assets table above for amounts as of December 31, 2020. The Utility
Registrants expect to seek recovery in upcoming distribution base rate cases.
247
Table of Contents
Combined Notes to Consolidated Financial Statements
(Dollars in millions, except per share data unless otherwise noted)
Note 3 — Regulatory Matters
Capitalized Ratemaking Amounts Not Recognized
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 our customers.
December 31, 2020
December 31, 2019
$
$
51 $
63 $
(1) $
3 $
— $
— $
45 $
53 $
7 $
7 $
4 $
4 $
3 $
3 $
—
—
Exelon
ComEd
(a)
PECO
BGE
(b)
PHI
Pepco
(c)
DPL
(c)
ACE
__________
(a) Reflects ComEd's unrecognized equity returns/(losses) earned/(incurred) 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.
Generation Regulatory Matters (Exelon and Generation)
Illinois Regulatory Matters
Zero Emission Standard. Pursuant to FEJA, on January 25, 2018, the ICC announced that Generation’s Clinton Unit 1, Quad Cities Unit 1, and Quad Cities
Unit 2 nuclear plants were selected as the winning bidders through the IPA's ZEC procurement event.
Generation executed the ZEC procurement contracts with Illinois utilities, including ComEd, effective January 26, 2018 and began recognizing revenue with
compensation for the sale of ZECs retroactive to the June 1, 2017 effective date of FEJA. The ZEC price was initially established at $16.50 per MWh of
production, subject to annual future adjustments determined by the IPA for specified escalation and pricing adjustment mechanisms designed to lower the
ZEC price based on increases in underlying energy and capacity prices. Illinois utilities are required to purchase all ZECs delivered by the zero-emissions
nuclear-powered generating facilities, subject to annual cost caps. For the initial delivery year, June 1, 2017 to May 31, 2018, and subsequent delivery year,
June 1, 2018 to May 31, 2019, the ZEC annual cost cap was set at $235 million (ComEd’s share is approximately $170 million). For subsequent delivery
years, the IPA-approved targeted ZEC procurement amounts will change based on forward energy and capacity prices. ZECs delivered to Illinois utilities in
excess of the annual cost cap may be paid in subsequent years if the payments do not exceed the prescribed annual cost cap for that year. During the first
quarter of 2018, Generation recognized $150 million of revenue related to ZECs generated from June 1, 2017 through December 31, 2017.
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 $69 million and $53 million for the year ended December 31, 2020 and 2019, respectively. On May 15, 2019, New Jersey
Rate Counsel appealed the NJBPU's decision to the New Jersey Superior Court. Briefing has been completed, and on December 9, 2020, oral argument
took place. On October 1, 2020, PSEG and Generation filed applications seeking ZECs for the second eligibility period (June 2022 through May 2025). The
NJBPU will act on the applications by the end of April 2021. Exelon and Generation cannot predict the outcome of the appeal. See Note 7 - Early Plant
Retirements for additional information related to Salem.
248
Table of Contents
Combined Notes to Consolidated Financial Statements
(Dollars in millions, except per share data unless otherwise noted)
Note 3 — Regulatory Matters
New York Regulatory Matters
New York Clean Energy Standard. On August 1, 2016, the NYPSC issued an order establishing the New York CES, a component of which is a Tier 3 ZEC
program targeted at preserving the environmental attributes of zero-emissions nuclear-powered generating facilities that meet the criteria demonstrating
public necessity as determined by the NYPSC to be Generation's FitzPatrick, Ginna, and Nine Mile Point nuclear facilities.
On November 30, 2016 (as amended on January 13, 2017), a group of parties filed a Petition in New York State court seeking to invalidate 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 provisions of the State Administrative Procedures Act when adopting the ZEC program. On January 22, 2018, the court dismissed the
environmental claims and the majority of the plaintiffs from the case but denied the motions to dismiss with respect to the remaining five plaintiffs and claims,
without commenting 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. Petitioners did not file a brief by the deadline, so the case is deemed dismissed. Petitioners are permitted up to one year from July 29, 2020 to file a
motion to vacate the dismissal if they can show good cause for the delay.
See Note 7 — Early Plant Retirements for additional information related to Ginna and Nine Mile Point.
New England Regulatory Matters
Mystic Units 8 & 9 and Everett Marine Terminal Cost of Service Agreement (Exelon and Generation). On March 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, 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 period 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 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 was submitted on September 15, 2020 and is pending. Several parties filed protests to the compliance filing on the issue of
how gross plant in-service was calculated and Generation filed an answer to the protests on October 21, 2020. On July 28, 2020, FERC ordered additional
briefings in the ROE proceeding. On December 21, 2020, FERC issued an order on rehearing of the three July 17, 2020 orders, clarifying several cost of
service provisions.
On August 25, 2020, a group of New England generators filed a complaint against Generation seeking to extend the scope of the claw back provision in the
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 September 14, 2020, Generation filed an answer to the complaint arguing that the complaint is procedurally improper and a collateral attack
on existing FERC orders, and pointing out that the ISO-NE tariff contains protections against the New England generators' concerns that they failed to
mention. On September 28, 2020, New England generators filed an answer to Generation’s answer. Generation cannot predict the outcome of this
proceeding.
On June 10, 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 the modifications that ISO-NE made to its unfiled
planning procedures to avoid retaining Mystic should have been filed with FERC for approval. 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. On August 17, 2020, FERC issued an order denying the complaint. On
September 16,
249
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Combined Notes to Consolidated Financial Statements
(Dollars in millions, except per share data unless otherwise noted)
Note 3 — Regulatory Matters
2020, Generation filed a request for rehearing with FERC. On October 19, 2020, FERC denied rehearing by operation of law and on December 18, 2020,
Generation appealed to the U.S. Court of Appeals for the D.C. Circuit. The timing and the outcome of this proceeding is uncertain.
See Note 7 — Early Plant Retirements and Note 12 — Asset Impairments for additional information on the impacts of Generation’s August 2020 decision to
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 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.
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 proposed tariff language interpreting and implementing FERC's directives, and proposed a
schedule for resuming capacity auctions that is contingent on the timing of FERC's action on the compliance filing.
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 which PJM submitted on June 1, 2020.
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. In November 2020, PJM announced that it will conduct its next capacity auction
beginning on May 19, 2021 and ending on May 25, 2021 and will post the results on June 2, 2021.
Because neither Illinois nor New Jersey have implemented an FRR program in their PJM zones, the MOPR will apply in that 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 clear the capacity market.
Exelon is currently working with PJM and other stakeholders to pursue the FRR option as an alternative to the PJM capacity auction. 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 7 — Early Plant Retirements. Implementing the FRR program in Illinois will require both legislative and regulatory changes. Whether
legislation is needed in New Jersey would depend on how the state chooses to structure an FRR program. Exelon cannot predict whether or when such
legislative and regulatory changes can be implemented.
250
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Combined Notes to Consolidated Financial Statements
(Dollars in millions, except per share data unless otherwise noted)
Note 3 — Regulatory Matters
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 has 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 21, 2016, Generation and the U.S. Fish and Wildlife Service of the U.S. Department of the Interior executed a settlement agreement (DOI
Settlement) resolving all fish passage issues between the parties.
On April 27, 2018, MDE issued its 401 Certification for Conowingo. As issued, the 401 Certification contains numerous conditions, including those relating to
reduction of nutrients from upstream sources, removal of all visible trash and debris from upstream sources, and implementation of measures relating to fish
passage, which could have a material, unfavorable impact on Exelon’s and Generation’s financial statements through an increase in capital expenditures
and operating costs if implemented. On May 25, 2018, Generation filed complaints in federal and state court, along with a petition for reconsideration with
MDE, alleging that the conditions are unfair and onerous and in violation of MDE regulations and state, federal, and constitutional law. Generation also
requested that FERC defer the issuance of the federal license while these significant state and federal law issues are pending. On February 28, 2019,
Generation filed a Petition for Declaratory Order with FERC requesting that FERC issue an order declaring that MDE waived its right to issue a 401
Certification for Conowingo because it failed to timely act on Conowingo’s 401 Certification application and requesting that FERC decline to include the
conditions required by MDE in April 2018.
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 FERC approves
the Offer of Settlement and incorporates the Proposed License Articles into the new license without modification, then MDE would waive its rights to issue a
401 Certification and Generation would agree, pursuant to a separate agreement 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 and
MDE Settlement are not effective unless and until FERC approves the Offer of Settlement, and issues the new license with the Proposed License Articles.
The financial impact of the DOI and MDE Settlements and other anticipated license commitments are estimated to be $11 million to $14 million per year, on
average, recognized over the new license term, including capital and operating costs. The actual timing and amount of the majority of these costs are not
currently fixed and will vary from year to year throughout the life of the new license. Generation cannot currently predict when FERC will issue the new
license. As of December 31, 2020, $45 million of direct costs associated with Conowingo licensing efforts have been capitalized. Generation's current
depreciation provision for Conowingo assumes renewal of the FERC license.
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(Dollars in millions, except per share data unless otherwise noted)
Note 3 — Regulatory Matters
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. See Note 8 –
Property, Plant, and Equipment for additional information regarding the estimated useful life and depreciation provisions for Peach Bottom.
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. The performance obligations, revenue recognition, and payment terms associated with these sources of revenue are
further discussed in the table below. There are no significant financing components for these sources of revenue and no variable consideration for regulated
electric and gas tariff sales and regulated transmission services unless noted below.
Unless otherwise noted, for each of the significant revenue categories and related performance obligations described below, the Registrants have the right to
consideration from the customer in an amount that corresponds directly with the value transferred to the customer for the performance completed to date.
Therefore, the Registrants generally recognize revenue in the amount for which they have the right to invoice the customer. As a result, there are generally
no significant judgments used in determining or allocating the transaction price.
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Combined Notes to Consolidated Financial Statements
(Dollars in millions, except per share data unless otherwise noted)
Note 4 — Revenue from Contracts with Customers
Revenue Source
Description
Performance Obligation
Timing of Revenue Recognition
Payment Terms
Competitive Power Sales
(Exelon and Generation)
Competitive Natural Gas
Sales (Exelon and
Generation)
Other Competitive
Products and Services
(Exelon and Generation)
Regulated Electric and
Gas Tariff Sales (Exelon
and the Utility Registrants)
Regulated Transmission
Services (Exelon and the
Utility Registrants)
Sales of power and other energy-
related commodities to wholesale and
retail customers across multiple
geographic regions through its
customer-facing business,
Constellation.
Sales of natural gas on a full
requirement basis or for an agreed
upon volume to commercial and
residential customers.
Sales of other energy-related
products and services such as long-
term construction and installation of
energy efficiency assets and new
power generating facilities, primarily
to commercial and industrial
customers.
Sales of electricity and electricity
distribution services (the Utility
Registrants) and natural gas and gas
distribution services (PECO, BGE,
and DPL) to residential, commercial,
industrial, and governmental
customers through regulated tariff
rates approved by state regulatory
commissions.
The Utility Registrants provide open
access to their transmission facilities
to PJM, which directs and controls
the operation of these transmission
facilities and accordingly
compensates the Utility Registrants
pursuant to filed tariffs at cost-based
rates approved by FERC.
Various including the delivery of
power (generally delivered over
time) and other energy-related
commodities such as capacity
(generally delivered over time),
ZECs, RECs or other ancillary
services (generally delivered at a
point in time).
Concurrently as power is
generated for bundled power
sale contracts.
(a)
Within the month
following delivery to
the customer.
Delivery of natural gas to the
customer.
Over time as the natural gas
is delivered and consumed
by the customer.
Within the month
following delivery to
the customer.
Construction and/or installation of
the asset for the customer.
Revenues and associated
costs are recognized
throughout the contract term
using an input method to
measure progress towards
completion.
(b)
Within 30 or 45 days
from the invoice date.
Delivery of electricity and/or
natural gas.
Over time (each day) as the
electricity and/or natural gas
is delivered to customers.
Tariff sales are generally
considered daily contracts as
customers can discontinue
service at any time.
(c)
Within the month
following delivery of
the electricity or natural
gas to the customer.
Various including (i) Network
Integration Transmission Services
(NITS), (ii) scheduling, system
control and dispatch services, and
(iii) access to the wholesale grid.
Over time utilizing output
methods to measure
progress towards
completion.
(d)
Paid weekly by PJM.
__________
(a) Certain contracts may contain limits on the total amount of revenue Exelon and Generation are able to collect over the entire term of the contract. In such cases, Exelon
and Generation estimate the total consideration expected to be received over the term of the contract net of the constraint and allocate the expected consideration to the
performance obligations
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Combined Notes to Consolidated Financial Statements
(Dollars in millions, except per share data unless otherwise noted)
Note 4 — Revenue from Contracts with Customers
in the contract such that revenue is recognized ratably over the term of the entire contract as the performance obligations are satisfied.
(b) The method recognizes revenue based on the various inputs used to satisfy the performance obligation, such as costs incurred and total labor hours expended. The total
amount of revenue that will be recognized is based on the agreed upon contractually-stated amount. The average contract term for these projects is approximately 18
months.
(c) Electric and natural gas utility customers have the choice to purchase electricity or natural gas from competitive electric generation and natural gas suppliers. While the
Utility Registrants are required under state legislation to bill their customers for the supply and distribution of electricity and/or natural gas, they recognize revenue related
only to the distribution services when customers purchase their electricity or natural gas from competitive suppliers.
(d) Passage of time is used for NITS and access to the wholesale grid and MWHs of energy transported over the wholesale grid is used for scheduling, system control and
dispatch services.
Generation incurs incremental costs in order to execute certain retail power and gas sales contracts. These costs, which primarily relate to retail broker fees
and sales commissions, are capitalized when incurred as contract acquisition costs and were immaterial as of December 31, 2020 and 2019. The Utility
Registrants do not incur any material costs to obtain or fulfill contracts with customers.
Contract Balances (All Registrants)
Contract Assets
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 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. The Utility Registrants
do not have any contract assets.
Balance as of December 31, 2018
Amounts reclassified to receivables
Revenues recognized
Balance at December 31, 2019
Amounts reclassified to receivables
Revenues recognized
Contract assets reclassified as held for sale
(a)
Balance at December 31, 2020
Exelon
Generation
$
$
187 $
(143)
130
174
(86)
68
(12)
144 $
187
(143)
130
174
(86)
68
(12)
144
__________
(a) Represents contract assets related to Generation's solar business, which were classified as held for sale as a result of the sale agreement. See Note 2 — Mergers,
Acquisitions, and Dispositions for additional information.
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, solar panel leases, and the
Illinois ZEC program that introduces a cap on the total consideration to be received by Generation. The Generation contract liability related to the Illinois ZEC
program includes certain amounts with ComEd that are eliminated in consolidation in Exelon’s Consolidated Statements of Operations and Consolidated
Balance Sheets.
On July 1, 2020, Pepco, DPL, and ACE each entered into a collaborative arrangement with an unrelated owner and manager of communication
infrastructure (the Buyer). Under this arrangement, Pepco, DPL, and ACE sold a 60% undivided interest in their respective portfolios of transmission tower
attachment agreements with
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Combined Notes to Consolidated Financial Statements
(Dollars in millions, except per share data unless otherwise noted)
Note 4 — Revenue from Contracts with Customers
telecommunications companies to the Buyer, in addition to transitioning management of the day-to-day operations of the jointly-owned agreements to the
Buyer for 35 years, while retaining the safe and reliable operation of its utility assets. In return, Pepco, DPL, and ACE will provide the Buyer limited access
on the portion of the towers where the equipment resides for the purposes of managing the agreements for the benefit of Pepco, DPL, ACE, and the Buyer.
In addition, for an initial period of three years and two, two-year extensions that are subject to certain conditions, 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. PHI, Pepco, DPL, and ACE
received cash and recorded contract liabilities as of July 1, 2020 as shown in the table below. 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. As of December 31, 2020, 2019, and 2018, ComEd's, PECO's, and BGE's contract liabilities were immaterial.
Exelon
Generation
PHI
Pepco
DPL
ACE
$
35
$
35
$
Balance as of December 31, 2017
Consideration received or due
Revenues recognized
Balance as of December 31, 2018
Consideration received or due
Revenues recognized
Balance at December 31, 2019
Consideration received or due
Revenues recognized
Contracts liabilities reclassified as held for sale
(a)
179
(187)
27
94
(88)
33
219
(98)
(3)
465
(458)
42
287
(258)
71
282
(266)
(3)
84
$
—
—
—
—
—
—
—
122
(4)
—
—
—
—
—
—
—
—
98
(4)
—
94
$
$
—
—
—
—
—
—
—
12
—
—
12
$
$
—
—
—
—
—
—
—
12
—
—
12
Balance at December 31, 2020
$
151
$
$
118
$
__________
(a) Represents contract liabilities related to Generation's solar business, which were classified as held for sale as a result of the sale agreement. See Note 2 — Mergers,
Acquisitions, and Dispositions for additional information.
The following table reflects revenues recognized in the years ended December 31, 2020, 2019 and 2018, which were included in contract liabilities at
December 31, 2019, 2018, and 2017, respectively:
Exelon
Generation
2020
2019
2018
$
27 $
64
$
18
32
11
11
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 December 31, 2020. 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.
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Combined Notes to Consolidated Financial Statements
(Dollars in millions, except per share data unless otherwise noted)
Exelon
Generation
PHI
Pepco
DPL
ACE
Note 4 — Revenue from Contracts with Customers
2021
2022
2023
2024
$
262 $
352
93 $
124
54 $
55
9
7
1
1
8
6
1
1
8
6
1
1
2025 and
thereafter
Total
40 $
34
6
5
—
1
330 $
243
87
70
9
8
779
808
118
94
12
12
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 5 — Segment Information for the presentation of the Registrant's revenue
disaggregation.
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 eleven reportable segments, which include Generation's five 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 three 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 five 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.
Other Power Regions:
New England represents 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 CAISO.
•
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’
256
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Combined Notes to Consolidated Financial Statements
(Dollars in millions, except per share data unless otherwise noted)
Note 5 — Segment Information
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 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, 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
years ended December 31, 2020, 2019, and 2018 is as follows:
Generation
ComEd
PECO
BGE
PHI
Other
(a)
Intersegment
Eliminations
Exelon
(b)
Operating revenues :
2020
Competitive businesses
electric revenues
Competitive businesses
natural gas revenues
Competitive businesses
other revenues
Rate-regulated electric
revenues
Rate-regulated natural gas
revenues
Shared service and other
revenues
Total operating revenues
2019
Competitive businesses
electric revenues
Competitive businesses
natural gas revenues
Competitive businesses
other revenues
Rate-regulated electric
revenues
Rate-regulated natural gas
revenues
Shared service and other
revenues
Total operating revenues
$
15,060
$
—
$
—
$
—
$
—
$
—
$
(1,196)
$
13,864
$
$
2,003
540
—
—
—
—
—
—
—
—
—
—
—
5,904
2,543
2,336
4,485
—
—
515
—
762
—
162
16
—
—
—
—
(3)
(4)
(61)
(7)
2,000
536
15,207
1,432
2,035
(2,051)
—
17,603
$
5,904
$
3,058
$
3,098
$
4,663
$
2,035
$
(3,322)
$
33,039
16,285
$
—
$
—
$
—
$
—
$
—
$
(1,165)
$
15,120
2,148
491
—
—
—
—
—
—
—
—
—
—
—
5,747
2,490
2,379
4,626
—
—
610
—
727
—
167
13
—
—
—
—
(1)
(4)
(47)
(15)
2,147
487
15,195
1,489
1,921
(1,934)
—
$
18,924
$
5,747
$
3,100
$
3,106
$
4,806
$
1,921
$
(3,166)
$
34,438
257
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Combined Notes to Consolidated Financial Statements
(Dollars in millions, except per share data unless otherwise noted)
Note 5 — Segment Information
2018
Competitive businesses
electric revenues
Competitive businesses
natural gas revenues
Competitive businesses
other revenues
Rate-regulated electric
revenues
Rate-regulated natural gas
revenues
Shared service and other
revenues
Total operating revenues
(c)
Intersegment revenues :
2020
2019
2018
Depreciation and amortization:
2020
2019
2018
Operating expenses:
2020
2019
2018
Interest expense, net:
2020
2019
2018
Income (loss) before income
taxes:
2020
2019
2018
Income taxes:
2020
2019
2018
Net income (loss):
2020
2019
Generation
ComEd
PECO
BGE
PHI
Other
(a)
Intersegment
Eliminations
Exelon
$
17,411
$
—
$
—
$
—
$
—
$
—
$
(1,256)
$
16,155
$
$
$
$
$
$
$
$
2,718
308
—
—
—
—
—
—
—
—
—
—
—
5,882
2,470
2,428
4,602
—
—
568
—
741
—
181
15
—
—
—
—
(8)
(5)
(45)
(20)
2,710
303
15,337
1,470
1,948
(1,960)
3
20,437
$
5,882
$
3,038
$
3,169
$
4,798
$
1,948
$
(3,294)
$
35,978
1,211
$
1,172
1,269
$
37
30
27
2,123
$
1,133
$
1,535
1,797
1,033
940
$
$
9
6
8
347
333
301
$
$
20
26
29
550
502
483
17
14
15
782
754
740
$
2,024
$
(3,314)
$
1,913
1,942
(3,159)
(3,289)
$
$
79
95
92
$
—
—
—
17,358
$
4,950
$
2,512
$
2,598
$
4,045
$
2,047
$
(3,270)
$
17,628
19,510
4,580
4,741
2,388
2,452
2,574
2,696
4,084
4,156
1,996
1,929
(3,154)
(3,341)
$
$
$
$
133
121
106
390
439
387
41
79
74
349
360
268
263
261
418
514
425
$
$
351
308
279
$
(343)
$
(327)
(249)
(77)
$
13
$
38
33
495
477
(87)
(55)
$
(354)
$
(240)
$
$
$
$
(3)
—
—
—
(2)
(1)
—
—
—
—
(2)
$
357
429
432
836
$
1,917
365
$
249
516
(108)
579
$
1,217
$
$
$
$
382
359
347
615
851
832
177
163
168
438
688
$
$
147
136
129
417
593
466
(30)
$
65
6
$
447
528
258
4
2
1
5,014
4,252
4,353
30,240
30,096
32,143
1,635
1,616
1,554
2,333
3,985
2,225
373
774
118
1,954
3,028
Table of Contents
Combined Notes to Consolidated Financial Statements
(Dollars in millions, except per share data unless otherwise noted)
Note 5 — Segment Information
Generation
ComEd
PECO
BGE
PHI
Other
(a)
Intersegment
Eliminations
Exelon
2018
Capital expenditures:
2020
2019
2018
Total assets:
2020
2019
$
$
443
664
460
313
393
(193)
1,747
$
2,217
$
1,147
$
1,247
$
1,604
$
1,845
2,242
1,915
2,126
939
849
1,145
959
1,355
1,375
86
49
43
48,094
48,995
$
34,466
32,765
$
12,531
11,469
$
11,650
10,634
$
23,736
22,719
$
9,005
8,484
$
$
(1)
—
—
—
(10,165)
(10,089)
2,079
8,048
7,248
7,594
129,317
124,977
$
$
__________
(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 24 — Supplemental Financial Information for additional information on total utility taxes.
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 25 - Related Party Transactions
for additional information on intersegment revenues.
(c)
259
Table of Contents
PHI:
(b)
Operating revenues :
2020
Rate-regulated electric revenues
Rate-regulated natural gas revenues
Shared service and other revenues
Total operating revenues
2019
Rate-regulated electric revenues
Rate-regulated natural gas revenues
Shared service and other revenues
Total operating revenues
2018
Rate-regulated electric revenues
Rate-regulated natural gas revenues
Shared service and other revenues
Total operating revenues
(c)
Intersegment revenues :
2020
2019
2018
Depreciation and amortization:
2020
2019
2018
Operating expenses:
2020
2019
2018
Interest expense, net:
2020
2019
2018
Income (loss) before income taxes:
2020
2019
2018
(d)
(d)
Income taxes:
2020
2019
2018
Combined Notes to Consolidated Financial Statements
(Dollars in millions, except per share data unless otherwise noted)
Note 5 — Segment Information
Pepco
DPL
ACE
Other
(a)
Intersegment
Eliminations
PHI
$
$
$
$
$
$
$
$
$
$
$
$
$
$
$
$
$
$
$
$
$
$
$
$
2,149
—
—
2,149
2,260
—
—
2,260
2,232
—
—
2,232
7
5
6
377
374
385
1,799
1,899
1,919
138
133
128
259
259
216
(7)
16
11
$
$
$
$
$
$
$
$
$
$
$
$
1,109
162
—
1,271
1,139
167
—
1,306
1,151
181
—
1,332
9
7
8
191
184
182
1,120
1,089
1,143
61
61
58
100
169
142
(25)
22
22
$
$
$
$
$
$
$
$
$
$
$
$
1,245
—
—
1,245
1,240
—
—
1,240
1,236
—
—
1,236
4
3
3
180
157
136
1,123
1,089
1,087
59
58
64
71
99
87
(41)
—
12
$
$
$
$
$
$
$
$
$
$
$
$
—
—
372
372
—
—
396
396
—
—
435
435
372
396
435
34
39
37
378
403
442
10
10
11
(12)
(13)
(20)
(4)
—
(12)
$
$
$
$
$
$
$
$
$
$
$
$
(18)
—
(356)
(374)
(13)
—
(383)
(396)
(17)
—
(420)
(437)
(375)
(397)
(437)
—
—
—
(375)
(396)
(435)
—
1
—
—
—
—
—
—
—
4,485
162
16
4,663
4,626
167
13
4,806
4,602
181
15
4,798
17
14
15
782
754
740
4,045
4,084
4,156
268
263
261
418
514
425
(77)
38
33
260
Table of Contents
Combined Notes to Consolidated Financial Statements
(Dollars in millions, except per share data unless otherwise noted)
Net income (loss):
2020
2019
2018
Capital expenditures:
2020
2019
2018
Total assets:
2020
2019
(d)
Note 5 — Segment Information
Pepco
DPL
ACE
Other
(a)
Intersegment
Eliminations
PHI
$
$
$
$
$
$
266
243
205
773
626
656
9,264
8,661
$
$
$
125
147
120
424
348
364
5,140
4,830
$
$
$
112
99
75
401
375
335
4,286
3,933
$
$
$
(8)
(12)
(7)
6
6
20
5,079
5,335
$
$
$
—
—
—
—
—
—
(33)
(40)
495
477
393
1,604
1,355
1,375
23,736
22,719
__________
(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 24 — Supplemental Financial Information for additional information on total utility taxes.
Includes intersegment revenues with ComEd, BGE, and PECO, which are eliminated at Exelon.
(c)
(d) The Income (loss) before income taxes in Other and Intersegment Eliminations have been adjusted by an offsetting $489 million and $408 million in 2019 and 2018,
respectively, and Total assets amounts in Other and Intersegment Eliminations have been adjusted by an offsetting $5.7 billion in 2019 for consistency with the Exelon
consolidating disclosure above.
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 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):
Revenues from external customers
(a)
2020
Contracts with
customers
Other
(b)
Total
Intersegment
Revenues
Total Revenues
Mid-Atlantic
Midwest
New York
ERCOT
Other Power Regions
Total Competitive Businesses Electric Revenues
Competitive Businesses Natural Gas Revenues
Competitive Businesses Other Revenues
(c)
Total Generation Consolidated Operating Revenues
$
$
$
4,785 $
3,717
1,444
735
3,586
14,267 $
1,283
355
15,905 $
(168) $
312
(12)
198
463
793 $
720
185
1,698 $
4,617 $
4,029
1,432
933
4,049
15,060 $
2,003
540
17,603 $
28 $
(5)
(1)
25
(47)
— $
—
—
— $
4,645
4,024
1,431
958
4,002
15,060
2,003
540
17,603
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Combined Notes to Consolidated Financial Statements
(Dollars in millions, except per share data unless otherwise noted)
Note 5 — Segment Information
Mid-Atlantic
Midwest
New York
ERCOT
Other Power Regions
Total Competitive Businesses Electric Revenues
Competitive Businesses Natural Gas Revenues
Competitive Businesses Other Revenues
(c)
Total Generation Consolidated Operating Revenues
Mid-Atlantic
Midwest
New York
ERCOT
Other Power Regions
Total Competitive Businesses Electric Revenues
Competitive Businesses Natural Gas Revenues
Competitive Businesses Other Revenues
(c)
Total Generation Consolidated Operating Revenues
Revenues from external customers
(a)
Contracts with
customers
Other
(b)
2019
Total
Intersegment
Revenues
Total Revenues
5,053 $
17 $
5,070 $
4 $
4,095
1,571
768
3,687
232
25
229
608
4,327
1,596
997
4,295
15,174 $
1,446
440
1,111 $
702
51
16,285 $
2,148
491
17,060 $
1,864 $
18,924 $
Revenues from external customers
(a)
2018
(34)
—
16
(49)
(63) $
62
1
— $
5,074
4,293
1,596
1,013
4,246
16,222
2,210
492
18,924
Contracts with
customers
Other
(b)
Total
Intersegment
Revenues
Total Revenues
5,241 $
233 $
5,474 $
13 $
4,527
1,723
572
3,530
190
(36)
560
871
4,717
1,687
1,132
4,401
15,593 $
1,524
510
1,818 $
1,194
(202)
17,411 $
2,718
308
17,627 $
2,810 $
20,437 $
(11)
—
1
(66)
(63) $
62
1
— $
5,487
4,706
1,687
1,133
4,335
17,348
2,780
309
20,437
$
$
$
$
$
$
__________
(a)
(b)
(c) Represents activities not allocated to a region. See text above for a description of included activities. Includes unrealized mark-to-market gains of $110 million and losses of
Includes all wholesale and retail electric sales to third parties and affiliated sales to the Utility Registrants.
Includes revenues from derivatives and leases.
$4 million and $262 million for the years ended December 31, 2020, 2019, and 2018, respectively, and the elimination of intersegment revenues.
262
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Combined Notes to Consolidated Financial Statements
(Dollars in millions, except per share data unless otherwise noted)
Note 5 — Segment Information
Revenues net of purchased power and fuel expense (Generation):
2020
2019
2018
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
Midwest
New York
ERCOT
Other Power Regions
Total RNF for
Reportable Segments
Other
(b)
Total Generation RNF
$
$
$
2,174
2,902
983
407
759
7,225
793
8,018
$
$
$
30
—
14
19
(94)
(31)
31
—
$
$
$
2,204
2,902
997
426
665
7,194
824
8,018
$
$
$
2,637
2,994
1,081
338
694
7,744
324
8,068
$
$
$
18
(32)
13
(30)
(74)
(105)
105
—
$
$
$
2,655
2,962
1,094
308
620
7,639
429
8,068
$
$
$
3,022
3,112
1,112
501
883
8,630
114
8,744
$
$
$
51
23
10
(243)
(154)
(313)
313
—
$
$
$
3,073
3,135
1,122
258
729
8,317
427
8,744
__________
(a)
(b) Other represents activities not allocated to a region. See text above for a description of included activities. Primarily includes:
Includes purchases and sales from/to third parties and affiliated sales to the Utility Registrants.
•
•
•
unrealized mark-to-market gains of $295 million and losses of $215 million and $319 million for the years ended December 31, 2020, 2019, and 2018,
respectively;
accelerated nuclear fuel amortization associated with the announced early plant retirements as discussed in Note 7 - Early Plant Retirements of $60 million, $13
million, and $57 million in for the years ended December 31, 2020, 2019, and 2018, respectively; and
the elimination of intersegment RNF.
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Combined Notes to Consolidated Financial Statements
(Dollars in millions, except per share data unless otherwise noted)
Note 5 — Segment Information
Electric and Gas Revenue by Customer Class (Utility Registrants):
Revenues from contracts with customers
Rate-regulated electric revenues
ComEd
PECO
BGE
2020
PHI
Pepco
DPL
ACE
Residential
Small commercial & industrial
Large commercial & industrial
Public authorities & electric railroads
Other
Total rate-regulated electric revenues
(a)
(b)
Rate-regulated natural gas revenues
Residential
Small commercial & industrial
Large commercial & industrial
Transportation
(c)
Other
Total rate-regulated natural gas revenues
(d)
Total rate-regulated revenues from contracts with
customers
Other revenues
Revenues from alternative revenue programs
Other rate-regulated electric revenues
Other rate-regulated natural gas revenues
(e)
(e)
Total other revenues
Total rate-regulated revenues for reportable
segments
1,345
241
406
27
309
2,328
504
79
135
—
29
747
3,075
16
5
2
23
3,098
$
$
$
$
$
$
$
$
2,332
472
1,001
60
613
4,478
96
42
4
14
6
162
4,640
21
2
—
23
4,663
$
$
$
$
$
$
$
$
988
132
736
34
218
2,108
—
—
—
—
—
—
2,108
40
1
—
41
2,149
$
$
$
$
$
$
$
$
652
171
89
13
190
1,115
96
42
4
14
6
162
1,277
(7)
1
—
(6)
1,271
$
$
$
$
$
$
$
$
692
169
176
13
207
1,257
—
—
—
—
—
—
1,257
(12)
—
—
(12)
1,245
$
$
$
$
$
$
$
$
3,090
1,399
515
45
884
5,933
—
—
—
—
—
—
5,933
(47)
18
—
(29)
5,904
$
$
$
$
$
$
$
$
1,656
386
228
29
225
2,524
361
126
—
24
4
515
3,039
16
3
—
19
3,058
$
$
$
$
$
$
$
$
264
Table of Contents
Combined Notes to Consolidated Financial Statements
(Dollars in millions, except per share data unless otherwise noted)
Note 5 — Segment Information
Revenues from contracts with customers
Rate-regulated electric revenues
ComEd
PECO
BGE
2019
PHI
Pepco
DPL
ACE
Residential
Small commercial & industrial
Large commercial & industrial
Public authorities & electric railroads
Other
Total rate-regulated electric revenues
(a)
(b)
Rate-regulated natural gas revenues
Residential
Small commercial & industrial
Large commercial & industrial
Transportation
(c)
Other
Total rate-regulated natural gas revenues
(d)
Total rate-regulated revenues from contracts with
customers
Other revenues
Revenues from alternative revenue programs
Other rate-regulated electric revenues
Other rate-regulated natural gas revenues
(e)
(e)
Total other revenues
Total rate-regulated revenues for reportable
segments
1,326
254
436
27
321
2,364
474
77
132
—
31
714
3,078
12
12
4
28
3,106
$
$
$
$
$
$
$
$
2,316
505
1,112
61
650
4,644
96
44
5
14
7
166
4,810
(14)
10
—
(4)
4,806
$
$
$
$
$
$
$
$
1,012
149
833
34
227
2,255
—
—
—
—
—
—
2,255
(3)
8
—
5
2,260
$
$
$
$
$
$
$
$
645
186
99
14
204
1,148
96
45
5
14
7
167
1,315
(11)
2
—
(9)
1,306
$
$
$
$
$
$
$
$
659
170
180
13
218
1,240
—
—
—
—
—
—
1,240
—
—
—
—
1,240
$
$
$
$
$
$
$
$
2,916
1,463
540
47
888
5,854
—
—
—
—
—
—
5,854
(133)
26
—
(107)
5,747
$
$
$
$
$
$
$
$
1,596
404
219
29
249
2,497
409
169
1
25
6
610
3,107
(21)
13
1
(7)
3,100
$
$
$
$
$
$
$
$
265
Table of Contents
Combined Notes to Consolidated Financial Statements
(Dollars in millions, except per share data unless otherwise noted)
Note 5 — Segment Information
Revenues from contracts with customers
Rate-regulated electric revenues
ComEd
PECO
BGE
2018
PHI
Pepco
DPL
ACE
Residential
Small commercial & industrial
Large commercial & industrial
Public authorities & electric railroads
Other
Total rate-regulated electric revenues
(a)
(b)
Rate-regulated natural gas revenues
Residential
Small commercial & industrial
Large commercial & industrial
Transportation
(c)
Other
Total rate-regulated natural gas revenues
(d)
Total rate-regulated revenues from contracts with
customers
Other revenues
Revenues from alternative revenue programs
Other rate-regulated electric revenues
Other rate-regulated natural gas revenues
(e)
(e)
$
$
$
$
$
$
Total other revenues
$
Total rate-regulated revenues for reportable segments $
2,942
1,487
538
47
867
5,881
—
—
—
—
—
—
5,881
(29)
30
—
1
5,882
$
$
$
$
$
$
$
$
1,566
404
223
28
243
2,464
395
143
1
23
6
568
3,032
(7)
12
1
6
3,038
$
$
$
$
$
$
$
$
1,382
257
429
28
327
2,423
491
77
124
—
63
755
3,178
(26)
13
4
(9)
3,169
$
$
$
$
$
$
$
$
2,351
488
1,124
58
593
4,614
99
44
8
16
13
180
4,794
(7)
10
1
4
4,798
$
$
$
$
$
$
$
$
1,021
140
846
32
193
2,232
—
—
—
—
—
—
2,232
(7)
7
—
—
2,232
$
$
$
$
$
$
$
$
669
186
100
14
175
1,144
99
44
8
16
13
180
1,324
4
3
1
8
1,332
$
$
$
$
$
$
$
$
661
162
178
12
227
1,240
—
—
—
—
—
—
1,240
(4)
—
—
(4)
1,236
__________
(a)
(b)
Includes revenues from transmission revenue from PJM, wholesale electric revenue and mutual assistance revenue.
Includes operating revenues from affiliates in 2020, 2019, and 2018 respectively of:
•
•
•
•
•
•
•
$37 million, $30 million, and $27 million at ComEd
$8 million, $5 million, and $7 million at PECO
$10 million, $8 million, and $8 million at BGE
$17 million, $14 million, and $15 million at PHI
$7 million, $5 million, and $6 million at Pepco
$9 million, $7 million, and $8 million at DPL
$4 million, $3 million, and $3 million at ACE
Includes revenues from off-system natural gas sales.
Includes operating revenues from affiliates in 2020, 2019, and 2018 respectively of:
(c)
(d)
•
•
$1 million, $1 million, and $1 million at PECO
$10 million, $18 million, and $21 million at BGE
(e)
Includes late payment charge revenues.
266
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Combined Notes to Consolidated Financial Statements
(Dollars in millions, except per share data unless otherwise noted)
Note 6 — Accounts Receivable
6. Accounts Receivable (All Registrants)
Allowance for Credit Losses on Accounts Receivable (All Registrants)
The following table presents the rollforward of Allowance for Credit Losses on Customer Accounts Receivable for the year ended December 31, 2020.
Balance as of December 31,
2019
Plus: Current Period
Provision for Expected Credit
Losses
(a)
Less: Write-offs, net of
(b)
recoveries
Less: Sale of customer
accounts receivable
(c)
Balance as of December 31,
2020
Exelon
Generation
ComEd
PECO
BGE
PHI
Pepco
DPL
ACE
$
243 $
80 $
59 $
55 $
12 $
37 $
13 $
11 $
13
248
69
56
13
5
56
62
24
—
79
18
—
30
7
—
64
15
—
24
5
—
15
4
—
$
366 $
32 $
97 $
116 $
35 $
86 $
32 $
22 $
25
6
—
32
_________
(a) For the Utility Registrants, the increase is primarily as a result of increased aging of receivables, the temporary suspension of customer disconnections for non-payment,
temporary cessation of new late payment fees, and reconnection of service to customers previously disconnected due to COVID-19.
(b) Recoveries were not material to the Registrants.
(c) See below for additional information on the sale of customer accounts receivable at Generation in the second quarter of 2020.
The following table presents the rollforward of Allowance for Credit Losses on Other Accounts Receivable for the year ended December 31, 2020.
Balance as of December 31,
2019
Plus: Current Period
Provision for Expected Credit
Losses
Less: Write-offs, net of
(a)
recoveries
Balance as of December 31,
2020
Exelon
Generation
ComEd
PECO
BGE
PHI
Pepco
DPL
ACE
$
48 $
— $
20 $
7 $
5 $
16 $
7 $
4 $
33
10
—
—
5
4
3
2
7
3
18
1
6
—
5
—
5
7
1
$
71 $
— $
21 $
8 $
9 $
33 $
13 $
9 $
11
_________
(a) Recoveries were not material to the Registrants.
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Combined Notes to Consolidated Financial Statements
(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 as of
December 31, 2020 and 2019.
Exelon
Generation
ComEd
PECO
BGE
PHI
Pepco
DPL
ACE
Unbilled customer revenues
(a)
December 31, 2020
$
998 $
258 $
218 $
147 $
197 $
178 $
87 $
December 31, 2019
_________
(a) Unbilled customer revenues are classified in Customer accounts receivables, net in the Registrants' Consolidated Balance Sheets.
1,535
170
807
194
218
146
100
62 $
61
29
33
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, whose maximum capacity is $750 million, is scheduled to expire on April 7, 2021, unless renewed by the mutual consent of the
parties in accordance with its terms. 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.
On April 8, 2020, Generation derecognized and transferred approximately $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. On February 17, 2021, Generation received additional cash of $250 million from
the Purchasers for the remaining capacity in the Facility.
The following table summarizes the impact of the sale of certain receivables:
Derecognized receivables transferred at fair value
Cash proceeds received
DPP
(a)
As of December 31, 2020
$
_________
(a)
Includes additional customer accounts receivable sold into the Facility of $6,608 million since the start of the financing agreement.
Loss on sale of receivables
(a)
For the year ended December 31, 2020
$
_________
(a) Reflected in Operating and maintenance expense on Exelon and Generation's Consolidated Statement of Operations and Comprehensive Income.
Proceeds from new transfers
Cash collections received on DPP
Cash collections reinvested in the Facility
For the year ended December 31, 2020
$
1,139
500
639
30
2,816
3,771
6,587
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.
268
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Combined Notes to Consolidated Financial Statements
(Dollars in millions, except per share data unless otherwise noted)
Note 6 — Accounts Receivable
Generation recognizes the cash proceeds received upon sale in Net cash provided by operating activities in the Consolidated Statement of Cash Flows. The
collection and reinvestment of DPP is recognized in Net cash provided by investing activities of the Consolidated Statement of Cash Flows.
See Note 18 — Fair Value of Financial Assets and Liabilities and Note 23 — Variable Interest Entities for additional information.
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, 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 for the year ended December 31, 2020.
Total Receivables Purchased $
Total Receivables Sold
3,529 $
572
— $
824
1,094 $
—
1,020 $
—
652 $
—
Exelon
Generation
ComEd
PECO
BGE
PHI
1,015 $
—
Pepco
DPL
ACE
622 $
—
207 $
—
186
—
Related Party Transactions:
Receivables purchased
from Generation
Receivables sold to the
Utility Registrants
—
—
—
252
34
—
67
—
79
—
72
—
51
—
13
—
8
—
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.
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 TMI
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,
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Combined Notes to Consolidated Financial Statements
(Dollars in millions, except per share data unless otherwise noted)
Note 7 — Early Plant Retirements
each of these plants, in 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 Illinois and New Jersey implement an FRR mechanism under which the Generation plants in these
states would be removed from PJM’s capacity auction. See Note 3 — Regulatory Matters for additional information on the Illinois ZES, New Jersey ZEC
program, New York CES, and FERC's December 19, 2019 order on the MOPR in PJM.
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, Generation announced that it would permanently cease generation operations at TMI. On September 20, 2019, Generation permanently ceased
generation operations at TMI.
Generation’s Dresden, Byron, and Braidwood nuclear plants in Illinois are also showing increased signs of economic distress, 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, including all of Dresden, and portions of Byron and Braidwood. While all of LaSalle's capacity did clear in the 2021-2022 planning year auction,
Generation has become increasingly concerned about the economic viability of this plant as well in a landscape where energy market prices remain
depressed and energy market rules remain fatally flawed.
On August 27, 2020, Generation announced that it intends to permanently cease generation operations at Byron in September 2021 and at Dresden in
November 2021. 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.
As a result of the decision to early retire Byron and Dresden, Exelon and Generation recognized certain one-time charges for the year ended December 31,
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. See Note 10 — Asset Retirement Obligations for additional
information on changes to the nuclear decommissioning ARO balance and Note 12 — Asset Impairments for impairment assessment considerations given to
the Midwest asset group as a result of the early retirement decision. The total impact on Exelon's and Generation's Consolidated Statements of Operations
and Comprehensive Income is summarized in the table below.
Income statement expense (pre-tax)
Depreciation and amortization
(d)
Accelerated depreciation
Accelerated nuclear fuel amortization
Operating and maintenance
One-time charges
Other charges
(e)
Contractual offset
(f)
Total
_________
(a) Reflects expense for Byron and Dresden.
(b) Reflects expense for TMI.
(c) Reflects expense for TMI and Oyster Creek.
(d)
Includes the accelerated depreciation of plant assets including any ARC.
270
2020
(a)
2019
(b)
2018
(c)
$
$
895 $
60
255
34
(364)
880 $
216 $
13
—
(53)
—
176 $
539
57
32
—
—
628
Table of Contents
Combined Notes to Consolidated Financial Statements
(Dollars in millions, except per share data unless otherwise noted)
Note 7 — Early Plant Retirements
(e) For Dresden, reflects the net impacts associated with the remeasurement of the ARO. For TMI, primarily reflects the net impacts associated with the remeasurement of the
ARO. See Note 10 - Asset Retirement Obligations for additional information.
(f) Reflects contractual offset for ARO accretion, ARC depreciation, and net impacts associated with the remeasurement of the ARO. For Byron and Dresden, based on the
regulatory agreement with the ICC, decommissioning-related activities in 2020 have been offset within Exelon's and Generation's Consolidated Statements of Operations
and Comprehensive Income. The offset in 2020 resulted in an equal adjustment to the noncurrent payables to ComEd at Generation and an adjustment to the regulatory
liabilities at ComEd. See Note 10 - Asset Retirement Obligations for additional information.
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. For the year ended December 31, 2020, Exelon and Generation recorded severance expense of $81 million within Operating and
maintenance expense in their Consolidated Statements of Operations and Comprehensive Income. The final amount of severance benefit costs will depend
on the specific employees severed.
The following table provides the balance sheet amounts as of December 31, 2020 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.
Asset Balances
Materials and supplies inventory, net
Nuclear fuel inventory, net
Completed plant, net
Construction work in progress
Liability Balances
Asset retirement obligation
NRC License First Renewal Term
Braidwood
LaSalle
Total
$
84 $
120
1,397
31
(570)
106 $
285
1,590
30
190
405
2,987
61
(954)
(1,524)
2046 (Unit 1)
2047 (Unit 2)
2042 (Unit 1)
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.
Other Generation
In March 2018, Generation notified ISO-NE of its plans to early retire, among other assets, the Mystic Generating Station's units 8 and 9 (Mystic 8 and 9)
absent regulatory reforms to 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 (FCA 15) 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
expiration of the cost 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 8 and 9, Exelon and Generation recognized $22 million of one-time charges for the year ended
December 31, 2020, related to materials and supplies inventory reserve adjustments, among other items. In addition, there are annual financial impacts
stemming from shortening the expected economic useful life of Mystic 8 and 9 primarily related to accelerated depreciation of plant assets.
271
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Combined Notes to Consolidated Financial Statements
(Dollars in millions, except per share data unless otherwise noted)
Note 7 — Early Plant Retirements
Exelon and Generation recorded incremental Depreciation and amortization expense of $26 million for the year ended December 31, 2020. See Note 12 —
Asset Impairments for impairment assessment considerations of the New England Asset Group.
8. Property, Plant, and Equipment (All Registrants)
The following tables present a summary of property, plant, and equipment by asset category as of December 31, 2020 and 2019:
Asset Category
December 31, 2020
Electric—transmission and
distribution
Electric—generation
Gas—transportation and
distribution
Common—electric and gas
(a)
Nuclear fuel
Construction work in progress
Other property, plant, and
equipment
(b)
Exelon
Generation
ComEd
PECO
BGE
PHI
Pepco
DPL
ACE
$
60,946
$
—
$
29,371
$
9,462
$
8,797
$
15,137
$
10,264
$
4,730
$
4,568
29,725
29,724
6,733
2,170
5,399
3,576
762
—
—
5,399
450
11
—
—
—
—
799
59
—
—
3,098
956
—
474
34
3,315
1,138
—
627
29
—
591
178
—
1,174
108
—
—
—
—
824
65
—
751
180
—
163
23
—
—
—
—
182
28
Total property, plant, and
equipment
Less: accumulated
depreciation
(c)
Property, plant, and equipment,
net
$
109,311
35,584
30,229
14,024
13,906
17,188
11,153
26,727
13,370
5,672
3,843
4,034
1,811
3,697
5,847
1,533
4,778
1,303
82,584
$
22,214
$
24,557
$
10,181
$
9,872
$
15,377
$
7,456
$
4,314
$
3,475
December 31, 2019
Electric—transmission and
distribution
Electric—generation
Gas—transportation and
distribution
Common—electric and gas
(a)
Nuclear fuel
Construction work in progress
Other property, plant and
(b)
equipment
Total property, plant and
equipment
Less: accumulated
depreciation
(c)
$
56,809
$
—
$
27,566
$
8,957
$
8,326
$
13,809
$
9,734
$
4,464
$
4,207
29,839
29,839
6,147
1,907
5,656
3,055
799
—
—
5,656
702
13
—
—
—
—
662
47
—
—
2,899
2,999
877
—
250
27
991
—
483
25
—
525
146
—
921
108
—
—
—
—
628
64
—
690
160
—
125
21
—
—
—
—
166
27
104,212
36,210
28,275
13,010
12,824
15,509
10,426
23,979
12,017
5,168
3,718
3,834
1,213
3,517
5,460
1,425
4,400
1,210
24,193
$
23,107
$
9,292
$
8,990
$
14,296
$
6,909
$
4,035
$
3,190
Property, plant, and equipment,
net
__________
(a)
(b) Primarily composed of land and non-utility property.
(c)
80,233
$
$
Includes nuclear fuel that is in the fabrication and installation phase of $939 million and $1,025 million at December 31, 2020 and 2019, respectively.
Includes accumulated amortization of nuclear fuel in the reactor core at Generation of $2,774 million and $2,867 million as of December 31, 2020 and 2019, respectively.
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Combined Notes to Consolidated Financial Statements
(Dollars in millions, except per share data unless otherwise noted)
Note 8 — Property, Plant, and Equipment
The following table presents the average service life for each asset category in number of years:
Asset Category
Exelon
Generation
ComEd
PECO
Electric - transmission and distribution
Electric - generation
Gas - transportation and distribution
Common - electric and gas
Nuclear fuel
Other property, plant, and equipment
5-80
1-58
5-80
4-75
1-8
1-50
N/A
1-58
N/A
N/A
1-8
1-10
5-80
N/A
N/A
N/A
N/A
33-50
5-70
N/A
5-70
5-55
N/A
50
BGE
5-80
N/A
5-80
4-50
N/A
20-50
PHI
5-75
N/A
5-75
5-75
N/A
3-50
Pepco
5-75
N/A
N/A
N/A
N/A
25-50
DPL
5-70
N/A
5-75
5-75
N/A
8-50
ACE
5-65
N/A
N/A
N/A
N/A
13-15
Average Service Life (years)
Depreciation provisions are based on the estimated useful lives of the stations, which reflect the first renewal of the operating licenses for all of Generation's
operating nuclear generating stations except for Clinton, Byron, Dresden, and Peach Bottom. Clinton depreciation provisions are based on an estimated
useful life through 2027, which is the last year of the Illinois ZES. Peach Bottom depreciation provisions are based on estimated useful life of 2053 and 2054
for Unit 2 and Unit 3, respectively, which reflects the second renewal of its operating licenses. Beginning August 2020, Byron, Dresden, and Mystic
depreciation provisions were based on their announced shutdown dates of September 2021, November 2021, and May 2024, respectively. See Note 3 —
Regulatory Matters for additional information regarding license renewals and the Illinois ZECs and Note 7 — Early Plant Retirements for additional
information on the impacts of early plant retirements.
The following table presents the annual depreciation rates for each asset category. Nuclear fuel amortization is charged to fuel expense using the unit-of-
production method and not included in the below table.
December 31, 2020
Electric—transmission and distribution
Electric—generation
Gas—transportation and distribution
Common—electric and gas
December 31, 2019
Electric—transmission and distribution
Electric—generation
Gas—transportation and distribution
Common—electric and gas
December 31, 2018
Electric—transmission and distribution
Electric—generation
Gas—transportation and distribution
Common—electric and gas
Exelon
Generation
ComEd
PECO
BGE
PHI
Pepco
DPL
ACE
Annual Depreciation Rates
2.79 %
6.11 %
2.14 %
7.01 %
2.80 %
4.35 %
2.04 %
7.37 %
2.73 %
5.37 %
2.07 %
6.98 %
N/A
6.11 %
N/A
N/A
N/A
4.35 %
N/A
N/A
N/A
5.37 %
N/A
N/A
2.95 %
2.31 %
2.69 %
N/A
N/A
N/A
N/A
1.85 %
6.39 %
N/A
2.56 %
7.45 %
2.99 %
2.36 %
2.60 %
N/A
N/A
N/A
N/A
1.89 %
6.06 %
N/A
2.30 %
8.30 %
2.95 %
2.35 %
2.61 %
N/A
N/A
N/A
N/A
1.90 %
5.44 %
N/A
2.36 %
8.50 %
2.81 %
N/A
1.50 %
7.36 %
2.77 %
N/A
1.55 %
8.25 %
2.61 %
N/A
1.59 %
6.30 %
2.53 %
N/A
N/A
N/A
2.47 %
N/A
N/A
N/A
2.40 %
N/A
N/A
N/A
2.85 %
N/A
1.50 %
6.72 %
2.86 %
N/A
1.55 %
6.24 %
2.77 %
N/A
1.59 %
3.70 %
3.08 %
N/A
N/A
N/A
2.94 %
N/A
N/A
N/A
2.45 %
N/A
N/A
N/A
273
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Combined Notes to Consolidated Financial Statements
(Dollars in millions, except per share data unless otherwise noted)
Note 8 — Property, Plant, and Equipment
Capitalized Interest and AFUDC (All Registrants)
The following table summarizes capitalized interest and credits to AFUDC by year:
December 31, 2020
Capitalized interest
AFUDC debt and equity
December 31, 2019
Capitalized interest
AFUDC debt and equity
December 31, 2018
Capitalized interest
AFUDC debt and equity
Exelon
Generation
ComEd
PECO
BGE
PHI
Pepco
DPL
ACE
$
$
$
22
$
150
24
$
132
31
$
109
$
$
$
22
—
24
—
31
—
$
$
$
—
42
—
32
—
30
$
$
$
—
23
—
17
—
12
$
$
$
—
30
—
29
—
24
$
$
$
—
55
—
54
—
44
$
$
$
—
42
—
39
—
34
$
$
$
—
6
—
6
—
4
—
7
—
9
—
4
See Note 1 — Significant Accounting Policies for additional information regarding property, plant and equipment policies. See Note 17 — Debt and Credit
Agreements for additional information regarding Exelon’s, ComEd’s, PECO's, Pepco's, DPL's, and ACE’s property, plant and equipment subject to mortgage
liens.
9. Jointly Owned Electric Utility Plant (Exelon, Generation, PECO, DPL, and ACE)
Exelon's, Generation's, PECO's, DPL's, and ACE's material undivided ownership interests in jointly owned electric plants and transmission facilities at
December 31, 2020 and 2019 were as follows:
Operator
Ownership interest
Exelon’s share at December 31, 2020:
Plant in service
Accumulated depreciation
Construction work in progress
Exelon’s share at December 31, 2019:
Plant in service
Accumulated depreciation
Construction work in progress
Nuclear Generation
Transmission
Quad Cities
Peach
Bottom
Generation
Generation
Salem
PSEG
Nuclear
Nine Mile Point Unit 2
NJ/DE
(a)
Generation
PSEG/DPL
75.00 %
50.00 %
42.59 %
82.00 %
various
$
$
$
1,188
670
13
$
1,506
601
13
1,161
$
1,466
$
627
13
571
21
$
$
717
265
39
663
249
53
$
$
990
187
25
951
156
27
103
54
—
102
53
—
__________
(a) PECO, DPL, and ACE own a 42.55%, 1%, and 13.9% share, respectively in 151.3 miles of 500kV lines located in New Jersey and of the Salem generating plant
substation. PECO, DPL, and ACE also own a 42.55%, 7.45%, and 7.45% share, respectively, in 2.5 miles of 500kV line located over the Delaware River. ACE also has a
21.78% share in a 500kV New Freedom Switching substation.
Exelon’s, Generation’s, PECO's, DPL's, and ACE's undivided ownership interests are financed with their funds and all operations are accounted for as if
such participating interests were wholly owned facilities. Exelon’s, Generation’s, PECO's, DPL's, and ACE's share of direct expenses of the jointly owned
plants are included in Purchased power and fuel and Operating and maintenance expenses in Exelon’s and Generation’s Consolidated Statements of
Operations and Comprehensive Income and in Operating and maintenance expenses in PECO's, PHI's, DPL's, and ACE's Consolidated Statements of
Operations and Comprehensive Income.
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(Dollars in millions, except per share data unless otherwise noted)
Note 10 — Asset Retirement Obligations
10. Asset Retirement Obligations (All Registrants)
Nuclear Decommissioning Asset Retirement Obligations (Exelon and Generation)
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. Generation began decommissioning the TMI nuclear plant upon permanently ceasing
operations in 2019. See below section for decommissioning of Zion Station.
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
January 1, 2019 to December 31, 2020:
Nuclear decommissioning ARO at January 1, 2019
Net increase due to changes in, and timing of, estimated future cash flows
Sale of Oyster Creek
Accretion expense
Costs incurred related to decommissioning plants
Nuclear decommissioning ARO at December 31, 2019
(a)
Net increase due to changes in, and timing of, estimated future cash flows
Accretion Expense
Costs incurred related to decommissioning plants
Nuclear decommissioning ARO at December 31, 2020
(a)
$
10,005
864
(755)
479
(89)
10,504
1,022
489
(93)
11,922
$
__________
(a)
Includes $80 million and $112 million as the current portion of the ARO at December 31, 2020 and 2019, respectively, which is included in Other current liabilities in
Exelon’s and Generation’s Consolidated Balance Sheets.
The net $1,022 million increase in the ARO during 2020 for changes in the amounts and timing of estimated decommissioning cash flows was driven by
multiple adjustments throughout the year. These adjustments primarily include:
•
•
•
A net increase of approximately $800 million was driven by updates to Byron and Dresden reflecting changes in assumed retirement dates and
assumed methods of decommissioning as a result of the announcement to early retire these plants in 2021. Refer to Note 7 — Early Plant
Retirements for additional information.
An increase of approximately $360 million resulting from the change in the assumed DOE spent fuel acceptance date for disposal from 2030 to
2035.
A decrease of approximately $220 million due to lower estimated decommissioning costs primarily for Limerick and Peach Bottom nuclear units
resulting from the completion of updated cost studies.
The 2020 ARO updates resulted in a increase of $60 million in Operating and maintenance expense for the year ended December 31, 2020 within Exelon
and Generation's Consolidated Statements of Operations and Comprehensive Income.
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Combined Notes to Consolidated Financial Statements
(Dollars in millions, except per share data unless otherwise noted)
Note 10 — Asset Retirement Obligations
The net $864 million increase in the ARO during 2019 for changes in the amounts and timing of estimated decommissioning cash flows was driven by
multiple adjustments throughout the year, some with offsetting impacts. These adjustments primarily include:
•
•
•
An increase of approximately $780 million for changes in the assumed retirement timing probabilities for sites including certain economically
challenged nuclear plants and the extension of Peach Bottom’s operating life.
An increase of approximately $490 million for other impacts that included updated cost escalation rates, primarily for labor, equipment and
materials, and current discount rates.
Lower estimated costs to decommission TMI, Nine Mile Point, Ginna, Braidwood, Byron, and LaSalle nuclear units of approximately $410 million
resulting from the completion of updated cost studies.
The 2019 ARO updates resulted in a decrease of $150 million in Operating and maintenance expense for the year ended December 31, 2019 within Exelon
and Generation's Consolidated Statements of Operations and Comprehensive Income. See Note 7 — Early Plant Retirements for additional information
regarding TMI and economically challenged nuclear plants and Note 3 — Regulatory Matters regarding the Peach Bottom second license renewal.
NDT Funds
NDT funds have been established for each generation station unit to satisfy Generation’s nuclear decommissioning obligations. Generally, NDT funds
established for a particular unit may not be used to fund the decommissioning obligations of any other unit.
The NDT funds associated with Generation's nuclear units have been funded with amounts collected from the previous owners and their respective utility
customers. PECO is authorized to collect funds, in revenues, for decommissioning the former PECO nuclear plants through regulated rates, and these
collections are scheduled through the operating lives of the former PECO plants. The amounts collected from PECO customers are remitted to Generation
and deposited into the NDT funds for the unit for which funds are collected. Every five years, PECO files a rate adjustment with the PAPUC that reflects
PECO’s calculations of the estimated amount needed to decommission each of the former PECO units based on updated fund balances and estimated
decommissioning costs. The rate adjustment is used to determine the amount collectible from PECO customers. On March 31, 2017, PECO filed its Nuclear
Decommissioning Cost Adjustment with the PAPUC proposing an annual recovery from customers of approximately $4 million. This amount reflects a
decrease from the previously approved annual collection of approximately $24 million primarily due to the removal of the collections for Limerick Units 1 and
2 as a result of the NRC approving the extension of the operating licenses for an additional 20 years. On August 8, 2017, the PAPUC approved the filing and
the new rates became effective January 1, 2018.
Any shortfall of funds necessary for decommissioning, determined for each generating station unit, is ultimately required to be funded by Generation, with the
exception of a shortfall for the current decommissioning activities at Zion Station, where certain decommissioning activities have been transferred to a third-
party (see Zion Station Decommissioning below) and the CENG units, where any shortfall is required to be funded by both Generation and EDF. Generation,
through PECO, has recourse to collect additional amounts from PECO customers related to a shortfall of NDT funds for the former PECO units, subject to
certain limitations and thresholds, as prescribed by an order from the PAPUC. Generally, PECO, and likewise Generation will not be allowed to collect
amounts associated with the first $50 million of any shortfall of trust funds compared to decommissioning costs, as well as 5% of any additional shortfalls, on
an aggregate basis for all former PECO units. The initial $50 million and up to 5% of any additional shortfalls would be borne by Generation. No recourse
exists to collect additional amounts from utility customers for any of Generation's other nuclear units. With respect to the former ComEd and PECO units, any
funds remaining in the NDTs after all decommissioning has been completed are required to be refunded to ComEd’s or PECO’s customers, subject to certain
limitations that allow sharing of excess funds with Generation related to the former PECO units. With respect to Generation's other nuclear units, Generation
retains any funds remaining after decommissioning. However, in connection with CENG's acquisition of the Nine Mile Point and Ginna plants and
settlements with certain regulatory agencies, CENG is subject to certain conditions pertaining to NDT funds that, if met, could possibly result in obligations to
make payments to certain third parties (clawbacks). For Nine Mile Point and Ginna, the clawback provisions are triggered only in the event
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Combined Notes to Consolidated Financial Statements
(Dollars in millions, except per share data unless otherwise noted)
Note 10 — Asset Retirement Obligations
that the required decommissioning activities are discontinued or not started or completed in a timely manner. In the event that the clawback provisions are
triggered for Nine Mile Point, then, depending upon the triggering event, an amount equal to 50% of the total amount withdrawn from the funds for non-
decommissioning activities or 50% of any excess funds in the trust funds above the amounts required for decommissioning (including spent fuel
management and decommissioning) is to be paid to the Nine Mile Point sellers. In the event that the clawback provisions are triggered for Ginna, then an
amount equal to any estimated cost savings realized by not completing any of the required decommissioning activities is to be paid to the Ginna sellers.
Generation expects to comply with applicable regulations and timely commence and complete all required decommissioning activities.
At December 31, 2020 and 2019, Exelon and Generation had NDT funds totaling $14,599 million and $13,353 million, respectively. The NDT funds include
$134 million and $163 million for the current portion of the NDT at December 31, 2020 and 2019, respectively, which are included in Other current assets in
Exelon's and Generation's Consolidated Balance Sheets. See Note 24 — 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, as described below, from the calculation used in the NRC minimum funding obligation
filings based on NRC guidelines.
For the former PECO units, given the symmetric settlement provisions that allow for continued recovery of decommissioning costs from PECO customers in
the event of a shortfall and the obligation for Generation to ultimately return any excess funds to PECO customers (on an aggregate basis for all seven
units), decommissioning-related activities are generally offset within Exelon’s and Generation’s Consolidated Statements of Operations and Comprehensive
Income regardless of whether the NDT funds are expected to exceed or fall short of the total estimated decommissioning obligation. The offset of
decommissioning-related activities within the Consolidated Statement of Operations and Comprehensive Income results in an equal adjustment to the
noncurrent payables or noncurrent receivables to affiliates at Generation with PECO recording an equal noncurrent affiliate receivable from or payable to
Generation and a corresponding regulatory liability or regulatory asset. Any changes to the existing PECO regulatory agreements could impact Exelon’s and
Generation’s ability to offset decommissioning-related activities within the Consolidated Statement of Operations and Comprehensive Income, and the
impact to Exelon’s and Generation’s financial statements could be material.
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 Statement 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.
As of December 31, 2020, decommissioning-related activities for all of the former ComEd units, except for Zion (see Zion Station Decommissioning below),
are currently offset within Exelon’s and Generation’s Consolidated Statements of Operations and Comprehensive Income.
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Combined Notes to Consolidated Financial Statements
(Dollars in millions, except per share data unless otherwise noted)
Note 10 — Asset Retirement Obligations
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 3 — Regulatory Matters and Note 25 — Related Party Transactions for additional information regarding regulatory liabilities at ComEd and PECO
and intercompany balances between Generation, ComEd, and PECO reflecting the obligation to refund to customers any decommissioning-related assets in
excess of the related decommissioning obligations.
Zion Station Decommissioning
In 2010, Generation completed an ASA under which ZionSolutions assumed responsibility for decommissioning Zion Station and Generation transferred to
ZionSolutions substantially all the Zion Station’s assets, including the related NDT funds.
Following ZionSolutions' completion of its contractual obligations and transfer of the NRC license to Generation, Generation will store the SNF at Zion
Station until it is transferred to the DOE for ultimate disposal, and will complete all remaining decommissioning activities associated with the SNF dry storage
facility.
Generation had retained its obligation for the SNF as well as certain NDT assets to fund its obligation to maintain the SNF at Zion Station until transfer to the
DOE and to complete all remaining decommissioning activities for the SNF storage facility. Any shortage of funds necessary to maintain the SNF and
decommission the SNF storage facility is ultimately required to be funded by Generation. As of December 31, 2020, the ARO associated with Zion's SNF
storage facility is $175 million and the NDT funds available to fund this obligation are $66 million.
NRC Minimum Funding Requirements
NRC regulations require that licensees of nuclear generating facilities demonstrate reasonable assurance that funds will be available in specified minimum
amounts to decommission the facility at the end of its life. The estimated decommissioning obligations as calculated using the NRC methodology differ from
the ARO recorded in Generation’s and Exelon’s Consolidated Balance Sheets primarily due to differences in the type of costs included in the estimates, the
basis for estimating such costs, and assumptions regarding the decommissioning alternatives to be used, potential license renewals, decommissioning cost
escalation, and the growth rate in the NDT funds. Under NRC regulations, if the minimum funding requirements calculated under the NRC methodology are
less than the future value of the NDT funds, also calculated under the NRC methodology, then the NRC requires either further funding or other financial
guarantees.
Key assumptions used in the minimum funding calculation using the NRC methodology at December 31, 2020 include: (1) consideration of costs only for the
removal of radiological contamination at each unit; (2) the option on a unit-by-unit basis to use generic, non-site specific cost estimates; (3) consideration of
only one decommissioning scenario for each unit; (4) the plants cease operation at the end of their current license lives (with no assumed license renewals
for those units that have not already received renewals); (5) the assumption of current nominal dollar cost estimates that are neither escalated through the
anticipated period of decommissioning, nor discounted using the CARFR; and (6) assumed annual after-tax returns on the NDT funds of 2% (3% for the
former PECO units, as specified by the PAPUC).
In contrast, the key criteria and assumptions used by Generation to determine the ARO and to forecast the target growth in the NDT funds at December 31,
2020 include: (1) the use of site specific cost estimates that are updated at least once every five years; (2) the inclusion in the ARO estimate of all legally
unavoidable costs required to decommission the unit (e.g., radiological decommissioning and full site restoration for certain units, on-site spent fuel
maintenance and storage subsequent to ceasing operations and until DOE acceptance, and disposal of certain LLRW); (3) the consideration of multiple
scenarios where decommissioning and site restoration activities, as applicable, are completed under possible scenarios ranging from 10 to 70 years after the
cessation of plant operations; (4) the consideration of multiple end of life scenarios; (5) the measurement of the obligation at the present value of the future
estimated costs and an annual average accretion of the ARO of approximately 4% through a period of approximately 30 years after the end of the extended
lives of the units; and (6) an estimated targeted annual pre-tax return on the NDT funds of 5.6% to 6.1% (as compared to a historical 5-year annual average
pre-tax return of approximately 9.0%).
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Combined Notes to Consolidated Financial Statements
(Dollars in millions, except per share data unless otherwise noted)
Note 10 — Asset Retirement Obligations
Generation is required to provide to the NRC a biennial report by unit (annually for units that have been retired or are within five years of the current
approved license life), based on values as of December 31, addressing Generation’s ability to meet the NRC minimum funding levels. Depending on the
value of the trust funds, Generation may be required to take steps, such as providing financial guarantees through letters of credit or parent company
guarantees or making additional contributions to the trusts, which could be significant, to ensure that the trusts are adequately funded and that NRC
minimum funding requirements are met. As a result, Exelon’s and Generation’s cash flows and financial positions may be significantly adversely affected.
Generation filed its biennial decommissioning funding status report with the NRC on April 1, 2019 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, 2018 for all units except for Clinton and Peach Bottom Unit 1. As of February 28, 2019, Clinton demonstrated
adequate minimum funding assurance due to market recovery and no further action is required. This demonstration was also included in the April 1, 2019
submittal. On March 31, 2020, Generation filed its annual decommissioning funding status report with the NRC for Generation’s shutdown units (excluding
Zion Station for the reason noted above). The annual status report demonstrated adequate decommissioning funding assurance as of December 31, 2019,
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.
Generation will file its next decommissioning funding status report with the NRC by March 31, 2021. This report will reflect the status of decommissioning
funding assurance as of December 31, 2020 and will include the 2021 early retirements of Byron and Dresden. A shortfall could require Exelon to post
parental guarantee for Generation’s share of the funding assurance. However, the amount of any required guarantee will ultimately depend on the
decommissioning approach adopted at Byron and Dresden, the associated level of costs, and the decommissioning trust fund investment performance going
forward.
As the future values of trust funds change due to market conditions, the NRC minimum funding status of Generation’s units will change. In addition, if
changes occur to the regulatory agreement with the PAPUC that currently allows amounts to be collected from PECO customers for decommissioning the
former PECO units, the NRC minimum funding status of those plants could change at subsequent NRC filing dates.
Non-Nuclear Asset Retirement Obligations (All Registrants)
Generation has AROs for plant closure costs associated with its fossil and renewable generating facilities, including asbestos abatement, removal of certain
storage tanks, restoring leased land to the condition it was in prior to construction of renewable generating stations and other decommissioning-related
activities. The Utility Registrants have AROs primarily associated with the abatement and disposal of equipment and buildings contaminated with asbestos
and PCBs. See Note 1 — Significant Accounting Policies for additional information on the Registrants’ accounting policy for AROs.
279
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Combined Notes to Consolidated Financial Statements
(Dollars in millions, except per share data unless otherwise noted)
Note 10 — Asset Retirement Obligations
The following table provides a rollforward of the non-nuclear AROs reflected in the Registrants’ Consolidated Balance Sheets from January 1, 2019 to
December 31, 2020:
Non-nuclear AROs at January 1, 2019
$
471 $
238 $
121 $
28 $
25 $
52 $
37 $
11 $
4
Exelon
Generation
ComEd
PECO
BGE
PHI
Pepco
DPL
ACE
Net increase (decrease) due to changes in,
and timing of, estimated future cash flows
Development projects
Accretion expense
Asset divestitures
(a)
Payments
Non-nuclear AROs at December 31, 2019
Net increase (decrease) due to changes in,
and timing of, estimated future cash flows
Development projects
Accretion expense
(a)
Asset divestitures
Payments
AROs reclassified to liabilities held for sale
(b)
17
2
16
(42)
(4)
460
7
1
16
(4)
(9)
(10)
7
2
12
(42)
(1)
216
2
1
11
(4)
(4)
(10)
8
—
1
—
(1)
129
—
—
1
—
(1)
—
—
—
1
—
(1)
28
2
—
1
—
(2)
—
(2)
—
1
—
(1)
23
1
—
1
—
(2)
—
4
—
1
—
—
57
1
—
1
—
—
—
3
—
1
—
—
41
(3)
—
1
—
—
—
1
—
—
—
—
12
2
—
—
—
—
—
Non-nuclear AROs at December 31, 2020
$
461 $
212 $
129 $
29 $
23 $
59 $
39 $
14 $
—
—
—
—
—
4
2
—
—
—
—
—
6
__________
(a) For ComEd, PECO, BGE, PHI, Pepco, and DPL, the majority of the accretion is recorded as an increase to a regulatory asset due to the associated regulatory treatment.
(b) Represents AROs related to Generation's solar business, which were classified as held for sale as a result of the sale agreement. See Note 2 — Mergers, Acquisitions,
and Dispositions for additional information.
11. Leases (All Registrants)
Lessee
The Registrants have operating and finance leases for which they are the lessees. The following tables outline the significant types of leases at each
registrant and other terms and conditions of the lease agreements as of December 31, 2020. Exelon, Generation, ComEd, PECO, and BGE did not have
material finance leases in 2020 or in 2019. PHI, Pepco, DPL, and ACE also did not have material finance leases in 2019.
Contracted generation
Real estate
Vehicles and equipment
(in years)
Remaining lease terms
Options to extend the term
Options to terminate within
Exelon
Generation
ComEd
PECO
BGE
PHI
Pepco
DPL
ACE
●
●
●
●
●
●
●
●
●
●
●
●
●
●
●
●
●
●
●
●
Exelon
Generation
ComEd
PECO
BGE
PHI
Pepco
DPL
ACE
1-85
2-30
1-12
1-35
2-30
1-4
1-4
5
2
1-13
N/A
N/A
1-85
N/A
1
1-11
3-30
N/A
1-11
5
N/A
1-11
3-30
N/A
1-7
5
N/A
280
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Combined Notes to Consolidated Financial Statements
(Dollars in millions, except per share data unless otherwise noted)
Note 11 — Leases
The components of operating lease costs were as follows:
For the year ended December 31, 2020
Operating lease costs
Variable lease costs
Short-term lease costs
Total lease costs
(a)
For the year ended December 31, 2019
Operating lease costs
Variable lease costs
Short-term lease costs
Total lease costs
(a)
Exelon
Generation
ComEd
PECO
BGE
PHI
Pepco
DPL
ACE
$
$
$
$
292
241
2
535
320
300
19
639
$
$
$
$
194
234
2
430
222
282
19
523
$
$
$
$
3
1
—
4
3
2
—
5
$
$
$
$
1
—
—
1
1
—
—
1
$
$
$
$
33
1
—
34
33
2
—
35
$
$
$
$
46
2
—
48
48
6
—
54
$
$
$
$
11
1
—
12
12
2
—
14
$
$
$
$
13
1
—
14
14
2
—
16
$
$
$
$
6
—
—
6
7
1
—
8
__________
(a) Excludes $48 million, $44 million, $4 million, and $4 million of sublease income recorded at Exelon, Generation, PHI, and DPL, respectively, for the year ended
December 31, 2020 and $51 million, $44 million, $7 million, and $7 million of sublease income recorded at Exelon, Generation, PHI, and DPL, respectively, for the year
ended December 31, 2019.
PHI, Pepco, DPL, and ACE recorded finance lease costs of $9 million, $3 million, $4 million, and $2 million, respectively, for the year ended December 31,
2020.
The following table presents the Registrants' rental expense under the prior lease accounting guidance for the year ended December 31, 2018:
Rent expense
$
670
$
558
$
7
$
10
$
35
$
48
$
10
$
13
$
8
Exelon
Generation
(a)
ComEd
PECO
BGE
PHI
Pepco
DPL
ACE
__________
(a)
Includes contingent operating lease payments associated with contracted generation agreements that are not included in the minimum future operating lease payments
table. Payments made under Generation's contracted generation lease agreements totaled $493 million.
281
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Combined Notes to Consolidated Financial Statements
(Dollars in millions, except per share data unless otherwise noted)
Note 11 — Leases
The following tables provide additional information regarding the presentation of operating and finance lease ROU assets and lease liabilities within the
Registrants’ Consolidated Balance Sheets:
As of December 31, 2020
Operating lease ROU assets
Other deferred debits and other assets
$
1,064
$
726
$
7
$
1
$
46
$
241
$
49
$
54
$
15
Exelon
(a)
Generation
(a)
ComEd
PECO
BGE
PHI
Pepco
DPL
ACE
Operating Leases
Operating lease liabilities
Other current liabilities
Other deferred credits and other liabilities
Total operating lease liabilities
As of December 31, 2019
Operating lease ROU assets
213
1,089
1,302
$
$
132
775
907
$
3
5
8
$
—
1
1
$
45
19
64
$
31
224
255
$
6
46
52
$
9
56
65
$
4
11
15
Other deferred debits and other assets
$
1,305
$
895
$
9
$
2
$
77
$
273
$
56
$
63
$
18
Operating lease liabilities
Other current liabilities
Other deferred credits and other liabilities
Total operating lease liabilities
225
1,307
1,532
$
$
157
925
1,082
$
3
8
11
$
—
1
1
$
32
50
82
$
31
254
285
$
6
51
57
$
9
65
74
$
4
14
18
__________
(a) Exelon's and Generation's operating ROU assets and lease liabilities include $387 million and $528 million, respectively, related to contracted generation as of
December 31, 2020, and $515 million and $664 million, respectively, as of December 31, 2019.
As of December 31, 2020
Finance lease ROU assets
Plant, property and equipment, net
Finance lease liabilities
Long-term debt due within one year
Long-term debt
Total finance lease liabilities
PHI
Pepco
DPL
ACE
Finance Leases
$
$
50
$
17
$
20
$
7
43
50
$
2
15
17
$
3
17
20
$
13
2
11
13
The weighted average remaining lease terms, in years, for operating and finance leases were as follows:
As of December 31, 2020
As of December 31, 2019
10.1
10.1
10.5
10.6
3.8
4.6
4.2
4.4
8.3
5.4
8.2
9.0
9.1
9.8
9.1
9.7
4.0
4.7
Exelon
Generation
ComEd
PECO
BGE
PHI
Pepco
DPL
ACE
Operating Leases
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Combined Notes to Consolidated Financial Statements
(Dollars in millions, except per share data unless otherwise noted)
Note 11 — Leases
As of December 31, 2020
PHI
Pepco
DPL
ACE
6.5
6.3
6.5
6.5
Finance Leases
The weighted average discount rates for operating and finance leases were as follows:
As of December 31, 2020
As of December 31, 2019
4.7 %
4.6 %
4.9 %
4.8 %
3.0 %
3.0 %
2.9 %
3.2 %
3.8 %
3.6 %
4.2 %
4.2 %
4.0 %
4.0 %
4.0 %
4.0 %
3.5 %
3.6 %
Exelon
Generation
ComEd
PECO
BGE
PHI
Pepco
DPL
ACE
Operating Leases
As of December 31, 2020
PHI
Pepco
DPL
ACE
2.5 %
2.6 %
2.4 %
2.4 %
Finance Leases
Future minimum lease payments for operating and finance leases as of December 31, 2020 were as follows:
Year
2021
2022
2023
2024
2025
Remaining years
Total
Interest
Total operating lease liabilities
$
$
Year
2021
2022
2023
2024
2025
Remaining years
Total
Interest
Total finance lease liabilities
Exelon
Generation
ComEd
PECO
BGE
PHI
Pepco
DPL
ACE
Operating Leases
239
177
146
141
140
834
1,677
375
1,302
$
$
145
113
100
98
99
640
1,195
288
907
$
$
3
2
1
1
1
—
8
—
8
$
$
1
—
—
—
—
—
1
—
1
$
$
46
16
1
—
—
18
81
17
64
$
$
40
39
38
36
33
120
306
51
255
$
$
Finance Leases
8
8
7
6
6
28
63
11
52
$
$
11
10
9
8
7
35
80
15
65
$
$
PHI
Pepco
DPL
ACE
$
$
8
8
8
8
8
13
53
3
50
$
$
3
3
3
3
3
3
18
1
17
$
$
3
3
3
3
3
6
21
1
20
$
$
Cash paid for amounts included in the measurement of operating and finance lease liabilities were as follows:
Exelon
Generation
ComEd
PECO
BGE
PHI
Pepco
DPL
ACE
For the year ended December
31, 2020
For the year ended December
31, 2019
$
271
$
204
$
287
206
3
3
$
1
$
20
$
39
$
—
33
37
$
8
9
$
9
6
Operating cash flows from operating leases
5
4
3
2
2
—
16
1
15
2
2
2
2
2
4
14
1
13
4
5
283
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Combined Notes to Consolidated Financial Statements
(Dollars in millions, except per share data unless otherwise noted)
Note 11 — Leases
For the year ended December 31, 2020
$
6
$
2
$
3
$
1
PHI
Pepco
DPL
ACE
Financing cash flows from finance leases
ROU assets obtained in exchange for operating and finance lease obligations were as follows:
For the year ended December
31, 2020
For the year ended December
31, 2019
Exelon
Generation
ComEd
PECO
BGE
PHI
Pepco
DPL
ACE
$
1
$
3
$
—
$
1
$
—
$
(1)
$
—
$
(1)
$
Operating Leases
52
14
6
—
2
(3)
(1)
(2)
For the year ended December 31, 2020
$
29
$
8
$
14
$
PHI
Pepco
DPL
ACE
Finance Leases
—
(1)
7
Lessor
The Registrants have operating leases for which they are the lessors. The following tables outline the significant types of leases at each registrant and other
terms and conditions of their lease agreements as of December 31, 2020.
Contracted generation
Real estate
●
●
●
●
●
●
●
Exelon
Generation
ComEd
PECO
BGE
PHI
●
PHI
Pepco
DPL
ACE
●
●
●
Pepco
DPL
ACE
(in years)
Remaining lease terms
Options to extend the term
Exelon
Generation
ComEd
PECO
BGE
1-82
1-79
1-31
1-5
1-16
5-79
1-82
5-50
22
N/A
1-12
5
1-5
N/A
11-12
N/A
1
N/A
The components of lease income were as follows:
Exelon
Generation
ComEd
PECO
BGE
PHI
Pepco
DPL
ACE
For the year ended December 31,
2020
Operating lease income
Variable lease income
For the year ended December 31,
2019
Operating lease income
Variable lease income
$
$
$
$
52
283
54
261
$
$
47
282
47
258
$
$
—
—
—
—
$
$
—
—
—
—
$
$
—
—
—
—
3
1
5
3
Future minimum lease payments to be recovered under operating leases as of December 31, 2020 were as follows:
Year
2021
2022
2023
2024
2025
Remaining years
Total
Exelon
Generation
ComEd
PECO
BGE
PHI
$
$
51
50
49
49
48
217
464
$
$
45
45
45
45
45
182
407
$
$
—
—
—
—
—
1
1
$
$
—
—
—
—
—
4
4
$
$
—
—
—
—
—
1
1
$
$
4
4
4
3
4
31
50
$
$
$
$
—
—
—
—
1
—
—
—
—
—
1
$
$
$
$
3
1
4
3
3
3
4
3
4
31
48
$
$
$
$
DPL
—
—
—
—
—
—
—
—
—
—
—
ACE
Pepco
284
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Combined Notes to Consolidated Financial Statements
(Dollars in millions, except per share data unless otherwise noted)
Note 12 — Asset Impairments
12. 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 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 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.
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 17 - Debt and Credit Agreements for additional information.
New England Asset Group
During the first quarter of 2018, Mystic Unit 9 did not clear in the ISO-NE capacity auction for the 2021 - 2022 planning year. On March 29, 2018, Generation
notified grid operator ISO-NE of its plans to early retire its Mystic Units 8 and 9 absent regulatory reforms on June 1, 2022. These events suggested that the
carrying value of the New England asset group may be impaired. In the first quarter of 2018, Generation completed a comprehensive review of the estimated
undiscounted future cash flows of the New England asset group and no impairment charge was required.
In the third quarter of 2020, in conjunction with the retirement announcement of Mystic Units 8 and 9, Generation completed a comprehensive review of the
estimated undiscounted future cash flows of the New England asset group and concluded that the estimated undiscounted future cash flows and fair value of
the New England asset group were less than their carrying values. As a result, a pre-tax impairment charge of $500 million was recorded in the third quarter
of 2020 within Operating and maintenance expense in Exelon’s and Generation’s Consolidated Statements of Operations and Comprehensive Income. See
Note 7 - Early Plant Retirements for additional information.
Midwest Asset Group
In the third quarter of 2020, in conjunction with the retirement announcements of the Byron and Dresden nuclear plants, Generation completed a
comprehensive review of the estimated undiscounted future cash flows of the Midwest asset group and no impairment charge was required.
Generation will continue to monitor the recoverability of the carrying value of the Midwest asset group as certain other nuclear plants in Illinois are also
showing increased signs of economic distress, which could lead to an early retirement. See Note 7 - Early Plant Retirements for additional information.
Equity Method Investments in Certain Distributed Energy Companies
In the third quarter of 2019, Generation’s equity method investments in certain distributed energy companies were fully impaired due to an other-than-
temporary decline in market conditions and underperforming projects.
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Combined Notes to Consolidated Financial Statements
(Dollars in millions, except per share data unless otherwise noted)
Note 12 — Asset Impairments
Exelon and Generation recorded a pre-tax impairment charge of $164 million in Equity in losses of unconsolidated affiliates and an offsetting pre-tax $96
million in Net income attributable to noncontrolling interests in their Consolidated Statements of Operations and Comprehensive Income. As a result,
Generation accelerated the amortization of investment tax credits associated with these companies and Exelon and Generation recorded a benefit of $46
million in Income taxes. The impairment charge and the accelerated amortization of investment tax credits resulted in a net $15 million decrease to Exelon’s
and Generation’s earnings. See Note 23 — Variable Interest Entities for additional information.
13. Intangible Assets (Exelon, Generation, ComEd, PHI, Pepco, DPL, and ACE)
Goodwill
The following table presents the gross amount, accumulated impairment loss, and carrying amount of goodwill at Exelon, ComEd, and PHI as of
December 31, 2020 and 2019. There were no additions or impairments during the years ended December 31, 2020 and 2019.
Exelon
(a)
ComEd
(b)
PHI
Gross Amount
Accumulated Impairment
Loss
Carrying Amount
$
8,660 $
1,983 $
4,608
4,005
1,983
—
6,677
2,625
4,005
__________
(a) Reflects goodwill recorded in 2000 from the PECO/Unicom merger (predecessor parent company of ComEd).
(b) Reflects goodwill recorded in 2016 from the PHI merger.
Goodwill is not amortized, but is subject to an assessment for impairment at least annually, or more frequently if events occur or circumstances change that
would more likely than not reduce the fair value of ComEd's and PHI's reporting units below their carrying amounts. A reporting unit is an operating segment
or one level below an operating segment (known as a component) and is the level at which goodwill is assessed for impairment. A component of an
operating segment is a reporting unit if the component constitutes a business for which discrete financial information is available and its operating results are
regularly reviewed by segment management. ComEd has a single operating segment. PHI's operating segments are Pepco, DPL, and ACE. See Note 5 —
Segment Information for additional information. There is no level below these operating segments for which operating results are regularly reviewed by
segment management. Therefore, the ComEd, Pepco, DPL, and ACE operating segments are also considered reporting units for goodwill impairment
assessment purposes. Exelon's and ComEd's $2.6 billion of goodwill has been assigned entirely to the ComEd reporting unit, while Exelon's and PHI's
$4.0 billion of goodwill has been assigned to the Pepco, DPL, and ACE reporting units in the amounts of $2.1 billion, $1.4 billion, and $0.5 billion,
respectively.
Entities assessing goodwill for impairment have the option of first performing a qualitative assessment to determine whether a quantitative assessment is
necessary. As part of the qualitative assessments, Exelon, ComEd, and PHI evaluate, among other things, management's best estimate of projected
operating and capital cash flows for their businesses, outcomes of recent regulatory proceedings, changes in certain market conditions, including the
discount rate and regulated utility peer EBITDA multiples, and the passing margin from their last quantitative assessments performed. If an entity bypasses
the qualitative assessment, a quantitative, fair value-based assessment is performed, which compares the fair value of the reporting unit to its carrying
amount, including goodwill. If the carrying amount of the reporting unit exceeds its fair value, the entity recognizes an impairment charge, which is limited to
the amount of goodwill allocated to the reporting unit.
Application of the goodwill impairment assessment requires management judgment, including the identification of reporting units and determining the fair
value of the reporting unit, which management estimates using a weighted combination of a discounted cash flow analysis and a market multiples analysis.
Significant assumptions used in these fair value analyses include discount and growth rates, utility sector market performance and transactions, projected
operating and capital cash flows for ComEd's, Pepco's, DPL's, and ACE's businesses, and the fair value of debt.
286
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Combined Notes to Consolidated Financial Statements
(Dollars in millions, except per share data unless otherwise noted)
Note 13 — Intangible Assets
2020 and 2019 Goodwill Impairment Assessment. ComEd and PHI qualitatively determined that it was more likely than not that the fair values of their
reporting units exceeded their carrying values and, therefore, did not perform quantitative assessments as of November 1, 2020 and 2019 for ComEd and
PHI. The last quantitative assessments performed were as of November 1, 2016 for ComEd and November 1, 2018 for PHI.
While the annual assessments indicated no impairments, certain assumptions used to estimate reporting unit fair values are highly sensitive to changes.
Adverse regulatory actions or changes in significant assumptions could potentially result in future impairments of Exelon's, ComEd's, and PHI’s goodwill,
which could be material.
Other Intangible Assets and Liabilities
Exelon’s, Generation’s, ComEd’s, and PHI's other intangible assets and liabilities, included in Unamortized energy contract assets and liabilities and Other
deferred debits and other assets in their Consolidated Balance Sheets, consisted of the following as of December 31, 2020 and 2019. The intangible assets
and liabilities shown below are amortized on a straight line basis, except for unamortized energy contracts which are amortized in relation to the expected
realization of the underlying cash flows:
Generation
Unamortized Energy Contracts
$
1,963 $
(1,642) $
321 $
1,967 $
(1,612) $
December 31, 2020
Accumulated
Amortization
Gross
Net
Gross
December 31, 2019
Accumulated
Amortization
Net
Customer Relationships
Trade Name
ComEd
Chicago Settlement Agreements
PHI
326
222
162
(215)
(197)
(162)
111
25
—
343
243
162
(190)
(193)
(155)
355
153
50
7
Unamortized Energy Contracts
(1,515)
1,188
(327)
(1,515)
1,073
(442)
Exelon Corporate
Software License
Exelon
95
(53)
42
95
(44)
$
1,253 $
(1,081) $
172 $
1,295 $
(1,121) $
51
174
The following table summarizes the amortization expense related to intangible assets and liabilities for each of the years ended December 31, 2020, 2019,
and 2018:
For the Years Ended December 31,
Exelon
(a)(b)
Generation
(a)
ComEd
PHI
(b)
2020
2019
2018
$
(17) $
(28)
(109)
81 $
74
63
7 $
7
7
(115)
(119)
(188)
__________
(a) At Exelon and Generation, amortization of unamortized energy contracts totaling $30 million, $21 million, and $14 million for the years ended December 31, 2020, 2019,
and 2018, respectively, was recorded in Operating revenues or Purchased power and fuel expense in their Consolidated Statements of Operations and Comprehensive
Income.
(b) At Exelon and PHI, amortization of the unamortized energy contract fair value adjustment amounts and the corresponding offsetting regulatory asset and liability amounts
are amortized through Purchased power and fuel expense in their Consolidated Statements of Operations and Comprehensive Income.
The following table summarizes the estimated future amortization expense related to intangible assets and liabilities as of December 31, 2020:
For the Years Ending December 31,
Exelon
Generation
PHI
2021
2022
2023
2024
2025
$
(1) $
(22)
(20)
20
40
81 $
57
51
48
41
(92)
(89)
(81)
(38)
(5)
287
Table of Contents
Combined Notes to Consolidated Financial Statements
(Dollars in millions, except per share data unless otherwise noted)
Note 13 — Intangible Assets
Renewable Energy Credits (Exelon and Generation)
Exelon’s and Generation’s RECs are included in Other current assets and Other deferred debits and other assets in the Consolidated Balance Sheets.
Purchased RECs are recorded at cost on the date they are purchased. The cost of RECs purchased on a stand-alone basis is based on the transaction
price, while the cost of RECs acquired through PPAs represents the difference between the total contract price and the market price of energy at contract
inception. Generally, revenue for RECs that are sold to a counterparty under a contract that specifically identifies a power plant is recognized at a point in
time when the power is produced. This includes both bundled and unbundled REC sales. Otherwise, the revenue is recognized upon physical transfer of the
REC to the customer.
The following table presents the current and noncurrent RECs as of December 31, 2020 and 2019:
Current REC's
Noncurrent REC's
14. Income Taxes (All Registrants)
Components of Income Tax Expense or Benefit
As of December 31, 2020
As of December 31, 2019
Exelon
Generation
Exelon
Generation
$
632 $
—
621 $
—
345 $
86
336
86
Income tax expense (benefit) from continuing operations is comprised of the following components:
Included in operations:
Federal
Current
Deferred
Investment tax credit amortization
State
Current
Deferred
Total
Included in operations:
Federal
Current
Deferred
Investment tax credit amortization
State
Current
Deferred
Total
Exelon
Generation
ComEd
PECO
BGE
PHI
Pepco
DPL
ACE
For the Year Ended December 31, 2020
$
26 $
130 $
(24) $
(7) $
4 $
25 $
40 $
(13) $
156
(28)
42
177
150
(25)
40
(46)
112
(2)
(27)
118
1
—
—
(24)
10
—
—
27
(129)
(1)
(5)
33
(62)
—
—
15
(20)
—
—
8
(4)
(43)
—
—
6
$
373 $
249 $
177 $
(30) $
41 $
(77) $
(7) $
(25) $
(41)
Exelon
Generation
ComEd
PECO
BGE
PHI
Pepco
DPL
ACE
For the Year Ended December 31, 2019
$
85 $
147 $
59 $
45 $
(51) $
43 $
16 $
29 $
489
(72)
5
267
346
(69)
10
82
15
(2)
(5)
96
20
—
—
—
95
—
—
35
(34)
(1)
3
27
(6)
—
—
6
(21)
—
—
14
$
774 $
516 $
163 $
65 $
79 $
38 $
16 $
22 $
(3)
(6)
—
—
9
—
288
Table of Contents
Combined Notes to Consolidated Financial Statements
(Dollars in millions, except per share data unless otherwise noted)
Note 14 — Income Taxes
Exelon
Generation
ComEd
PECO
BGE
PHI
Pepco
DPL
ACE
For the Year Ended December 31, 2018
$
226 $
337 $
(63) $
11 $
(5) $
(4) $
28 $
(3) $
(14)
(99)
(24)
(1)
16
(347)
(21)
6
(83)
145
(2)
(29)
117
10
—
1
(16)
47
—
—
32
23
(1)
7
8
(22)
—
—
5
13
—
—
12
$
118 $
(108) $
168 $
6 $
74 $
33 $
11 $
22 $
18
—
—
8
12
Included in operations:
Federal
Current
Deferred
Investment tax credit amortization
State
Current
Deferred
Total
Rate Reconciliation
The effective income tax rate from continuing operations varies from the U.S. federal statutory rate principally due to the following:
U.S. federal statutory rate
Increase (decrease) due to:
State income taxes, net of Federal
income tax benefit
Qualified NDT fund income
Deferred Prosecution Agreement
payments
Amortization of investment tax credit,
including deferred taxes on basis
difference
Plant basis differences
Production tax credits and other credits
Noncontrolling interests
Excess deferred tax amortization
Tax settlements
Other
Effective income tax rate
U.S. federal statutory rate
Increase (decrease) due to:
State income taxes, net of Federal
income tax benefit
Qualified NDT fund income
Amortization of investment tax credit,
including deferred taxes on basis
difference
Plant basis differences
Production tax credits and other credits
Noncontrolling interests
Excess deferred tax amortization
Other
Effective income tax rate
Exelon
Generation
ComEd
(b)
PECO
(c)
BGE
(d)
PHI
(d)
Pepco
(d)
DPL
(d)
ACE
(d)
21.0 %
21.0 %
21.0 %
21.0 %
21.0 %
21.0 %
21.0 %
21.0 %
21.0 %
For the Year Ended December 31, 2020
(a)
7.8
8.4
1.8
(1.1)
(4.0)
(2.2)
1.1
(13.6)
(3.7)
0.5
0.5
23.5
—
(2.6)
—
(5.4)
3.2
—
(10.3)
(0.1)
11.6
—
6.8
(0.3)
(0.6)
(0.3)
—
(11.2)
—
1.8
(4.5)
—
—
—
(18.7)
—
—
(4.6)
—
(0.4)
5.5
—
—
(0.1)
(1.5)
(0.4)
—
(13.9)
—
(0.1)
5.1
—
—
(0.2)
(1.6)
(0.3)
—
(42.0)
—
(0.4)
4.5
—
—
(0.1)
(1.7)
(0.3)
—
(25.4)
—
(0.7)
6.6
—
—
(0.3)
(0.4)
(0.3)
—
(51.7)
—
0.1
7.0
—
—
(0.5)
(3.0)
(0.5)
—
(82.1)
—
0.4
16.0 %
29.8 %
28.8 %
(7.2)%
10.5 %
(18.4)%
(2.7)%
(25.0)%
(57.7)%
Exelon
Generation
ComEd
PECO
21.0 %
21.0 %
21.0 %
21.0 %
BGE
21.0 %
PHI
Pepco
21.0 %
21.0 %
DPL
21.0 %
ACE
21.0 %
For the Year Ended December 31, 2019
(a)
5.4
5.9
(1.5)
(1.4)
(3.1)
(0.6)
(5.5)
(0.8)
3.8
12.3
(3.0)
—
(4.8)
(1.2)
—
(1.2)
8.5
—
(0.2)
—
(1.2)
—
(9.7)
0.8
—
—
—
(7.2)
—
—
(2.8)
—
6.4
—
(0.1)
(1.2)
(1.3)
—
(6.8)
—
4.7
—
(0.2)
(1.2)
(0.2)
—
(17.5)
0.8
2.0
—
(0.1)
(1.8)
(0.1)
—
(15.1)
0.3
6.8
—
(0.2)
(0.4)
—
—
(14.2)
—
7.0
—
(0.3)
(0.7)
(0.1)
—
(27.0)
0.1
19.4 %
26.9 %
19.2 %
11.0 %
18.0 %
7.4 %
6.2 %
13.0 %
— %
289
Table of Contents
Combined Notes to Consolidated Financial Statements
(Dollars in millions, except per share data unless otherwise noted)
Note 14 — Income Taxes
U.S. federal statutory rate
Increase (decrease) due to:
State income taxes, net of Federal
income tax benefit
Qualified NDT fund income
Amortization of investment tax credit,
including deferred taxes on basis
difference
Plant basis differences
Production tax credits and other credits
Noncontrolling interests
Excess deferred tax amortization
Tax Cuts and Jobs Act of 2017
Other
Effective income tax rate
Exelon
Generation
ComEd
PECO
BGE
PHI
Pepco
DPL
ACE
21.0 %
21.0 %
21.0 %
21.0 %
21.0 %
21.0 %
21.0 %
21.0 %
21.0 %
For the Year Ended December 31, 2018
(a)
0.5
(1.9)
(1.2)
(3.5)
(2.2)
(1.0)
(8.3)
0.9
1.0
5.3 %
(16.6)
(11.8)
(6.5)
—
(13.5)
(6.1)
—
2.7
1.3
(29.5)%
8.3
—
(0.2)
(0.2)
—
—
(9.1)
(0.1)
0.5
20.2 %
(2.6)
—
(0.1)
(14.1)
—
—
(3.2)
—
0.3
1.3 %
6.6
—
(0.1)
(1.3)
—
—
(8.0)
—
0.9
19.1 %
2.9
—
(0.2)
(1.6)
—
—
(14.8)
0.1
0.4
7.8 %
2.0
—
(0.1)
(2.8)
—
—
(15.3)
—
0.3
5.1 %
6.7
—
(0.3)
(0.3)
—
—
(12.0)
—
0.4
15.5 %
7.4
—
(0.4)
(0.5)
—
—
(14.9)
—
1.2
13.8 %
__________
(a) Positive percentages represent income tax expense. Negative percentages represent income tax benefit.
(b) At ComEd, the higher effective tax rate is primarily related to the nondeductible Deferred Prosecution Agreement payments. See Note 19 — Commitments and
Contingencies for additional information.
(c) At PECO, the negative effective tax rate is primarily related to an increase in plant basis differences attributable to tax repair deductions related to an increase in storms
and qualifying projects.
(d) At BGE, the lower effective tax rate, and at PHI, Pepco, DPL, and ACE, the negative effective tax rate is primarily attributable to accelerated amortization of transmission
related income tax regulatory liabilities as a result of regulatory settlements. See Note 3 — Regulatory Matters for additional information.
290
Table of Contents
Combined Notes to Consolidated Financial Statements
(Dollars in millions, except per share data unless otherwise noted)
Note 14 — Income Taxes
Tax Differences and Carryforwards
The tax effects of temporary differences and carryforwards, which give rise to significant portions of the deferred tax assets (liabilities), as of December 31,
2020 and 2019 are presented below:
Plant basis differences
$
Accrual based contracts
Derivatives and other financial
instruments
Deferred pension and
postretirement obligation
Nuclear decommissioning
activities
Deferred debt refinancing costs
Regulatory assets and liabilities
Tax loss carryforward
Tax credit carryforward
Investment in partnerships
Other, net
Deferred income tax liabilities (net)
Unamortized investment tax credits
Total deferred income tax liabilities
(net) and unamortized investment tax
credits
(a)
$
$
Exelon
Generation
ComEd
PECO
BGE
PHI
Pepco
DPL
ACE
(13,868)
40
$
(2,592)
(37)
$
(4,432)
—
$
(2,131)
—
$
(1,711)
—
$
(2,822)
77
$
(1,259)
—
$
$
(806)
—
(725)
—
As of December 31, 2020
41
1,559
(742)
169
(1,107)
286
841
(835)
1,070
(41)
(236)
(742)
16
—
55
838
(813)
347
84
(288)
—
(6)
87
—
—
—
223
—
(30)
—
—
(231)
47
—
—
104
—
(33)
—
(2)
142
57
—
—
29
2
(80)
—
131
(41)
90
—
—
220
—
(74)
—
(3)
38
4
—
—
107
—
(40)
—
(1)
67
49
—
—
18
—
(7)
—
(1)
46
38
—
—
27
(12,546)
(464)
$
(3,205)
(445)
$
(4,332)
(9)
$
(2,241)
(1)
$
(1,518)
(3)
$
(2,423)
(6)
$
(1,187)
(2)
$
$
(713)
(2)
(622)
(3)
(13,010)
$
(3,650)
$
(4,341)
$
(2,242)
$
(1,521)
$
(2,429)
$
(1,189)
$
(715)
$
(625)
__________
(a) Does not include unamortized investment tax credits reclassified to liabilities held for sale.
291
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Combined Notes to Consolidated Financial Statements
(Dollars in millions, except per share data unless otherwise noted)
Note 14 — Income Taxes
Plant basis differences
$
Accrual based contracts
Derivatives and other financial
instruments
Deferred pension and
postretirement obligation
Nuclear decommissioning
activities
Deferred debt refinancing costs
Regulatory assets and liabilities
Tax loss carryforward
Tax credit carryforward
Investment in partnerships
Other, net
Deferred income tax liabilities (net)
Unamortized investment tax credits
Total deferred income tax liabilities
(net) and
unamortized investment tax credits
$
$
Exelon
Generation
ComEd
PECO
BGE
PHI
Pepco
DPL
ACE
As of December 31, 2019
(13,413)
61
$
(2,814)
(43)
$
(4,197)
—
$
(1,978)
—
$
(1,578)
—
$
(2,681)
104
$
(1,204)
—
$
$
(753)
—
165
1,504
(503)
183
(884)
240
892
(830)
926
88
(220)
(503)
20
—
55
897
(808)
236
84
(270)
—
(7)
183
—
—
—
196
—
(28)
—
—
(169)
25
—
—
70
—
(28)
—
(3)
157
49
—
—
10
2
(89)
—
142
(10)
93
—
—
181
—
(75)
—
(3)
55
13
—
—
85
—
(42)
—
(2)
88
44
—
—
12
(687)
—
—
(10)
—
(1)
77
31
—
—
16
(11,659)
(668)
$
(3,092)
(648)
$
(4,011)
(10)
$
(2,080)
(1)
$
(1,393)
(3)
$
(2,258)
(7)
$
(1,129)
(2)
$
$
(653)
(2)
(574)
(3)
(12,327)
$
(3,740)
$
(4,021)
$
(2,081)
$
(1,396)
$
(2,265)
$
(1,131)
$
(655)
$
(577)
The following table provides Exelon’s, Generation’s, PECO’s, BGE’s, PHI’s, Pepco’s, DPL’s, and ACE’s carryforwards, which are presented on a post-
apportioned basis, and any corresponding valuation allowances as of December 31, 2020. ComEd does not have net operating losses or credit
carryforwards for the year ended December 31, 2020.
Exelon
Generation
PECO
BGE
PHI
Pepco
DPL
ACE
Federal
Federal general business credits
carryforwards and other carryforwards
State
State net operating losses and other
carryforwards
Deferred taxes on state tax attributes (net)
Valuation allowance on state tax attributes
Year in which net operating loss or credit
carryforwards will begin to expire
(a)
$
858 $
852 $
— $
— $
— $
— $
— $
—
5,202
324
27
2034
1,118
76
23
616
49
1
902
59
—
1,436
98
—
63
4
—
728
49
—
2034
2032
2033
2029
2029
2032
531
38
—
2031
__________
(a) Generation's state net operating loss carryforwards will begin expiring in 2029. PECO's Pennsylvania charitable contribution carryforwards and BGE's Maryland charitable
deduction and capital loss carryforwards will begin expiring in 2021. ACE's New Jersey tax credit carryforward has an indefinite carryforward period. These amounts are
not material.
Tabular Reconciliation of Unrecognized Tax Benefits
The following table presents changes in unrecognized tax benefits, by Registrant.
292
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Combined Notes to Consolidated Financial Statements
(Dollars in millions, except per share data unless otherwise noted)
Note 14 — Income Taxes
Balance at January 1, 2018
$
743 $
468 $
2
$
— $
120 $
125 $
59 $
21 $
Exelon
Generation
ComEd
PECO
BGE
PHI
Pepco
DPL
ACE
Change to positions that only affect
timing
Increases based on tax positions prior
to 2018
Decreases based on tax positions prior
to 2018
Decrease from settlements with taxing
authorities
(a)
Decreases from expiration of statute of
limitations
Balance at December 31, 2018
Change to positions that only affect
timing
Increases based on tax positions
related to 2019
Increases based on tax positions prior
to 2019
Decreases based on tax positions prior
to 2019
Decrease from settlements with taxing
authorities
Balance at December 31, 2019
Change to positions that only affect
timing
Increases based on tax positions
related to 2020
Increases based on tax positions prior
to 2020
Decreases based on tax positions prior
to 2020
(b)
Decrease from settlements with taxing
authorities
(b)
15
30
(251)
(53)
(7)
477
26
2
34
(3)
(29)
507
6
3
26
(348)
(69)
15
21
(36)
(53)
(7)
408
12
1
19
(3)
4
441
—
1
23
(346)
(69)
—
—
—
—
—
2
3
—
3
—
(2)
6
2
—
1
—
—
—
—
—
—
—
—
1
—
2
—
—
3
3
—
—
—
—
—
—
—
8
—
7
—
1
(120)
(88)
(66)
(22)
—
—
—
4
—
3
—
—
7
3
—
—
—
—
—
—
45
3
—
—
—
—
48
3
—
1
—
—
—
—
—
2
—
—
—
—
2
1
—
—
—
—
—
—
—
1
—
—
—
—
1
—
—
—
—
—
Balance at December 31, 2020
$
125 $
50 $
9 $
6 $
10 $
52 $
3 $
1 $
14
—
—
—
—
—
14
—
—
—
—
—
14
1
—
—
—
—
15
__________
(a) Exelon, Generation, BGE, PHI, Pepco, and DPL decreased their unrecognized state tax benefits primarily due to the receipt of favorable guidance with respect to the
deductibility of certain depreciable fixed assets. The recognition of the tax benefits related to BGE, PHI, Pepco, and DPL was offset by corresponding regulatory liabilities
and that portion had no immediate impact to their effective tax rate.
(b) Exelon's and Generation's unrecognized federal and state tax benefits decreased in the first quarter of 2020 by approximately $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.
Like-Kind Exchange
In 2016, the Tax Court held that Exelon was not entitled to defer a gain on its 1999 like-kind exchange transaction. In addition to the tax and interest related
to the gain deferral, the Tax Court also ruled that Exelon was liable for penalties and interest on the penalties. Exelon had fully paid the amounts assessed
resulting from the Tax Court decision in 2017. In September 2017, Exelon appealed the Tax Court decision to the U.S. Court of Appeals for the Seventh
Circuit. In October 2018, the U.S. Court of Appeals for the Seventh Circuit affirmed the
293
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Combined Notes to Consolidated Financial Statements
(Dollars in millions, except per share data unless otherwise noted)
Note 14 — Income Taxes
Tax Court’s decision. Exelon filed a petition seeking rehearing of the Seventh Circuit’s decision, but the Seventh Circuit denied that petition in December
2018. In the first quarter of 2019, Exelon elected not to seek a further review by the U.S. Supreme Court. As a result, Exelon's and ComEd's unrecognized
tax benefits decreased by approximately $33 million and $2 million, respectively, in the first quarter of 2019.
Recognition of unrecognized tax benefits
The following table presents Exelon's, Generation's, and PHI's unrecognized tax benefits that, if recognized, would decrease the effective tax rate. ComEd's,
PECO's, BGE's, Pepco's, DPL's, and ACE's amounts are not material.
December 31, 2020
December 31, 2019
December 31, 2018
Exelon
Generation
PHI
(a)
$
73 $
462
463
39 $
429
408
33
32
31
__________
(a) PHI has $21 million of unrecognized state tax benefits that, if recognized, $14 million would be in the form of a net operating loss carryforward, which is expected to require
a full valuation allowance based on present circumstances.
ACE has $14 million of unrecognized tax benefits as of December 31, 2020, 2019 and 2018 that, if recognized, may be included in future base rates and that
portion would have no impact on the effective tax rate. Exelon's, Generation's, ComEd's, PECO's, BGE's, PHI's, Pepco's, and DPL's amounts are not
material.
Reasonably possible the total amount of unrecognized tax benefits could significantly increase or decrease within 12 months after the reporting
date
As of December 31, 2020, ACE has approximately $14 million of unrecognized state tax benefits that could significantly decrease within the 12 months after
the reporting date based on the outcome of pending court cases involving other taxpayers. The unrecognized tax benefit, if recognized, may be included in
future base rates and that portion would have no impact to the effective tax rate.
Total amounts of interest and penalties recognized
The following table represents the net interest and penalties receivable (payable) related to tax positions reflected in Exelon's Consolidated Balance Sheets.
Generation's and the Utility Registrants' amounts are not material.
Net interest and penalties receivable as of
December 31, 2020
December 31, 2019
Exelon
$
314
318
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Combined Notes to Consolidated Financial Statements
(Dollars in millions, except per share data unless otherwise noted)
Note 14 — Income Taxes
The Registrants did not record material interest and penalty expense related to tax positions reflected in their Consolidated Balance Sheets. Interest
expense and penalty expense are recorded in Interest expense, net and Other, net, respectively, in Other income and deductions in the Registrants'
Consolidated Statements of Operations and Comprehensive Income.
Description of tax years open to assessment by major jurisdiction
Major Jurisdiction
Federal consolidated income tax returns
(a)
Delaware separate corporate income tax returns
District of Columbia combined corporate income tax returns
Illinois unitary corporate income tax returns
Maryland separate company corporate net income tax returns
New Jersey separate corporate income tax returns
New Jersey separate corporate income tax returns
New York combined corporate income tax returns
New York combined corporate income tax returns
Pennsylvania separate corporate income tax returns
Open Years
2010-2019
Same as federal
Registrants Impacted
All Registrants
DPL
2017-2019
2012-2019
Exelon, PHI, Pepco
Exelon, Generation, ComEd
Same as federal
2013-2019
2014-2019
2010-March 2012
2011-2019
2011-2019
BGE, Pepco, DPL
Exelon, Generation
ACE
Exelon, Generation
Exelon, Generation
Exelon, Generation
Pennsylvania separate corporate income tax returns
__________
(a) Certain registrants are only open to assessment for tax years since joining the Exelon federal consolidated group; BGE beginning in 2012 and PHI, Pepco, DPL, and ACE
2017-2019
PECO
beginning in 2016.
Other Tax Matters
Long-Term Marginal State Income Tax Rate (All Registrants)
Quarterly, Exelon reviews and updates its marginal state income tax rates for changes in state apportionment. The Registrants remeasure their existing
deferred income tax balances to reflect the changes in marginal rates, which results in either an increase or a decrease to their net deferred income tax
liability balances. Utility Registrants record corresponding regulatory liabilities or assets to the extent such amounts are probable of settlement or recovery
through customer rates and an adjustment to income tax expense for all other amounts. The impacts to the Utility Registrants for the years ended December
31, 2020, 2019, and 2018 were not material.
December 31, 2020
Increase (decrease) to Deferred Income Tax Liability and Income Tax Expense, Net of
Federal Taxes
December 31, 2019
Increase to Deferred Income Tax Liability and Income Tax Expense, Net of Federal
Taxes
December 31, 2018
Decrease to Deferred Income Tax Liability and Income Tax Expense, Net of Federal
Taxes
$
$
$
Allocation of Tax Benefits (All Registrants)
Exelon
Generation
66 $
23 $
(50) $
(26)
9
(53)
Generation and the Utility Registrants are all party to an agreement with Exelon and other subsidiaries of Exelon that provides for the allocation of
consolidated tax liabilities and benefits (Tax Sharing Agreement). The Tax Sharing Agreement provides that each party is allocated an amount of tax similar
to that which would be owed had the party been separately subject to tax. In addition, any net federal and state benefits attributable to Exelon is reallocated
to the other Registrants. That allocation is treated as a contribution to the capital of the party receiving the benefit.
The following table presents the allocation of tax benefits from Exelon under the Tax Sharing Agreement.
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Combined Notes to Consolidated Financial Statements
(Dollars in millions, except per share data unless otherwise noted)
Note 14 — Income Taxes
December 31, 2020
(a)
December 31, 2019
(b)
$
64 $
41
14 $
—
17 $
14
— $
3
17 $
7
8 $
6
6 $
1
Generation
ComEd
PECO
BGE
PHI
Pepco
DPL
ACE
(c)
December 31, 2018
__________
(a) BGE did not record an allocation of federal tax benefits from Exelon under the Tax Sharing Agreement as a result of a tax net operating loss.
(b) ACE did not record an allocation of federal tax benefits from Exelon under the Tax Sharing Agreement as a result of a tax net operating loss.
(c) Pepco, DPL, and ACE did not record an allocation of federal tax benefits from Exelon under the Tax Sharing Agreement as a result of a tax net operating loss.
155
48
26
—
—
1
2
1
—
—
Research and Development Activities
In the fourth quarter of 2019, Exelon and Generation recognized additional tax benefits related to certain research and development activities that qualify for
federal and state tax incentives for the 2010 through 2018 tax years, which resulted in an increase to Exelon’s and Generation’s net income of $108 million
and $75 million, respectively, for the year ended December 31, 2019, reflecting a decrease to Exelon’s and Generation’s Income tax expense of $97 million
and $66 million, respectively.
15. Retirement Benefits (All Registrants)
Exelon sponsors defined benefit pension plans and OPEB plans for essentially all current employees. Substantially all non-union employees and electing
union employees hired on or after January 1, 2001 participate in cash balance pension plans. Effective January 1, 2009, substantially all newly-hired union-
represented employees participate in cash balance pension plans. Effective February 1, 2018 for most newly-hired Generation and BSC non-represented,
non-craft, employees and January 1, 2021 for most newly-hired utility management employees, these newly-hired employees are not eligible for pension
benefits, and will instead be eligible to receive an enhanced non-discretionary employer contribution in an Exelon defined contribution savings plan. Effective
January 1, 2018, most newly-hired non-represented, non-craft, employees are not eligible for OPEB benefits and employees represented by Local 614 are
not eligible for retiree health care benefits. Effective January 1, 2021, most non-represented, non-craft, employees who are under the age of 40 are not
eligible for retiree health care benefits.
Effective January 1, 2019, Exelon merged the Exelon Corporation Cash Balance Pension Plan (CBPP) into the Exelon Corporation Retirement Program
(ECRP). The merging of the plans did not change the benefits offered to the plan participants and, thus, had no impact on Exelon's pension obligation.
However, beginning in 2019, actuarial losses and gains related to the CBPP and ECRP are amortized over participants’ average remaining service period of
the merged ECRP rather than each individual plan.
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Combined Notes to Consolidated Financial Statements
(Dollars in millions, except per share data unless otherwise noted)
Note 15 — Retirement Benefits
The table below shows the pension and OPEB plans in which employees of each operating company participated at December 31, 2020:
Name of Plan:
Qualified Pension Plans:
Generation
ComEd
PECO
BGE
PHI
Pepco
DPL
ACE
Operating Company
(e)
Exelon Corporation Retirement Program
Exelon Corporation Pension Plan for Bargaining Unit
Employees
(a)
(a)
Exelon New England Union Employees Pension Plan
Exelon Employee Pension Plan for Clinton, TMI, and
Oyster Creek
(a)
(a)
Pension Plan of Constellation Energy Group, Inc.
Pension Plan of Constellation Energy Nuclear Group,
LLC
(c)
(b)
Nine Mile Point Pension Plan
Constellation Mystic Power, LLC Union Employees
Pension Plan Including Plan A and Plan B
(b)
(c)
(d)
(b)
(b)
(a)
(a)
Pepco Holdings LLC Retirement Plan
Non-Qualified Pension Plans:
Exelon Corporation Supplemental Pension Benefit Plan
and 2000 Excess Benefit Plan
Exelon Corporation Supplemental Management
Retirement Plan
Constellation Energy Group, Inc. Senior Executive
Supplemental Plan
Constellation Energy Group, Inc. Supplemental Pension
Plan
Constellation Energy Group, Inc. Benefits Restoration
Plan
Constellation Energy Nuclear Plan, LLC Executive
Retirement Plan
Constellation Energy Nuclear Plan, LLC Benefits
Restoration Plan
Baltimore Gas & Electric Company Executive Benefit
Plan
Baltimore Gas & Electric Company Manager Benefit
Plan
Pepco Holdings LLC 2011 Supplemental Executive
Retirement Plan
Conectiv Supplemental Executive Retirement Plan
(d)
(d)
(b)
(b)
(b)
(c)
(c)
Pepco Holdings LLC Combined Executive Retirement
Plan
(d)
Atlantic City Electric Director Retirement Plan
(d)
X
X
X
X
X
X
X
X
X
X
X
X
X
X
X
X
X
X
X
X
X
X
X
X
X
X
X
X
X
X
X
X
X
X
X
X
X
X
X
X
X
X
X
X
X
X
X
X
X
X
X
X
X
X
X
X
X
X
X
X
X
X
X
X
X
X
X
X
X
X
X
X
X
X
X
X
X
X
X
X
X
297
Table of Contents
Combined Notes to Consolidated Financial Statements
(Dollars in millions, except per share data unless otherwise noted)
Name of Plan:
OPEB Plans:
PECO Energy Company Retiree Medical Plan
(a)
Exelon Corporation Health Care Program
(a)
Exelon Corporation Employees’ Life Insurance Plan
Exelon Corporation Health Reimbursement
Arrangement Plan
(a)
(a)
(b)
Constellation Energy Group, Inc. Retiree Medical Plan
(b)
Constellation Energy Group, Inc. Retiree Dental Plan
Constellation Energy Group, Inc. Employee Life
(b)
Insurance Plan and Family Life Insurance Plan
Constellation Mystic Power, LLC
Post-Employment Medical Account Savings Plan
Exelon New England Union Post-Employment Medical
Savings Account Plan
Retiree Medical Plan of Constellation Energy Nuclear
Group, LLC
Retiree Dental Plan of Constellation Energy Nuclear
Group, LLC
Nine Mile Point Nuclear Station, LLC Medical Care and
Prescription Drug Plan for Retired Employees
(b)
(a)
(c)
(c)
(c)
Pepco Holdings LLC Welfare Plan for Retirees
(d)
Note 15 — Retirement Benefits
Generation
ComEd
PECO
BGE
PHI
Pepco
DPL
ACE
Operating Company
(e)
X
X
X
X
X
X
X
X
X
X
X
X
X
X
X
X
X
X
X
X
X
X
X
X
X
X
X
X
X
X
X
X
X
X
X
X
X
X
X
X
X
X
X
X
X
X
X
X
X
X
X
X
X
X
X
X
X
__________
(a) These plans are collectively referred to as the legacy Exelon plans.
(b) These plans are collectively referred to as the legacy Constellation Energy Group (CEG) Plans.
(c) These plans are collectively referred to as the legacy CENG plans.
(d) These plans are collectively referred to as the legacy PHI plans.
(e) Employees generally remain in their legacy benefit plans when transferring between operating companies.
Exelon’s traditional and cash balance pension plans are intended to be tax-qualified defined benefit plans. Exelon has elected that the trusts underlying
these plans be treated as qualified trusts under the IRC. If certain conditions are met, Exelon can deduct payments made to the qualified trusts, subject to
certain IRC limitations.
Benefit Obligations, Plan Assets, and Funded Status
During the first quarter of 2020, Exelon received an updated valuation of its pension and OPEB to reflect actual census data as of January 1, 2020. This
valuation resulted in an increase to the pension and OPEB obligations of $8 million and $31 million, respectively. Additionally, accumulated other
comprehensive loss increased by $7 million (after-tax) and regulatory assets and liabilities increased by $19 million and decreased by $10 million,
respectively.
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Combined Notes to Consolidated Financial Statements
(Dollars in millions, except per share data unless otherwise noted)
Note 15 — Retirement Benefits
The following tables provide a rollforward of the changes in the benefit obligations and plan assets of Exelon for the most recent two years for all plans
combined:
Change in benefit obligation:
Net benefit obligation at beginning of year
Service cost
Interest cost
Plan participants’ contributions
Actuarial loss
Plan amendments
(a)
Curtailments
Settlements
Contractual termination benefits
Gross benefits paid
Net benefit obligation at end of year
Change in plan assets:
Fair value of net plan assets at beginning of year
Actual return on plan assets
Employer contributions
Plan participants’ contributions
Gross benefits paid
Settlements
Fair value of net plan assets at end of year
Pension Benefits
OPEB
2020
2019
2020
2019
22,868 $
387
20,692 $
357
4,658 $
90
757
—
2,217
—
—
(45)
—
(1,290)
883
—
2,322
68
(3)
(35)
1
(1,417)
154
49
49
(111)
—
(5)
—
(280)
24,894 $
22,868 $
4,604 $
Pension Benefits
OPEB
2020
2019
2020
2019
18,590 $
16,678 $
2,541 $
2,547
542
—
(1,290)
(45)
3,008
356
—
(1,417)
(35)
190
59
49
(280)
(5)
20,344 $
18,590 $
2,554 $
4,369
93
188
44
250
—
—
(4)
—
(282)
4,658
2,408
324
51
44
(282)
(4)
2,541
$
$
$
$
__________
(a) The pension and OPEB actuarial losses in 2020 and 2019 primarily reflect a decrease in the discount rate. OPEB losses in 2020 were offset by gains related to plan
changes.
Exelon presents its benefit obligations and plan assets net on its balance sheet within the following line items:
Other current liabilities
Pension obligations
Non-pension postretirement benefit obligations
Unfunded status (net benefit obligation less plan assets)
Pension Benefits
2020
2019
2020
47 $
31 $
4,503
—
4,247
—
OPEB
42 $
—
2,008
4,550 $
4,278 $
2,050 $
$
$
2019
41
—
2,076
2,117
The following table provides the ABO and fair value of plan assets for all pension plans with an ABO in excess of plan assets. Information for pension and
OPEB plans with projected benefit obligations (PBO) and accumulated postretirement benefit obligation (APBO), respectively, in excess of plan assets has
been disclosed in the Obligations and Plan Assets table above as all pension and OPEB plans are underfunded.
ABO in excess of plan assets
ABO
Fair value of net plan assets
Exelon
2020
2019
$
23,514 $
20,344
21,727
18,590
299
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Combined Notes to Consolidated Financial Statements
(Dollars in millions, except per share data unless otherwise noted)
Note 15 — Retirement Benefits
Components of Net Periodic Benefit Costs
The majority of the 2020 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%. The majority of the 2020 OPEB cost is calculated using an expected long-term rate of return on plan assets of 6.69%
for funded plans and a discount rate of 3.31%.
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 years ended December 31, 2020, 2019, and 2018.
Pension Benefits
2020
2019
2018
2020
OPEB
2019
2018
Components of net periodic
benefit cost:
Service cost
$
387 $
357 $
405 $
90 $
93 $
Interest cost
Expected return on assets
Amortization of:
Prior service cost (credit)
Actuarial loss
Curtailment benefits
Settlement and other charges
Contractual termination benefits
Net periodic benefit cost
757
(1,270)
883
(1,225)
802
(1,252)
4
512
—
14
—
—
414
—
17
1
2
629
—
3
—
154
(163)
(124)
49
(1)
1
—
188
(153)
(179)
45
—
1
—
$
404 $
447 $
589 $
6 $
(5) $
112
175
(173)
(186)
66
—
1
—
(5)
Cost Allocation to Exelon Subsidiaries
All Registrants account for their participation in Exelon’s pension and OPEB plans by applying multi-employer accounting. Exelon allocates costs related to
its pension and OPEB plans to its subsidiaries based on both active and retired employee participation in each plan.
The amounts below represent the Registrants' allocated pension and OPEB 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.
For the Years Ended December 31,
2020
2019
2018
$
Exelon
Generation
ComEd
PECO
BGE
PHI
Pepco
DPL
ACE
411 $
442
583
115 $
135
204
114 $
96
177
5 $
12
18
64 $
61
60
70 $
95
67
15 $
25
15
7 $
15
6
14
16
12
Components of AOCI and Regulatory Assets
Exelon recognizes the overfunded or underfunded status of defined benefit pension and OPEB plans as an asset or liability on its balance sheet, with
offsetting entries to AOCI and regulatory assets (liabilities). A portion of current year actuarial (gains) losses and prior service costs (credits) is capitalized
within Exelon’s Consolidated Balance Sheets to reflect the expected regulatory recovery of these amounts, which would otherwise be recorded to AOCI. The
following tables provide the components of AOCI and regulatory assets (liabilities) for Exelon for the years ended December 31, 2020, 2019, and 2018 for all
plans combined.
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Combined Notes to Consolidated Financial Statements
(Dollars in millions, except per share data unless otherwise noted)
Pension Benefits
2020
2019
2018
2020
OPEB
2019
2018
Note 15 — Retirement Benefits
Changes in plan assets and
benefit obligations recognized in
AOCI and regulatory assets
(liabilities):
Current year actuarial loss (gain)
$
Amortization of actuarial loss
Current year prior service cost
(credit)
Amortization of prior service (cost)
credit
Curtailments
Settlements
Total recognized in AOCI and
regulatory assets (liabilities)
Total recognized in AOCI
Total recognized in regulatory assets
(liabilities)
$
$
$
941 $
(512)
538 $
(414)
635 $
(629)
22 $
(49)
—
(4)
—
(14)
68
—
(3)
(17)
(4)
(2)
—
(3)
(111)
124
1
(1)
80 $
(45)
—
179
—
(1)
(232)
(66)
—
186
—
—
411 $
172 $
(3) $
(14) $
213 $
(112)
271 $
169 $
140 $
3 $
3 $
(6) $
6 $
107 $
(20) $
106 $
(55)
(57)
The following table provides the components of gross accumulated other comprehensive loss and regulatory assets (liabilities) for Exelon that have not been
recognized as components of periodic benefit cost at December 31, 2020 and 2019, respectively, for all plans combined:
Prior service cost (credit)
Actuarial loss
Total
Total included in AOCI
Total included in regulatory assets (liabilities)
Average Remaining Service Period
Pension Benefits
OPEB
2020
2019
2020
2019
$
$
$
$
35 $
8,077
8,112 $
4,339 $
3,773 $
39 $
7,662
7,701 $
4,068 $
3,633 $
(145) $
538
393 $
183 $
210 $
(158)
565
407
177
230
For pension benefits, Exelon amortizes its unrecognized prior service costs (credits) and certain actuarial (gains) losses, as applicable, based on
participants’ average remaining service periods.
For OPEB, Exelon amortizes its unrecognized prior service costs (credits) over participants’ average remaining service period to benefit eligibility age and
amortizes certain actuarial (gains) losses over participants’ average remaining service period to expected retirement. The resulting average remaining
service periods for pension and OPEB were as follows:
Pension plans
OPEB plans:
Benefit Eligibility Age
Expected Retirement
2020
2019
2018
12.3
9.0
10.2
11.7
8.7
9.3
12.0
8.8
9.5
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Assumptions
Combined Notes to Consolidated Financial Statements
(Dollars in millions, except per share data unless otherwise noted)
Note 15 — Retirement Benefits
The measurement of the plan obligations and costs of providing benefits under Exelon’s defined benefit and OPEB plans involves various factors, including
the development of valuation assumptions and inputs and accounting policy elections. The measurement of benefit obligations and costs is impacted by
several assumptions and inputs, as shown below, among other factors. When developing the required assumptions, Exelon considers historical information
as well as future expectations.
Expected Rate of Return. In determining the EROA, Exelon considers historical economic indicators (including inflation and GDP growth) that impact asset
returns, as well as expectations regarding future long-term capital market performance, weighted by Exelon’s target asset class allocations.
Mortality. The mortality assumption is composed of a base table that represents the current expectation of life expectancy of the population adjusted by an
improvement scale that attempts to anticipate future improvements in life expectancy. For the year ended December 31, 2020, Exelon’s mortality assumption
utilizes the SOA 2019 base table (Pri-2012) and MP-2020 improvement scale adjusted to use Proxy SSA ultimate improvement rates. For the year ended
December 31, 2019, Exelon's mortality assumption utilizes the SOA 2019 base table (Pri-2012) and MP-2019 improvement scale adjusted to a 0.75% long-
term rate reached in 2035.
For Exelon, the following assumptions were used to determine the benefit obligations for the plans at December 31, 2020 and 2019. Assumptions used to
determine year-end benefit obligations are the assumptions used to estimate the subsequent year’s net periodic benefit costs.
Discount rate
Investment crediting rate
Rate of compensation increase
Mortality table
Pension Benefits
OPEB
2020
2019
2020
2019
(a)
(b)
2.58 %
3.72 %
3.75 %
3.34 %
3.82 %
(a)
(b)
(c)
(a)
2.51 %
N/A
3.75 %
3.31 %
N/A
(a)
(c)
Pri-2012 table with MP-
2020 improvement scale
(adjusted)
Pri-2012 table with MP-
2019 improvement scale
(adjusted)
Pri-2012 table with MP-
2020 improvement scale
(adjusted)
Pri-2012 table with MP-
2019 improvement scale
(adjusted)
5.00% with
ultimate trend of 5.00% in
2017
Health care cost trend on covered charges
N/A
N/A
Initial and ultimate rate of
5.00%
__________
(a) The discount rates above represent the blended rates used to determine the majority of Exelon’s pension and OPEB obligations. Certain benefit plans used individual
rates, which range from 2.11% - 2.73% and 2.45% - 2.63% for pension and OPEB plans, respectively, as of December 31, 2020 and 3.02% - 3.44% and 3.27% - 3.40% for
pension and OPEB plans, respectively, as of December 31, 2019.
(b) The investment crediting rate above represents a weighted average rate.
(c) 3.25% through 2019 and 3.75% thereafter.
The following assumptions were used to determine the net periodic benefit cost for Exelon for the years ended December 31, 2020, 2019 and 2018:
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Combined Notes to Consolidated Financial Statements
(Dollars in millions, except per share data unless otherwise noted)
Note 15 — Retirement Benefits
Discount rate
Investment crediting
rate
Expected return on
plan assets
Rate of
compensation
increase
2020
Pension Benefits
2019
2018
2020
(a)
3.34 %
3.82 %
(b)
(c)
7.00 %
(a)
4.31 %
4.46 %
(b)
(c)
7.00 %
(a)
3.62 %
4.00 %
(b)
(c)
7.00 %
(a)
3.31 %
N/A
(c)
6.69 %
OPEB
2019
(a)
4.30 %
N/A
(c)
6.67 %
2018
(a)
3.61 %
N/A
(c)
6.60 %
(d)
(d)
(d)
(d)
(d)
(d)
Mortality table
Pri-2012 table with
MP- 2019
improvement scale
(adjusted)
RP-2000 table
projected to 2012 with
improvement scale AA,
with Scale BB-2D
improvements
(adjusted)
RP-2000 table
projected to 2012 with
improvement scale AA,
with Scale BB-2D
improvements
(adjusted)
Pri-2012 table with MP-
2019 improvement
scale (adjusted)
Health care cost
trend on covered
charges
N/A
N/A
N/A
Initial and ultimate rate
of 5.00%
RP-2000 table
projected to 2012 with
improvement scale AA,
with Scale BB-2D
improvements
(adjusted)
5.00%
with
ultimate
trend of
5.00% in
2017
RP-2000 table
projected to 2012 with
improvement scale AA,
with Scale BB-2D
improvements
(adjusted)
5.00%
with
ultimate
trend of
5.00% in
2017
__________
(a) The discount rates above represent the blended rates used to establish the majority of Exelon’s pension and OPEB costs. Certain benefit plans used individual rates, which
range from 3.02%-3.44% and 3.27%-3.40% for pension and OPEB plans, respectively, for the year ended December 31, 2020; 4.13%-4.36% and 4.27%-4.38% for pension
and OPEB plans; respectively, for the year ended December 31, 2019; and 3.49%-3.65% and 3.57%-3.68% for pension and OPEB plans, respectively, for the year ended
December 31, 2018.
(b) The investment crediting rate above represents a weighted average rate.
(c) Not applicable to pension and OPEB plans that do not have plan assets.
(d) 3.25% through 2019 and 3.75% thereafter.
Contributions
Exelon allocates contributions related to its legacy Exelon pension and OPEB plans to its subsidiaries based on accounting cost. For legacy CEG, CENG,
FitzPatrick, and PHI plans, pension and OPEB contributions are allocated to the subsidiaries based on employee participation (both active and retired). The
following tables provide contributions to the pension and OPEB plans:
Exelon
Generation
ComEd
PECO
BGE
PHI
Pepco
DPL
ACE
Pension Benefits
2020
2019
2018
2020
$
542 $
236
143
18
56
30
2
—
2
356 $
160
337 $
128
72
27
34
10
2
1
—
38
28
40
62
6
—
6
OPEB
2019
2018
59 $
51 $
19
5
—
22
9
9
—
—
15
5
1
14
15
12
—
1
46
11
4
—
14
12
11
—
—
Management considers various factors when making pension funding decisions, including actuarially determined minimum contribution requirements under
ERISA, contributions required to avoid benefit restrictions and at-risk status as defined by the Pension Protection Act of 2006 (the Act), management of the
pension obligation, and regulatory implications. The Act requires the attainment of certain funding levels to avoid benefit restrictions (such as an inability to
pay lump sums or to accrue benefits prospectively), and at-risk status (which triggers higher minimum contribution requirements and participant notification).
The projected contributions below reflect a funding strategy to make levelized annual contributions with the objective of achieving 100% funded status on an
ABO basis over time. This level funding strategy helps minimize volatility of future period required pension contributions. Based on this funding strategy and
current market conditions, which are subject to change,
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Combined Notes to Consolidated Financial Statements
(Dollars in millions, except per share data unless otherwise noted)
Note 15 — Retirement Benefits
Exelon’s estimated annual qualified pension contributions will be approximately $500 million in 2021. Unlike the qualified pension plans, Exelon’s non-
qualified pension plans are not funded, given that they are not subject to statutory minimum contribution requirements.
While OPEB plans are also not subject to statutory minimum contribution requirements, Exelon does fund certain of its plans. For Exelon's funded OPEB
plans, contributions generally equal accounting costs, however, Exelon’s management has historically considered several factors in determining the level of
contributions to its OPEB plans, including liabilities management, levels of benefit claims paid, and regulatory implications (amounts deemed prudent to meet
regulatory expectations and best assure continued rate recovery). The amounts below include benefit payments related to unfunded plans.
The following table provides all Registrants' planned contributions to the qualified pension plans, planned benefit payments to non-qualified pension plans,
and planned contributions to OPEB plans in 2021:
Exelon
Generation
ComEd
PECO
BGE
PHI
Pepco
DPL
ACE
Qualified Pension Plans
Non-Qualified Pension Plans
OPEB
$
505 $
51 $
196
170
14
57
29
1
—
3
27
2
1
1
9
2
1
—
Estimated Future Benefit Payments
Estimated future benefit payments to participants in all of the pension plans and postretirement benefit plans at December 31, 2020 were:
2021
2022
2023
2024
2025
2026 through 2030
Total estimated future benefit payments through 2030
Plan Assets
Pension
Benefits
OPEB
$
$
1,279 $
1,280
1,315
1,325
1,338
6,759
13,296 $
75
24
23
—
16
7
6
—
—
257
259
261
262
265
1,320
2,624
Investment Strategy. On a regular basis, Exelon evaluates its investment strategy to ensure that plan assets will be sufficient to pay plan benefits when due.
As part of this ongoing evaluation, Exelon may make changes to its targeted asset allocation and investment strategy.
Exelon has developed and implemented a liability hedging investment strategy for its qualified pension plans that has reduced the volatility of its pension
assets relative to its pension liabilities. Exelon is likely to continue to gradually increase the liability hedging portfolio as the funded status of its plans
improves. The overall objective is to achieve attractive risk-adjusted returns that will balance the liquidity requirements of the plans’ liabilities while striving to
minimize the risk of significant losses. Trust assets for Exelon’s OPEB plans are managed in a diversified investment strategy that prioritizes maximizing
liquidity and returns while minimizing asset volatility.
Actual asset returns have an impact on the costs reported for the Exelon-sponsored pension and OPEB plans. The actual asset returns across Exelon’s
pension and OPEB plans for the year ended December 31, 2020 were 14.45% and 9.14%, respectively, compared to an expected long-term return
assumption of 7.00% and 6.69%,
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Combined Notes to Consolidated Financial Statements
(Dollars in millions, except per share data unless otherwise noted)
Note 15 — Retirement Benefits
respectively. Exelon used an EROA of 7.00% and 6.46% to estimate its 2021 pension and OPEB costs, respectively.
Exelon’s pension and OPEB plan target asset allocations at December 31, 2020 and 2019 were as follows:
Asset Category
Equity securities
Fixed income securities
Alternative investments
Total
(a)
December 31, 2020
December 31, 2019
Pension Benefits
OPEB
Pension Benefits
OPEB
34 %
43 %
23 %
100 %
45 %
39 %
16 %
100 %
33 %
44 %
23 %
100 %
46 %
32 %
22 %
100 %
__________
(a) Alternative investments include private equity, hedge funds, real estate, and private credit.
Concentrations of Credit Risk. Exelon evaluated its pension and OPEB plans’ asset portfolios for the existence of significant concentrations of credit risk as
of December 31, 2020. Types of concentrations that were evaluated include, but are not limited to, investment concentrations in a single entity, type of
industry, foreign country, and individual fund. As of December 31, 2020, there were no significant concentrations (defined as greater than 10% of plan
assets) of risk in Exelon’s pension and OPEB plan assets.
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Combined Notes to Consolidated Financial Statements
(Dollars in millions, except per share data unless otherwise noted)
Note 15 — Retirement Benefits
Fair Value Measurements
The following tables present pension and OPEB plan assets measured and recorded at fair value in Exelon's Consolidated Balance Sheets on a recurring
basis and their level within the fair value hierarchy at December 31, 2020 and 2019:
December 31, 2020
December 31, 2019
Level 1
Level 2
Level 3
Not subject to
leveling
Total
Level 1
Level 2
Level 3
Not subject to
leveling
Total
Pension plan assets
(a)
Cash equivalents
$
408
$
121
$
Equities
(b)
Fixed income:
U.S. Treasury and
agencies
State and municipal
debt
Corporate debt
(c)
Other
(b)
4,255
—
1,137
367
—
—
—
Fixed income subtotal
1,137
Private equity
Hedge funds
Real estate
Private credit
—
—
—
—
Pension plan assets subtotal
5,800
5,685
85
4,873
239
5,564
—
—
—
—
OPEB plan assets
(a)
Cash equivalents
Equities
Fixed income:
U.S. Treasury and
agencies
State and municipal
debt
Corporate debt
(c)
Other
Fixed income subtotal
Hedge funds
Real estate
Private credit
OPEB plan assets subtotal
Total pension and OPEB plan
assets
(d)
50
618
16
—
—
285
301
—
—
—
969
52
2
66
89
89
3
247
—
—
—
301
$
—
2
—
$
529
$
258
$
107
$
2,552
6,809
3,616
1
$
—
5
—
$
2,589
365
6,211
—
—
573
21
594
—
—
—
234
830
—
—
—
—
—
—
—
—
—
—
—
—
—
—
537
537
1,632
1,314
1,080
1,046
8,161
—
569
—
—
—
179
179
308
111
117
1,504
1,294
280
85
5,446
797
7,832
1,632
1,314
1,080
1,280
—
—
—
1,294
—
—
—
—
56
4,390
305
5,031
—
—
—
—
20,476
5,168
5,139
102
1,189
82
89
89
467
727
308
111
117
39
473
17
—
—
258
275
—
—
—
787
49
5
64
107
71
5
247
—
—
—
301
1,284
2,554
—
—
245
—
245
—
—
—
237
487
—
—
—
—
—
—
—
—
—
—
—
—
—
—
851
851
1,391
1,126
1,030
929
7,916
—
719
—
—
—
201
201
293
109
131
1,574
56
4,635
1,156
7,421
1,391
1,126
1,030
1,166
18,710
88
1,197
81
107
71
464
723
293
109
131
1,453
2,541
$
6,769
$
5,986
$
830
$
9,445
$
23,030
$
5,955
$
5,440
$
487
$
9,369
$
21,251
__________
(a) See Note 18—Fair Value of Financial Assets and Liabilities for a description of levels within the fair value hierarchy.
(b)
Includes derivative instruments of $2 million for the years ended December 31, 2020 and 2019, which have total notional amounts of $6,879 million and $6,668 million at
December 31, 2020 and 2019, respectively. The notional principal
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Combined Notes to Consolidated Financial Statements
(Dollars in millions, except per share data unless otherwise noted)
Note 15 — Retirement Benefits
(c)
amounts for these instruments provide one measure of the transaction volume outstanding as of the fiscal years ended and do not represent the amount of the company’s
exposure to credit or market loss.
Includes investments in equities sold short held in investment vehicles primarily to hedge the equity option component of its convertible debt. Pension equities sold short
totaled $(96) million and $(75) million as of December 31, 2020 and 2019, respectively. OPEB equities sold short totaled $(42) million and $(35) million as of December 31,
2020 and 2019, respectively.
(d) Excludes net liabilities of $132 million and $120 million at December 31, 2020 and 2019, respectively, which include certain derivative assets that have notional amounts of
$239 million and $632 million at December 31, 2020 and 2019, respectively. These items are required to reconcile to the fair value of net plan assets and consist primarily
of receivables or payables related to pending securities sales and purchases and interest and dividends receivable.
The following table presents the reconciliation of Level 3 assets and liabilities for Exelon measured at fair value for pension and OPEB plans for the years
ended December 31, 2020 and 2019:
Pension Assets
Balance as of January 1, 2020
Actual return on plan assets:
Relating to assets still held at the
reporting date
Purchases, sales and settlements:
Purchases
Settlements
Transfers into Level 3
(a)
(b)
Balance as of December 31, 2020
Pension Assets
Balance as of January 1, 2019
Actual return on plan assets:
Relating to assets still held at the
reporting date
Relating to assets sold during the
period
Purchases, sales and settlements:
Purchases
Sales
Settlements
(a)
Transfers out of Level 3
Balance as of December 31, 2019
Fixed Income
Equities
Private
Credit
Total
245 $
5 $
237 $
19
34
(3)
299
(3)
—
—
—
15
24
(42)
—
594 $
2 $
234 $
Fixed Income
Equities
Private
Credit
Total
487
31
58
(45)
299
830
216 $
2 $
268 $
486
$
$
$
28
(7)
26
(4)
(2)
(12)
3
—
—
—
—
—
28
—
41
—
(100)
—
$
245 $
5 $
237 $
59
(7)
67
(4)
(102)
(12)
487
__________
(a) Represents cash settlements only.
(b)
In 2020, a contract was terminated for a certain fixed income commingled fund resulting in the ownership of certain fixed income securities which led to a transfer into Level
3 from not subject to leveling of $299 million.
Valuation Techniques Used to Determine Fair Value
The techniques used to fair value the pension and OPEB assets invested in cash equivalents, equities, fixed income, derivatives, private equity, real estate,
and private credit investments are the same as the valuation techniques for these types of investments in NDTFs. See Cash Equivalents and NDT Fund
Investments in Note 18 - Fair Value of Financial Assets and Liabilities for further information.
Pension and OPEB assets also include investments in hedge funds. Hedge fund investments include those that employ a broad range of strategies to
enhance returns and provide additional diversification. The fair value of
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Combined Notes to Consolidated Financial Statements
(Dollars in millions, except per share data unless otherwise noted)
Note 15 — Retirement Benefits
hedge funds is determined using NAV or its equivalent as a practical expedient, and therefore, hedge funds are not classified within the fair value hierarchy.
Exelon has the ability to redeem these investments at NAV or its equivalent subject to certain restrictions which may include a lock-up period or a gate.
Defined Contribution Savings Plan (All Registrants)
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 matching contributions to the savings plan for
the years ended December 31, 2020, 2019, and 2018:
For the Years Ended December 31,
Exelon
Generation
ComEd
PECO
BGE
PHI
Pepco
DPL
ACE
2020
2019
2018
$
158 $
63 $
36 $
12 $
161
179
73
86
35
37
11
9
13
12
12
14 $
4 $
3 $
13
13
3
3
3
2
3
2
2
16. 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 settles 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 referenced 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, which 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. 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.
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Combined Notes to Consolidated Financial Statements
(Dollars in millions, except per share data unless otherwise noted)
Note 16 — Derivative Financial Instruments
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 mechanisms. The following table
provides a summary of the Utility Registrants’ primary derivative hedging instruments, listed by commodity and accounting treatment.
Registrant
Commodity
Accounting Treatment
Hedging Instrument
Electricity
NPNS
Fixed price contracts based on all requirements in the IPA procurement plans.
ComEd
PECO
(b)
BGE
Pepco
DPL
ACE
Electricity
Changes in fair value of economic hedge recorded
to an offsetting regulatory asset or liability
(a)
Gas
NPNS
Electricity
NPNS
Gas
NPNS
Electricity
NPNS
Electricity
NPNS
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.
Fixed price contracts to cover about 10% of planned natural gas purchases in
support of projected firm sales.
Fixed price contracts for all SOS requirements through full requirements
contracts.
Fixed price contracts for between 10-20% of forecasted system supply
requirements for flowing (i.e., non-storage) gas for the November through March
period.
Fixed price contracts for all SOS requirements through full requirements
contracts.
Fixed price contracts for all SOS requirements through full requirements
contracts.
NPNS
Fixed and Index priced contracts through full requirements contracts.
Gas
Changes in fair value of economic hedge recorded
to an offsetting regulatory asset or liability
(c)
Exchange traded future contracts for up to 50% of estimated monthly purchase
requirements each month, including purchases for storage injections.
Electricity
NPNS
Fixed price contracts for all BGS requirements through full requirements
contracts.
_________
(a) See Note 3—Regulatory Matters 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 December 31, 2020 and 2019 and is not presented in the fair value tables below.
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Combined Notes to Consolidated Financial Statements
(Dollars in millions, except per share data unless otherwise noted)
Note 16 — Derivative Financial Instruments
The following table provides a summary of the derivative fair value balances recorded by Exelon, Generation, and ComEd as of December 31, 2020 and
2019:
December 31, 2020
Mark-to-market derivative assets (current
assets)
$
Mark-to-market derivative assets
(noncurrent assets)
Total mark-to-market derivative assets
Mark-to-market derivative liabilities
(current liabilities)
Mark-to-market derivative liabilities
(noncurrent liabilities)
Total mark-to-market derivative liabilities
Total mark-to-market derivative net assets
(liabilities)
$
December 31, 2019
Mark-to-market derivative assets (current
assets)
$
Mark-to-market derivative assets
(noncurrent assets)
Total mark-to-market derivative assets
Mark-to-market derivative liabilities
(current liabilities)
Mark-to-market derivative liabilities
(noncurrent liabilities)
Total mark-to-market derivative liabilities
Total mark-to-market derivative net assets
(liabilities)
$
Exelon
Total
Derivatives
Economic
Hedges
Proprietary
Trading
Generation
Collateral
(a)(b)
Netting
(a)
Subtotal
ComEd
Economic
Hedges
639 $
2,757 $
40 $
103 $
(2,261) $
639 $
554
1,193
(293)
(472)
(765)
1,501
4,258
(2,629)
(1,335)
(3,964)
4
44
(23)
(2)
(25)
64
167
131
118
249
(1,015)
(3,276)
2,261
1,015
3,276
554
1,193
(260)
(204)
(464)
—
—
—
(33)
(268)
(301)
428 $
294 $
19 $
416 $
— $
729 $
(301)
675 $
3,506 $
72 $
287 $
(3,190) $
675 $
508
1,183
(236)
(380)
(616)
1,238
4,744
(3,713)
(1,140)
(4,853)
25
97
(38)
(11)
(49)
122
409
357
163
520
(877)
(4,067)
3,190
877
4,067
508
1,183
(204)
(111)
(315)
—
—
—
(32)
(269)
(301)
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, $209 million and $511 million represents variation margin on the exchanges at December 31, 2020 and 2019, respectively.
Economic Hedges (Commodity Price Risk)
Generation. For the years ended December 31, 2020, 2019, and 2018, 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.
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Combined Notes to Consolidated Financial Statements
(Dollars in millions, except per share data unless otherwise noted)
Income Statement Location
Operating revenues
Purchased power and fuel
Total Exelon and Generation
Note 16 — Derivative Financial Instruments
2020
Gain (Loss)
2019
2018
$
$
112 $
168
280 $
— $
(204)
(204) $
(270)
(47)
(317)
In general, increases and decreases in forward market prices have a positive and negative impact, respectively, on Generation’s owned and contracted
generation positions that have not been hedged. Generation hedges commodity price risk on a ratable basis over three-year periods. As of December 31,
2020, the percentage of expected generation hedged for the Mid-Atlantic, Midwest, New York, and ERCOT reportable segments is 94%-97% for 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 years ended
December 31, 2020, 2019, and 2018, net pre-tax commodity mark-to-market gains and losses for Exelon and Generation were not material. The Utility
Registrants do not execute derivatives for proprietary trading purposes.
Interest Rate and Foreign Exchange Risk (Exelon and Generation)
Exelon and Generation utilize interest rate swaps, which are treated as economic hedges, to manage their interest rate exposure. On July 1, 2018, Exelon
de-designated its fair value hedges related to interest rate risk and Generation de-designated its cash flow hedges related to interest rate risk. The notional
amounts were $516 million and $1,269 million at December 31, 2020 and 2019, respectively, for Exelon and $516 million and $569 million at December 31,
2020 and 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, which are treated as economic hedges. The notional amounts were $149 million and $231 million at December 31, 2020 and 2019,
respectively.
The mark-to-market derivative assets and liabilities as of December 31, 2020 and 2019 and the mark-to-market gains and losses for the years ended
December 31, 2020, 2019, and 2018 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 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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(Dollars in millions, except per share data unless otherwise noted)
Note 16 — 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 December 31, 2020. The tables further delineate that exposure by credit rating of the
counterparties and provide guidance on the concentration of credit risk to individual counterparties. The figures in the tables below exclude credit risk
exposure from individual retail counterparties, nuclear fuel procurement contracts, and exposure through RTOs, ISOs, NYMEX, ICE, NASDAQ, NGX, and
Nodal commodity exchanges.
Rating as of December 31, 2020
Investment grade
Non-investment grade
No external ratings
Internally rated — investment grade
Internally rated — non-investment grade
Total
$
$
Total
Exposure
Before Credit
Collateral
Credit
Collateral
(a)
Net
Exposure
577 $
32
165
80
27 $
—
1
28
854 $
56 $
550
32
164
52
798
Net Credit Exposure by Type of Counterparty
Financial institutions
Investor-owned utilities, marketers, power producers
Energy cooperatives and municipalities
Other
Total
Number of
Counterparties
Greater than 10%
of Net Exposure
Net Exposure of
Counterparties
Greater than 10%
of Net Exposure
— $
—
— $
As of December 31, 2020
$
$
—
15
607
138
38
798
__________
(a) As of December 31, 2020, credit collateral held from counterparties where Generation had credit exposure included $31 million of cash and $25 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 December 31, 2020, 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 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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Combined Notes to Consolidated Financial Statements
(Dollars in millions, except per share data unless otherwise noted)
Note 16 — 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
Gross fair value of derivative contracts containing this feature
(a)
Offsetting fair value of in-the-money contracts under master netting arrangements
(b)
Net fair value of derivative contracts containing this feature
(c)
As of December 31,
2020
2019
$
$
(834) $
537
(297) $
(956)
649
(307)
__________
(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 December 31, 2020 and 2019, 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.
Cash collateral posted
Letters of credit posted
Cash collateral held
Letters of credit held
Additional collateral required in the event of a credit downgrade below investment grade
$
As of December 31,
2020
2019
511 $
226
110
40
1,432
982
264
103
112
1,509
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's, and DPL’s credit rating. As of
December 31, 2020, 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 December 31, 2020, they could have been required to post incremental collateral to their counterparties of $34 million, $54 million,
and $9 million, respectively.
17. 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
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(Dollars in millions, except per share data unless otherwise noted)
Note 17 — Debt and Credit Agreements
from the PHI intercompany money pool. PHI Corporate meets its short-term liquidity requirements primarily through the issuance of short-term notes and
borrowings from 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 supported by the revolving credit agreements and bilateral credit agreements at
December 31, 2020 and 2019:
Commercial Paper Issuer
Exelon
(d)
Generation
ComEd
PECO
BGE
(e)
PHI
Pepco
DPL
ACE
Maximum
Program Size at
December 31,
Outstanding
Commercial
Paper at
December 31,
Average Interest Rate on
Commercial Paper Borrowings at December 31,
2020
(a)(b)(c)
2019
(a)(b)(c)
2020
2019
2020
2019
$
9,000 $
9,000 $
1,031 $
5,300
1,000
600
600
900
300
300
300
5,300
1,000
600
600
900
300
300
300
340
323
—
—
368
35
146
187
870
320
130
—
76
208
82
56
70
0.25 %
0.27 %
0.23 %
— %
— %
0.24 %
0.22 %
0.24 %
0.25 %
2.25 %
1.84 %
2.38 %
2.39 %
2.46 %
N/A
2.56 %
2.02 %
2.43 %
__________
(a) Excludes $1,500 million and $1,400 million in bilateral credit facilities at December 31, 2020 and 2019, respectively, and $144 million and $159 million in credit facilities for
project finance at December 31, 2020 and 2019, respectively. These credit facilities do not back Generation's commercial paper program.
(b) At December 31, 2020, excludes $135 million of credit facility agreements arranged at minority and community banks at Generation, ComEd, PECO, BGE, Pepco, DPL,
and ACE with aggregate commitments of $38 million, $32 million, $33 million, $8 million, $8 million, $8 million, and $8 million, respectively. These facilities expire on
October 8, 2021. These facilities are solely utilized to issue letters of credit. At December 31, 2019, excludes $142 million of credit facility agreements arranged at minority
and community banks at Generation, ComEd, PECO, BGE, Pepco, DPL, and ACE with aggregate commitments of $44 million, $33 million, $33 million, $8 million, $8
million, $8 million, and $8 million, respectively.
(c) Pepco, DPL, and ACE's revolving credit facility has the ability to flex to $500 million, $500 million, and $350 million, respectively. The borrowing capacity may be increased
or decreased during the term of the facility, except that (i) the sum of the borrowing capacity must equal the total amount of the facility, and (ii) the aggregate amount of
credit used at any given time by each of Pepco, DPL, or ACE may not exceed $900 million or the maximum amount of short-term debt the company is permitted to have
outstanding by its regulatory authorities. The total number of the borrowing reallocations may not exceed eight per year during the term of the facility.
Includes revolving credit agreement at Exelon Corporate with a maximum program size of $600 million at both December 31, 2020 and 2019, respectively. Exelon
Corporate had no outstanding commercial paper as of December 31, 2020 and $136 million at 2019 with an average interest rate on commercial paper borrowings of
1.92%.
(d)
(e) Represents the consolidated amounts of Pepco, DPL, and ACE.
In order to maintain their respective commercial paper programs in the amounts indicated above, each Registrant must have credit facilities in place, at least
equal to the amount of its commercial paper program. A registrant does not issue commercial paper in an aggregate amount exceeding the then available
capacity under its credit facility.
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(Dollars in millions, except per share data unless otherwise noted)
Note 17 — Debt and Credit Agreements
At December 31, 2020, the Registrants had the following aggregate bank commitments, credit facility borrowings, and available capacity under their
respective credit facilities:
Available Capacity at December 31, 2020
Borrower
(a)
Facility Type
Aggregate Bank
(b)
Commitment
Facility Draws
Outstanding
Letters of Credit
Actual
(c)
Exelon
Generation
Generation
Generation
ComEd
PECO
BGE
PHI
Pepco
DPL
ACE
Syndicated Revolver /
Bilaterals / Project Finance
$
10,644 $
— $
1,230 $
9,414 $
Syndicated Revolver
Bilaterals
Project Finance
Syndicated Revolver
Syndicated Revolver
Syndicated Revolver
Syndicated Revolver
Syndicated Revolver
Syndicated Revolver
Syndicated Revolver
5,300
1,500
144
1,000
600
600
900
300
300
300
—
—
—
—
—
—
—
—
—
—
262
840
119
2
—
—
1
1
—
—
5,038
660
25
998
600
600
899
299
300
300
To Support
Additional
Commercial
Paper
(c)
7,698
4,698
—
—
675
600
600
531
264
154
113
__________
(a) On May 26, 2018, each of the Registrants' respective syndicated revolving credit facilities had their maturity dates extended to May 26, 2023.
(b) Excludes $135 million of credit facility agreements arranged at minority and community banks at Generation, ComEd, PECO, BGE, Pepco, DPL, and ACE with aggregate
commitments of $38 million, $32 million, $33 million, $8 million, $8 million, $8 million, and $8 million, respectively. These facilities expire on October 8, 2021. These facilities
are solely utilized to issue letters of credit. As of December 31, 2020, letters of credit issued under these facilities totaled $5 million, $5 million, and $2 million for
Generation, ComEd, and BGE, respectively.
Includes $600 million aggregate bank commitment related to Exelon Corporate. Exelon Corporate had $6 million outstanding letters of credit at December 31, 2020. Exelon
Corporate had $594 million in available capacity to support additional commercial paper at December 31, 2020.
(c)
On March 19, 2020, Generation borrowed $1.5 billion on its revolving credit facility due to disruptions in the commercial paper markets 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.
Short-Term Loan Agreements
On March 23, 2017, Exelon Corporate entered into a 12-month term loan agreement for $500 million, which was renewed annually on March 22, 2018,
March 20, 2019, and March 19, 2020, respectively. The loan agreement will expire on March 18, 2021. Pursuant to the loan agreement, as of December 31,
2020, loans made thereunder bear interest at a variable rate equal to LIBOR plus 0.65% and all indebtedness thereunder is unsecured. The loans beared
interest at LIBOR plus 0.95% as of December 31, 2019 as part of the March 20, 2019 renewal. The loan agreement is reflected in Exelon's Consolidated
Balance Sheets within Short-term borrowings.
On March 19, 2020, Generation entered into a term loan agreement for $200 million. 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 is reflected in Generation's Consolidated Balance Sheet within Short-term borrowings.
On March 31, 2020, Generation entered into a term loan agreement for $300 million. The loan agreement has an expiration of March 30, 2021. Pursuant to
the loan agreement, loans made thereunder bear interest at a variable rate equal to LIBOR plus 0.75% and all indebtedness thereunder is unsecured. The
loan agreement is reflected in Generation's Consolidated Balance Sheet within Short-term borrowings.
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(Dollars in millions, except per share data unless otherwise noted)
Note 17 — Debt and Credit Agreements
On January 25, 2021, ComEd entered into two 90-day term loan agreements of $125 million each with variable interest rates of LIBOR plus 0.50% and
LIBOR plus 0.75%, respectively.
Revolving Credit Agreements
On April 24, 2020, Exelon Corporate entered into a credit agreement establishing a $550 million 364-day revolving credit facility at a variable interest rate of
LIBOR plus 1.75%. This facility will be used by Exelon as an additional source of short-term liquidity as needed.
Bilateral Credit Agreements
The following table reflects the bilateral credit agreements at December 31, 2020:
Registrant
Date Initiated
Latest Amendment Date
Maturity Date
(a)
Amount
Generation
(b)
Generation
(c)
Generation
(c)
Generation
(c)
Generation
Generation
(c)
(c)
Generation
(c)
Generation
(c)
Generation
(c)
October 26, 2012
January 11, 2013
January 5, 2016
February 21, 2019
October 25, 2019
October 25, 2019
November 20, 2019
November 21, 2019
November 21, 2019
October 23, 2020
January 4, 2019
January 4, 2019
N/A
N/A
N/A
N/A
N/A
N/A
October 22, 2021
$
March 1, 2021
April 5, 2021
March 31, 2021
N/A
N/A
N/A
N/A
November 21, 2021
200
100
150
100
200
100
300
150
100
(c)
Generation
__________
(a) Credit facilities that do not contain a maturity date are specific to the agreements set within each contract. In some instances, credit facilities are automatically renewed
May 15, 2020
100
N/A
N/A
based on the contingency standards set within the specific agreement.
(b) Bilateral credit facility relates to CENG, which is incorporated within Generation, and supports the issuance of letters of credit and funding for working capital and does not
back Generation's commercial paper program. During the second and third quarters of 2020, CENG drew on its bilateral credit facility. As of December 31, 2020, there was
no outstanding balance at this facility.
(c) Bilateral credit agreements solely support the issuance of letters of credit and do not back Generation's commercial paper program.
Borrowings under Exelon’s, Generation’s, ComEd’s, PECO’s, BGE's, Pepco's, DPL's, and ACE's revolving credit agreements bear interest at a rate based
upon either the prime rate or a LIBOR-based rate, plus an adder based upon the particular Registrant’s credit rating. The adders for the prime based
borrowings and LIBOR-based borrowings are presented in the following table:
Prime based borrowings
LIBOR-based borrowings
__________
(a)
Exelon
(a)
Generation
ComEd
PECO
BGE
Pepco
DPL
ACE
0 - 27.5
90.0 - 127.5
27.5
127.5
—
100.0
—
90.0
—
90.0
7.5
107.5
—
100.0
7.5
107.5
Includes interest rate adders at Exelon Corporate of 27.5 and 127.5 for prime and LIBOR-based borrowings, respectively.
If any registrant loses its investment grade rating, the maximum adders for prime rate borrowings and LIBOR-based rate borrowings would be 65 basis
points and 165 basis points, respectively. The credit agreements also require the borrower to pay a facility fee based upon the aggregate commitments. The
fee varies depending upon the respective credit ratings of the borrower.
Variable Rate Demand Bonds
DPL has outstanding obligations in respect of Variable Rate Demand Bonds (VRDB). VRDBs are subject to repayment on the demand of the holders and, for
this reason, are accounted for as short-term debt in accordance with GAAP. However, these bonds may be converted to a fixed-rate, fixed-term option to
establish a maturity which corresponds to the date of final maturity of the bonds. On this basis, PHI views VRDBs as a source of long-term financing. As of
both December 31, 2020 and December 31, 2019, $79 million in variable
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Combined Notes to Consolidated Financial Statements
(Dollars in millions, except per share data unless otherwise noted)
Note 17 — Debt and Credit Agreements
rate demand bonds issued by DPL were outstanding and are included in the Long-term debt due within one year in Exelon's, PHI's, and DPL's Consolidated
Balance Sheet.
Long-Term Debt
The following tables present the outstanding long-term debt at the Registrants as of December 31, 2020 and 2019:
Exelon
Long-term debt
First mortgage bonds
Senior unsecured notes
(a)
Unsecured notes
Pollution control notes
Nuclear fuel procurement contracts
Notes payable and other
Junior subordinated notes
Long-term software licensing agreement
Unsecured tax-exempt bonds
Medium-terms notes (unsecured)
Transition bonds
Loan agreement
Nonrecourse debt:
Fixed rates
Variable rates
Total long-term debt
Unamortized debt discount and premium, net
Unamortized debt issuance costs
Fair value adjustment
Long-term debt due within one year
Long-term debt
Long-term debt to financing trusts
(b)
Subordinated debentures to ComEd Financing III
Subordinated debentures to PECO Trust III
Subordinated debentures to PECO Trust IV
Total long-term debt to financing trusts
Rates
0.19 % -
2.45 % -
2.40 % -
2.50 % -
2.10 % -
0.17 % -
2.29 % -
2.99 % -
7.90 %
7.60 %
6.35 %
2.70 %
3.15 %
7.99 %
3.50 %
3.95 %
1.70 %
7.72 %
5.55 %
2.00 %
6.00 %
3.18 %
Maturity
Date
December 31,
2020
2019
2021 - 2050 $
18,915 $
2021 - 2050
2021 - 2050
2020
2020
2021 - 2053
2022
2024
2022 - 2024
2027
2021
2023
2031 - 2037
2021 - 2027
10,585
3,700
—
—
170
1,150
30
143
10
21
50
977
765
36,516
(77)
(248)
721
(1,819)
17,486
10,685
3,300
412
3
154
1,150
55
222
10
40
50
1,182
811
35,560
(72)
(214)
765
(4,710)
31,329
206
81
103
390
5.25 % -
6.35 %
7.38 %
5.75 %
$
35,093 $
2033 $
206 $
2028
2033
81
103
$
390 $
__________
(a) Substantially all of ComEd’s assets other than expressly excepted property and substantially all of PECO’s, Pepco's, DPL's, and ACE's assets are subject to the liens of
their respective mortgage indentures.
(b) Amounts owed to these financing trusts are recorded as Long-term debt to financing trusts within Exelon’s Consolidated Balance Sheets.
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Table of Contents
Generation
Long-term debt
Senior unsecured notes
Pollution control notes
Nuclear fuel procurement contracts
Notes payable and other
Nonrecourse debt:
Fixed rates
Variable rates
Total long-term debt
Unamortized debt discount and premium, net
Unamortized debt issuance costs
Fair value adjustment
Long-term debt due within one year
Long-term debt
ComEd
Long-term debt
First mortgage bonds
Other
(a)
Total long-term debt
Unamortized debt discount and premium, net
Unamortized debt issuance costs
Long-term debt due within one year
Long-term debt
Long-term debt to financing trust
(b)
Combined Notes to Consolidated Financial Statements
(Dollars in millions, except per share data unless otherwise noted)
Rates
3.25 % -
2.50 % -
2.10 % -
2.29 % -
2.99 % -
7.60 %
2.70 %
3.15 %
4.85 %
6.00 %
3.18 %
Rates
2.20 % -
6.45 %
7.49 %
Note 17 — Debt and Credit Agreements
Maturity
Date
December 31,
2020
2019
2022 - 2042 $
4,219 $
5,420
2020
2020
2021 - 2028
2031 - 2037
2021 - 2027
—
—
111
977
765
6,072
(5)
(46)
66
(197)
$
5,890 $
412
3
115
1,182
811
7,943
(5)
(42)
78
(3,182)
4,792
Maturity
Date
December 31,
2020
2019
2021 - 2050 $
9,079 $
8,578
2053
8
9,087
(28)
(76)
(350)
$
8,633 $
8
8,586
(27)
(68)
(500)
7,991
206
206
(1)
205
Subordinated debentures to ComEd Financing III
6.35 %
2033 $
206 $
Total long-term debt to financing trusts
Unamortized debt issuance costs
Long-term debt to financing trusts
206
(1)
$
205 $
__________
(a) Substantially all of ComEd’s assets, other than expressly excepted property, are subject to the lien of its mortgage indenture.
(b) Amount owed to this financing trust is recorded as Long-term debt to financing trust within ComEd’s Consolidated Balance Sheets.
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Combined Notes to Consolidated Financial Statements
(Dollars in millions, except per share data unless otherwise noted)
Note 17 — Debt and Credit Agreements
PECO
Long-term debt
First mortgage bonds
Loan agreement
(a)
Total long-term debt
Unamortized debt discount and premium, net
Unamortized debt issuance costs
Long-term debt due within one year
Long-term debt
Long-term debt to financing trusts
(b)
Subordinated debentures to PECO Trust III
Subordinated debentures to PECO Trust IV
Long-term debt to financing trusts
Rates
1.70 % -
5.95 %
2.00 %
5.25 % -
7.38 %
5.75 %
Maturity
Date
December 31,
2020
2019
2021 - 2050 $
3,750 $
2023
50
3,800
(20)
(27)
(300)
3,400
50
3,450
(21)
(24)
—
$
3,453 $
3,405
2028 $
2033
81 $
103
$
184 $
81
103
184
__________
(a) Substantially all of PECO’s assets are subject to the lien of its mortgage indenture.
(b) Amounts owed to this financing trust are recorded as Long-term debt to financing trusts within PECO’s Consolidated Balance Sheets.
BGE
Long-term debt
Unsecured notes
Total long-term debt
Unamortized debt discount and premium, net
Unamortized debt issuance costs
Long-term debt due within one year
Long-term debt
Rates
Maturity
Date
December 31,
2020
2019
2.40 % -
6.35 %
2021 - 2050 $
3,700 $
3,700
(12)
(24)
(300)
3,300
3,300
(9)
(21)
—
$
3,364 $
3,270
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Table of Contents
PHI
Long-term debt
First mortgage bonds
Senior unsecured notes
(a)
Unsecured tax-exempt bonds
Medium-terms notes (unsecured)
Transition bonds
Finance leases
Other
Total long-term debt
Unamortized debt discount and premium, net
Unamortized debt issuance costs
Fair value adjustment
Long-term debt due within one year
Long-term debt
Combined Notes to Consolidated Financial Statements
(Dollars in millions, except per share data unless otherwise noted)
Rates
0.19 % -
0.17 % -
7.28 % -
7.90 %
7.45 %
1.70 %
7.72 %
5.55 %
3.54 %
7.99 %
Note 17 — Debt and Credit Agreements
Maturity
Date
December 31,
2020
2019
2021 - 2050 $
2032
2022 - 2024
2027
2021
2022 - 2028
2021 - 2022
6,086 $
185
143
10
21
50
1
6,496
4
(28)
534
(347)
$
6,659 $
5,508
185
222
10
40
28
2
5,995
4
(19)
583
(103)
6,460
_________
(a) Substantially all of Pepco's, DPL's, and ACE's assets are subject to the liens of their respective mortgage indentures.
Pepco
Long-term debt
First mortgage bonds
(a)
Unsecured tax-exempt bonds
Finance leases
Other
Total long-term debt
Unamortized debt discount and premium, net
Unamortized debt issuance costs
Long-term debt due within one year
Long-term debt
Rates
2.53 % -
7.28 % -
Maturity
Date
December 31,
2020
2019
7.90 %
1.70 %
3.54 %
7.99 %
2022 - 2050 $
2022
2025 - 2028
2021 - 2022
3,075 $
110
17
1
2,775
110
10
2
3,203
2,897
2
(40)
(3)
2
(35)
(2)
$
3,162 $
2,862
__________
(a) Substantially all of Pepco's assets are subject to the lien of its mortgage indenture.
320
Combined Notes to Consolidated Financial Statements
(Dollars in millions, except per share data unless otherwise noted)
Table of Contents
DPL
Rates
0.19 % -
0.17 % -
4.27 %
0.20 %
7.72 %
3.54 %
Long-term debt
First mortgage bonds
Unsecured tax-exempt bonds
(a)
Medium-terms notes (unsecured)
Finance leases
Total long-term debt
Unamortized debt discount and premium, net
Unamortized debt issuance costs
Long-term debt due within one year
Long-term debt
__________
(a) Substantially all of DPL's assets are subject to the lien of its mortgage indenture.
Note 17 — Debt and Credit Agreements
Maturity
Date
December 31,
2020
2019
2023 - 2049 $
1,624 $
1,446
2024
2027
2025 - 2028
33
10
20
112
10
10
1,687
1,578
1
(11)
(82)
1
(12)
(80)
$
1,595 $
1,487
ACE
Long-term debt
First mortgage bonds
(a)
Transition bonds
Finance leases
Total long-term debt
Unamortized debt discount and premium, net
Unamortized debt issuance costs
Long-term debt due within one year
Long-term debt
__________
(a) Substantially all of ACE's assets are subject to the lien of its mortgage indenture.
Rates
2.25 % -
6.80 %
5.55 %
3.54 %
Maturity
Date
December 31,
2020
2019
2021 - 2050 $
1,387 $
1,287
2021
2022 - 2028
21
13
1,421
(1)
(7)
(261)
40
8
1,335
(1)
(7)
(20)
$
1,152 $
1,307
Long-term debt maturities at the Registrants in the periods 2021 through 2025 and thereafter are as follows:
Year
2021
2022
2023
2024
2025
Thereafter
Total
$
$
1,819
3,092
859
814
2,215
(a)
28,107
36,906
Exelon
Generation
ComEd
PECO
BGE
PHI
Pepco
DPL
ACE
$
197 $
350
$
$
300 $
347 $
3 $
82 $
261
1,025
1
1
900
3,948
—
—
250
—
300
350
50
—
350
250
300
—
—
317
508
558
158
312
3
403
3
3
503
3
3
2
2
152
152
852
$
6,072 $
9,292
$
3,984
$
3,700 $
6,496 $
3,203 $
1,687 $
1,421
8,692
(b)
2,934
(c)
2,850
4,608
2,479
1,093
__________
(a)
(b)
(c)
Includes $390 million due to ComEd and PECO financing trusts.
Includes $206 million due to ComEd financing trust.
Includes $184 million due to PECO financing trusts.
Debt Covenants
As of December 31, 2020, the Registrants are in compliance with debt covenants.
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Nonrecourse Debt
Combined Notes to Consolidated Financial Statements
(Dollars in millions, except per share data unless otherwise noted)
Note 17 — Debt and Credit Agreements
Exelon and Generation have issued nonrecourse debt financing, in which approximately $2.2 billion of generating assets have been pledged as collateral at
December 31, 2020. 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 nonrecourse debt
financing covenants, there could be a requirement to accelerate repayment of the associated debt or other borrowings earlier than the stated maturity dates.
In these instances, if such repayment was not satisfied, 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.
Antelope Valley Solar Ranch One. In December 2011, the DOE Loan Programs Office issued a guarantee for up to $646 million for a nonrecourse loan
from the Federal Financing Bank to support the financing of the construction of the Antelope Valley facility. The project became fully operational in 2014. The
loan will mature on January 5, 2037. Interest rates on the loan were fixed upon each advance at a spread of 37.5 basis points above U.S. Treasuries of
comparable maturity. The advances were completed as of December 31, 2015 and the outstanding loan balance will bear interest at an average blended
interest rate of 2.82%. As of December 31, 2020 and December 31, 2019, approximately $460 million and $485 million were outstanding, respectively. In
addition, Generation has issued letters of credit to support its equity investment in the project. As of December 31, 2020, Generation had $37 million in
letters of credit outstanding related to the project. In December 2017, Generation’s interests in Antelope Valley were contributed to and are pledged as
collateral for the EGR IV financing structures 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,
distributions from Antelope Valley to EGR IV were permitted and the debt was classified as noncurrent as of June 30, 2020. The debt continues to be
presented as noncurrent as of December 31, 2020.
See Note 12 — Asset Impairments for additional information.
Continental Wind, LLC. In September 2013, Continental Wind, an indirect subsidiary of Exelon and Generation, completed the issuance and sale of $613
million senior secured notes. Continental Wind owns and operates a portfolio of wind farms in Idaho, Kansas, Michigan, Oregon, New Mexico, and Texas
with a total net capacity of 667 MW. The net proceeds were distributed to Generation for its general business purposes. The notes are scheduled to mature
on February 28, 2033. The notes bear interest at a fixed rate of 6.00% with interest payable semi-annually. As of December 31, 2020 and December 31,
2019, approximately $415 million and $447 million were outstanding, respectively.
In addition, Continental Wind has a $122 million letter of credit facility and $4 million working capital revolver facility. Continental Wind has issued letters of
credit to satisfy certain of its credit support and security obligations. As of December 31, 2020, the Continental Wind letter of credit facility had $114 million in
letters of credit outstanding related to the project.
In 2017, Generation’s interests in Continental Wind were contributed to EGRP. Refer to Note 23 - Variable Interest Entities for additional information on
EGRP.
Renewable Power Generation. In March 2016, RPG, an indirect subsidiary of Exelon and Generation, issued $150 million aggregate principal amount of
a nonrecourse senior secured notes. The net proceeds were distributed to Generation for paydown of long term debt obligations at Sacramento PV Energy
and Constellation
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Combined Notes to Consolidated Financial Statements
(Dollars in millions, except per share data unless otherwise noted)
Note 17 — Debt and Credit Agreements
Solar Horizons and for general business purposes. The loan is scheduled to mature on March 31, 2035. The term loan bears interest at a fixed rate of 4.11%
payable semi-annually. As of December 31, 2020 and December 31, 2019, approximately $95 million and $106 million were outstanding, respectively.
In 2017, Generation’s interests in RPG were contributed to EGRP. Refer to Note 23 - Variable Interest Entities for additional information on EGRP.
SolGen, LLC. In September 2016, SolGen, an indirect subsidiary of Exelon and Generation, issued $150 million aggregate principal amount of a
nonrecourse senior secured notes. The net proceeds were distributed to Generation for general business purposes. The loan is scheduled to mature on
September 30, 2036. The term loan bears interest at a fixed rate of 3.93% payable semi-annually. As of December 31, 2020 and December 31, 2019,
approximately $125 million and $131 million were outstanding, respectively. As a result of the sale agreement with an affiliate of Brookfield Renewable in the
fourth quarter of 2020, the outstanding balance was reclassified to Liabilities held for sale in Exelon's and Generation's Consolidated Balance Sheets as of
December 31, 2020. In 2017, Generation’s interests in SolGen were contributed to and were pledged as collateral for the EGR IV financing structure. In
December 2020, as part of the EGR IV financing, SolGen was removed from the collateral terms structured within the agreement. See EGR IV discussed
below for additional information and Note 2 — Mergers, Acquisitions, and Dispositions for additional information on the sale agreement.
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 with a maturity date of November 28, 2024. In addition to the financing, EGR IV entered into interest rate swaps
with an initial notional amount of $636 million at an interest rate of 2.32% to manage a portion of the interest rate exposure in connection with the financing.
In December 2020, EGR IV entered into a financing agreement for a $750 million nonrecourse senior secured term loan credit facility, scheduled to mature
on December 15, 2027. The term loan bears interest at a variable rate equal to LIBOR plus 2.75%, subject to a 1% LIBOR floor with interest payable
quarterly. In addition to the financing, EGR IV entered into interest rate swaps with an initial notional amount of $516 million at an interest rate of 1.05% to
manage a portion of the interest rate exposure in connection with the financing.
The proceeds were used to repay the November 2017 nonrecourse senior secured term loan credit facility of $850 million, of which $709 million was
outstanding as of the retirement date in December of 2020, and to settle the November 2017 interest rate swap. Generation’s interests in EGRP and
Antelope Valley remained contributed to and are pledged as collateral for this financing. As of December 31, 2020, $750 million was outstanding. See Note
23 — Variable Interest Entities for additional information on EGRP and Note 16 — Derivative Financial Instruments for additional information on interest rate
swaps.
18. 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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Combined Notes to Consolidated Financial Statements
(Dollars in millions, except per share data unless otherwise noted)
Note 18 — 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 December 31, 2020 and 2019. 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.
December 31, 2020
December 31, 2019
Carrying Amount
Level 2
Fair Value
Level 3
Total
Carrying Amount
Level 2
Fair Value
Level 3
Total
Long-Term Debt, including amounts due within one year
40,688
Exelon
36,912
$
$
(a)
$
3,064
$
43,752
$
36,039
$
37,453
$
2,580
$
40,033
Generation
ComEd
PECO
BGE
PHI
Pepco
DPL
6,087
8,983
3,753
3,664
7,006
3,165
1,677
ACE
Long-Term Debt to Financing Trusts
Exelon
1,413
(a)
390
$
$
ComEd
PECO
SNF Obligation
Exelon
Generation
205
184
$
1,208
$
1,208
5,648
11,117
4,553
4,366
6,099
3,336
1,484
1,018
$
$
—
—
—
909
909
1,208
—
50
—
1,806
748
455
602
467
246
221
—
—
$
$
6,856
11,117
4,603
4,366
7,905
4,084
1,939
1,620
7,974
8,491
3,405
3,270
6,563
2,864
1,567
1,327
7,304
9,848
3,868
3,649
5,902
3,198
1,408
1,026
$
$
467
246
221
909
909
$
390
205
184
$
—
—
—
1,199
$
1,199
1,055
$
1,055
1,366
—
50
—
1,164
388
311
464
428
227
201
—
—
$
$
8,670
9,848
3,918
3,649
7,066
3,586
1,719
1,490
428
227
201
1,055
1,055
__________
(a) Includes unamortized debt issuance costs which are not fair valued. Refer to Note 17 — Debt and Credit Agreements for each Registrants’ unamortized debt issuance costs.
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Combined Notes to Consolidated Financial Statements
(Dollars in millions, except per share data unless otherwise noted)
Note 18 — Fair Value of Financial Assets and Liabilities
Exelon uses the following methods and assumptions to estimate fair value of financial liabilities recorded at carrying cost:
Type
Level
Registrants
Valuation
Long-Term Debt, including amounts due within one year
Taxable Debt Securities
Variable Rate Financing Debt
Taxable Private Placement Debt
Securities
Government Backed Fixed Rate
Project Financing Debt
Non-Government Backed Fixed
Rate Nonrecourse Debt
Long-Term Debt to Financing Trusts
Long Term Debt to Financing
Trusts
SNF Obligation
2
2
3
3
3
3
All
The fair value is determined by a valuation model that is based on a conventional discounted cash
flow methodology and utilizes assumptions of current market pricing curves. Exelon obtains credit
spreads based on trades of existing Exelon debt securities as well as other issuers in the utility
sector with similar credit ratings. The yields are then converted into discount rates of various
tenors that are used for discounting the respective cash flows of the same tenor for each bond or
note.
Exelon, Generation, DPL Debt rates are reset on a regular basis and the carrying value approximates fair value.
Exelon, Pepco, DPL, ACE
Exelon, Generation
Exelon, Generation, Pepco
Rates are obtained similar to the process for taxable debt securities. Due to low trading volume
and qualitative factors such as market conditions, low volume of investors, and investor demand,
these debt securities are Level 3.
The fair value is similar to the process for taxable debt securities. Due to the lack of market
trading data on similar debt, the discount rates are derived based on the original loan interest rate
spread to the applicable U.S. Treasury rate as well as a current market curve derived from
government-backed securities.
Fair value is based on market and quoted prices for its own and other nonrecourse debt with
similar risk profiles. Given the low trading volume in the nonrecourse debt market, the price
quotes used to determine fair value will reflect certain qualitative factors, such as market
conditions, investor demand, new developments that might significantly impact the project cash
flows or off-taker credit, and other circumstances related to the project.
Exelon, ComEd, PECO
Fair value is based on publicly traded securities issued by the financing trusts. Due to low trading
volume of these securities and qualitative factors, such as market conditions, investor demand,
and circumstances related to each issue, this debt is classified as Level 3.
SNF Obligation
2
Exelon, Generation
The carrying amount is derived from a contract with the DOE to provide for disposal of SNF from
Generation’s nuclear generating stations. When determining the fair value of the obligation, the
future carrying amount of the SNF obligation is calculated by compounding the current book value
of the SNF obligation at the 13-week U.S. Treasury rate. The compounded obligation amount is
discounted back to present value using Generation’s discount rate, which is calculated using the
same methodology as described above for the taxable debt securities, and an estimated maturity
date of 2035 and 2030 for the years ended December 31, 2020 and 2019, respectively.
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 December 31, 2020 and 2019:
325
Table of Contents
Combined Notes to Consolidated Financial Statements
(Dollars in millions, except per share data unless otherwise noted)
Note 18 — Fair Value of Financial Assets and Liabilities
Exelon and Generation
Level 1
Level 2
Level 3
Not subject to
leveling
Total
Level 1
Level 2
Level 3
Not subject to
leveling
Total
Exelon
Generation
$
686
$
—
$
—
$
—
$
686
$
124
$
—
$
—
$
—
$
124
(a)
As of December 31, 2020
Assets
Cash equivalents
NDT fund investments
Cash equivalents
Equities
Fixed income
(b)
(c)
Corporate debt
U.S. Treasury and
agencies
Foreign governments
State and municipal debt
Other
Fixed income subtotal
Private credit
Private equity
Real estate
NDT fund investments
subtotal
(d)(e)
Rabbi trust investments
Cash equivalents
Mutual funds
Fixed income
Life insurance contracts
Rabbi trust investments
subtotal
(f)
Investments in equities
Commodity derivative assets
Economic hedges
Proprietary trading
Effect of netting and
allocation of collateral
(g)(h)
Commodity derivative
assets subtotal
DPP consideration
Total assets
Liabilities
Commodity derivative liabilities
Economic hedges
Proprietary trading
Effect of netting and
allocation of collateral
(g)(h)
Commodity derivative
liabilities subtotal
Deferred compensation obligation
Total liabilities
Total net assets
—
—
285
—
—
—
—
285
212
—
—
497
—
—
—
34
34
—
1,599
27
(905)
721
—
1,252
210
3,886
95
2,077
—
1,485
1,871
—
—
—
1,871
—
—
—
126
56
101
41
1,809
—
—
—
5,967
3,981
60
91
—
—
151
195
745
—
—
—
11
87
98
—
1,914
17
(607)
(1,597)
334
639
5,052
138
—
7,137
(682)
—
540
(142)
—
(142)
(1,928)
(21)
(1,655)
(4)
1,918
1,067
(31)
(145)
(176)
(592)
—
(592)
—
—
285
—
—
—
—
285
212
—
—
497
—
—
—
—
—
—
1,599
27
(905)
721
—
1,218
—
1,562
—
—
—
—
961
961
629
504
679
305
7,525
1,770
1,997
56
101
1,002
4,926
841
504
679
210
3,886
95
2,077
—
1,485
1,871
—
—
—
1,871
—
—
—
126
56
101
41
1,809
—
—
—
4,335
14,780
5,967
3,981
—
—
—
—
—
—
—
—
—
—
—
4,335
—
—
—
—
—
—
60
91
11
121
283
195
4,258
44
(3,109)
1,193
639
17,776
(4,265)
(25)
3,525
(765)
(145)
(910)
4
29
—
—
33
195
745
—
—
—
—
28
28
—
1,914
17
(607)
(1,597)
334
639
4,982
138
—
6,457
(682)
—
540
(142)
—
(142)
(1,928)
(21)
(1,354)
(4)
1,918
1,067
(31)
(42)
(73)
(291)
—
(291)
—
1,562
—
—
—
—
961
961
629
504
679
305
7,525
1,770
1,997
56
101
1,002
4,926
841
504
679
4,335
14,780
—
—
—
—
—
—
—
—
—
—
—
4,335
—
—
—
—
—
—
4
29
—
28
61
195
4,258
44
(3,109)
1,193
639
16,992
(3,964)
(25)
3,525
(464)
(42)
(506)
$
6,995
$
4,876
$
660
$
4,335
$
16,866
$
6,315
$
4,909
$
927
$
4,335
$
16,486
326
Table of Contents
Combined Notes to Consolidated Financial Statements
(Dollars in millions, except per share data unless otherwise noted)
Note 18 — Fair Value of Financial Assets and Liabilities
(a)
As of December 31, 2019
Assets
Cash equivalents
NDT fund investments
Cash equivalents
Equities
Fixed income
(b)
(c)
Corporate debt
U.S. Treasury and
agencies
Foreign governments
State and municipal debt
Other
Fixed income subtotal
Private credit
Private equity
Real estate
NDT fund investments
subtotal
(d)(e)
Rabbi trust investments
Cash equivalents
Mutual funds
Fixed income
Life insurance contracts
Rabbi trust investments
subtotal
Commodity derivative assets
Economic hedges
Proprietary trading
Effect of netting and
allocation of collateral
(g)(h)
Commodity derivative
assets subtotal
Total assets
Liabilities
Commodity derivative liabilities
Economic hedges
Proprietary trading
Effect of netting and
allocation of collateral
(g)(h)
Commodity derivative
liabilities subtotal
Deferred compensation obligation
Total liabilities
Total net assets
Level 1
Level 2
Level 3
Not subject to
leveling
Total
Level 1
Level 2
Level 3
Not subject to
leveling
Total
Exelon
Generation
$
639
$
—
$
—
$
—
$
639
$
214
$
—
$
—
$
—
$
214
365
3,353
87
1,801
—
1,421
1,808
—
—
—
1,808
—
—
—
131
42
90
33
1,717
—
—
—
5,526
3,605
50
81
—
—
131
768
—
—
—
12
78
90
2,491
37
(908)
(2,162)
(140)
6,156
366
4,061
—
—
257
—
—
—
—
257
254
—
—
511
—
—
—
41
41
1,485
60
(588)
957
1,509
(1,071)
—
(2,855)
(34)
(1,228)
(15)
1,071
2,714
—
—
—
(175)
(147)
(322)
802
(441)
—
(441)
—
1,388
—
—
—
—
953
953
508
402
607
452
6,542
1,678
1,939
42
90
986
4,735
762
402
607
365
3,353
87
1,801
—
1,421
1,808
—
—
—
1,808
—
—
—
131
42
90
33
1,717
—
—
—
3,858
13,500
5,526
3,605
—
—
—
—
—
—
—
—
—
3,858
—
—
—
—
—
—
50
81
12
119
262
4,744
97
(3,658)
1,183
15,584
4
25
—
—
29
768
—
(908)
(140)
5,629
—
—
—
25
25
2,491
37
(2,162)
366
3,996
(5,154)
(49)
(1,071)
—
(2,855)
(34)
4,587
1,071
2,714
(616)
(147)
(763)
—
—
—
(175)
(41)
(216)
—
—
257
—
—
—
—
257
254
—
—
511
—
—
—
—
—
1,485
60
(588)
957
1,468
(927)
(15)
802
(140)
—
(140)
—
1,388
—
—
—
—
953
953
508
402
607
452
6,542
1,678
1,939
42
90
986
4,735
762
402
607
3,858
13,500
—
—
—
—
—
—
—
—
—
3,858
—
—
—
—
—
—
4
25
—
25
54
4,744
97
(3,658)
1,183
14,951
(4,853)
(49)
4,587
(315)
(41)
(356)
$
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 $409 million and $373 million at December 31, 2020 and 2019, respectively, and restricted cash of $59 million and $110 million at December 31,
2020 and 2019, respectively, and includes long-term restricted cash of $53 million and $177 million at December 31, 2020 and 2019, respectively, which is reported in
Other deferred debits in
327
Table of Contents
Combined Notes to Consolidated Financial Statements
(Dollars in millions, except per share data unless otherwise noted)
Note 18 — Fair Value of Financial Assets and Liabilities
(b)
(c)
(d)
the Consolidated Balance Sheets. Generation excludes cash of $171 million and $177 million at December 31, 2020 and 2019, respectively, and restricted cash of $20
million and $58 million at December 31, 2020 and 2019, respectively.
Includes $116 million and $90 million of cash received from outstanding repurchase agreements at December 31, 2020 and 2019, respectively, and is offset by an
obligation to repay upon settlement of the agreement as discussed in (e) below.
Includes investments in equities sold short of $(62) million and $(48) million as of December 31, 2020 and 2019, respectively, held in an investment vehicle primarily to
hedge the equity option component of its convertible debt.
Includes derivative assets of $2 million and $2 million, which have total notional amounts of $1,043 million and $724 million at December 31, 2020 and 2019, 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 $181 million and $147 million at December 31, 2020 and 2019, respectively, which include certain derivative assets that have notional amounts of
$104 million and $99 million at December 31, 2020 and 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.
(f) Reflects equity investments held by Generation which were previously designated as equity investments without readily determinable fair values but are now publicly traded
and therefore have readily determinable fair values. 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 December 31, 2020, which resulted in an unrealized gain of $186 million within Other, net
in Exelon's and Generation's Consolidated Statement of Operations and Comprehensive Income for the year ended December 31, 2020.
(g) Collateral posted/(received) 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. 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.
(h) Of the collateral posted/(received), $209 million and $511 million represents variation margin on the exchanges as of December 31, 2020 and 2019, respectively.
As of December 31, 2020, Exelon and Generation have outstanding commitments to invest in private credit, private equity, and real estate investments of
approximately $195 million, $254 million, and $369 million, respectively. These commitments will be funded by Generation’s existing NDT funds.
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. Exelon and Generation held investments without readily determinable fair values with carrying amounts of $69 million as of December 31,
2019. Changes in fair value, cumulative adjustments, and impairments were not material for the years ended December 31, 2020 and December 31, 2019.
ComEd, PECO, and BGE
As of December 31, 2020
Assets
Cash equivalents
Rabbi trust investments
Mutual funds
Life insurance contracts
(a)
Rabbi trust investments
subtotal
Total assets
Liabilities
Mark-to-market derivative
liabilities
Deferred compensation obligation
(b)
Total liabilities
—
—
—
285
—
—
—
Total net assets (liabilities)
$
285
$
ComEd
PECO
BGE
Level 1
Level 2
Level 3
Total
Level 1
Level 2
Level 3
Total
Level 1
Level 2
Level 3
Total
$
285
$
—
$
—
$
285
$
8
$
—
$
—
$
8
$
120
$
—
$
—
$
120
—
—
—
—
—
(8)
(8)
(8)
$
—
—
—
—
(301)
—
(301)
(301)
—
—
—
285
(301)
(8)
(309)
$
(24)
$
9
—
9
17
—
—
—
17
$
328
—
13
13
13
—
(9)
(9)
4
$
—
—
—
—
—
—
—
—
$
9
13
22
30
—
(9)
(9)
21
10
—
10
130
—
—
—
$
130
$
—
—
—
—
—
(5)
(5)
(5)
$
—
—
—
—
—
—
—
—
10
—
10
130
—
(5)
(5)
$
125
Table of Contents
Combined Notes to Consolidated Financial Statements
(Dollars in millions, except per share data unless otherwise noted)
Note 18 — Fair Value of Financial Assets and Liabilities
As of December 31, 2019
Assets
Cash equivalents
Rabbi trust investments
Mutual funds
Life insurance contracts
(a)
Rabbi trust investments
subtotal
Total assets
Liabilities
Mark-to-market derivative
liabilities
Deferred compensation
obligation
(b)
Total liabilities
Total net assets (liabilities)
$
280
$
ComEd
PECO
BGE
Level 1
Level 2
Level 3
Total
Level 1
Level 2
Level 3
Total
Level 1
Level 2
Level 3
Total
$
280
$
—
$
—
$
280
$
15
$
—
$
—
$
15
$
—
$
—
$
—
$
—
—
—
280
—
—
—
—
—
—
—
—
(8)
(8)
(8)
$
—
—
—
—
(301)
—
(301)
(301)
—
—
—
280
(301)
(8)
(309)
$
(29)
$
8
—
8
23
—
—
—
23
$
—
11
11
11
—
(9)
(9)
2
$
—
—
—
—
—
—
—
—
$
8
11
19
34
—
(9)
(9)
25
$
8
—
8
8
—
—
—
8
$
—
—
—
—
—
(5)
(5)
(5)
$
—
—
—
—
—
—
—
—
$
—
8
—
8
8
—
(5)
(5)
3
__________
(a) ComEd excludes cash of $83 million and $90 million at December 31, 2020 and 2019, respectively, and restricted cash of $37 million and $33 million at December 31,
2020 and 2019, respectively, and includes long-term restricted cash of $43 million and $163 million at December 31, 2020 and 2019, respectively, which is reported in
Other deferred debits in the Consolidated Balance Sheets. PECO excludes cash of $18 million and $12 million at December 31, 2020 and 2019, respectively. BGE
excludes cash of $24 million at both December 31, 2020 and 2019, respectively, and restricted cash of $1 million at both December 31, 2020 and 2019, respectively.
(b) The Level 3 balance consists of the current and noncurrent liability of $33 million and $268 million, respectively, at December 31, 2020 and $32 million and $269 million,
respectively, at December 31, 2019 related to floating-to-fixed energy swap contracts with unaffiliated suppliers.
PHI, Pepco, DPL, and ACE
PHI
(a)
Assets
Cash equivalents
Rabbi trust investments
Cash equivalents
Mutual funds
Fixed income
Life insurance contracts
Rabbi trust investments subtotal
Total assets
Liabilities
Deferred compensation obligation
Total liabilities
Total net assets
As of December 31, 2020
As of December 31, 2019
Level 1
Level 2
Level 3
Total
Level 1
Level 2
Level 3
Total
$
86
$
—
$
—
$
86
$
124
$
—
$
—
$
55
14
11
60
140
226
(17)
(17)
44
14
—
—
58
182
—
—
$
209
$
182
$
—
—
12
24
36
36
(19)
(19)
17
$
—
—
—
41
41
41
—
—
41
$
55
14
—
—
69
155
—
—
$
155
$
—
—
11
26
37
37
(17)
(17)
20
$
—
—
—
34
34
34
—
—
34
329
124
44
14
12
65
135
259
(19)
(19)
240
Table of Contents
Combined Notes to Consolidated Financial Statements
(Dollars in millions, except per share data unless otherwise noted)
Note 18 — Fair Value of Financial Assets and Liabilities
(a)
As of December 31, 2020
Assets
Cash equivalents
Rabbi trust investments
Cash equivalents
Fixed income
Life insurance contracts
Rabbi trust investments subtotal
Total assets
Liabilities
Deferred compensation
obligation
Total liabilities
Total net assets
As of December 31, 2019
(a)
Assets
Cash equivalents
Rabbi trust investments
Cash equivalents
Fixed income
Life insurance contracts
Rabbi trust investments subtotal
Total assets
Liabilities
Deferred compensation
obligation
Total liabilities
Total net assets
Pepco
DPL
ACE
Level 1
Level 2
Level 3
Total
Level 1
Level 2
Level 3
Total
Level 1
Level 2
Level 3
Total
$
35
$
—
$
—
$
35
$
—
$
—
$
—
$
—
$
13
$
—
$
—
$
13
53
—
—
53
88
—
—
88
$
—
2
26
28
28
(2)
(2)
26
$
—
—
34
34
34
—
—
34
$
53
2
60
115
150
(2)
(2)
$
148
$
—
—
—
—
—
—
—
—
$
—
—
—
—
—
—
—
—
$
—
—
—
—
—
—
—
—
$
—
—
—
—
—
—
—
—
$
—
—
—
—
13
—
—
13
$
—
—
—
—
—
—
—
—
$
—
—
—
—
—
—
—
—
$
—
—
—
—
13
—
—
13
Level 1
Level 2
Level 3
Total
Level 1
Level 2
Level 3
Total
Level 1
Level 2
Level 3
Total
Pepco
DPL
ACE
$
34
$
—
$
—
$
34
$
—
$
—
$
—
$
—
$
16
$
—
$
—
$
16
43
—
—
43
77
—
—
77
$
—
2
24
26
26
(2)
(2)
24
$
—
—
41
41
41
—
—
41
$
43
2
65
110
144
(2)
(2)
$
142
$
—
—
—
—
—
—
—
—
$
—
—
—
—
—
—
—
—
$
—
—
—
—
—
—
—
—
$
—
—
—
—
—
—
—
—
$
—
—
—
—
16
—
—
16
$
—
—
—
—
—
—
—
—
$
—
—
—
—
—
—
—
—
$
—
—
—
—
16
—
—
16
__________
(a) PHI excludes cash of $74 million and $57 million at December 31, 2020 and 2019, respectively, and includes long-term restricted cash of $10 million and $14 million at
December 31, 2020 and 2019, respectively, which is reported in Other deferred debits in the Consolidated Balance Sheets. Pepco excludes cash of $30 million and $29
million at December 31, 2020 and 2019, respectively. DPL excludes cash of $15 million and $13 million at December 31, 2020 and 2019, respectively. ACE excludes cash
of $17 million and $12 million at December 31, 2020 and 2019, respectively, and includes long-term restricted cash of $10 million and $14 million at December 31, 2020
and 2019, respectively, which is reported in Other deferred debits in the Consolidated Balance Sheets.
330
Table of Contents
Combined Notes to Consolidated Financial Statements
(Dollars in millions, except per share data unless otherwise noted)
Note 18 — 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 years ended
December 31, 2020 and 2019:
For the year ended December 31, 2020
Total
NDT Fund Investments
Exelon
Generation
Mark-to-Market
Derivatives
Total Generation
ComEd
Mark-to-Market
Derivatives
PHI and Pepco
Life Insurance
Contracts
Eliminated in
Consolidation
$
1,068
$
511
$
817
$
1,328
$
(301)
$
41
$
Balance as of January 1, 2020
Total realized / unrealized gains (losses)
Included in net income
Included in noncurrent payables to
affiliates
Included in regulatory assets/liabilities
Change in collateral
Purchases, sales, issuances and settlements
Purchases
Sales
Settlements
Transfers into Level 3
Transfers out of Level 3
Balance as of December 31, 2020
The amount of total gains included in net
income attributed to the change in unrealized
gains (losses) related to assets and liabilities
held as of December 31, 2020
$
$
(414)
(a)
(412)
21
—
(53)
151
(27)
(45)
(12)
(24)
(b)
—
—
—
—
—
—
—
—
—
$
$
927
$
(301)
8
$
—
$
$
(409)
—
21
(53)
151
(27)
(55)
(12)
(24)
2
21
—
—
8
—
(45)
—
—
660
$
497
$
—
—
(53)
143
(27)
—
(12)
(24)
430
(c)
(c)
11
$
2
$
6
331
3
—
—
—
—
—
(10)
—
—
34
$
3
$
—
—
(21)
21
—
—
—
—
—
—
—
—
Table of Contents
Combined Notes to Consolidated Financial Statements
(Dollars in millions, except per share data unless otherwise noted)
For the year ended December 31, 2019
Balance as of January 1, 2019
Total realized / unrealized gains (losses)
Included in net income
Included in noncurrent payables to
affiliates
Included in regulatory assets/liabilities
Change in collateral
Purchases, sales, issuances and settlements
Purchases
Sales
Settlements
Transfers into Level 3
Transfers out of Level 3
Balance as of December 31, 2019
The amount of total gains included in net
income attributed to the change in unrealized
gains (losses) related to assets and liabilities
held as of December 31, 2019
$
$
$
Exelon
Total
907
(23)
—
(18)
138
176
(23)
(89)
5
(5)
1,068
$
Note 18 — Fair Value of Financial Assets and Liabilities
Generation
Mark-to-Market
Derivatives
Total Generation
ComEd
Mark-to-Market
Derivatives
PHI and Pepco
Life Insurance
Contracts
Eliminated in
Consolidation
575
$
1,118
$
(249)
$
38
$
NDT Fund Investments
543
$
$
5
34
—
—
44
(21)
(94)
—
—
511
$
(31)
(a)
—
—
138
132
(2)
5
5
(5)
(c)
(c)
817
(26)
34
—
138
176
(23)
(89)
5
(5)
—
—
(52)
—
(b)
—
—
—
—
—
$
$
1,328
$
(301)
356
$
—
$
$
3
—
—
—
—
—
—
—
—
41
$
3
$
—
—
(34)
34
—
—
—
—
—
—
—
—
359
$
5
$
351
__________
(a)
(b)
Includes a reduction for the reclassification of $420 million and $377 million of realized gains due to the settlement of derivative contracts for the years ended December 31,
2020 and 2019, respectively.
Includes $33 million of decreases in fair value and an increase for realized losses due to settlements of $33 million recorded in purchased power expense associated with
floating-to-fixed energy swap contracts with unaffiliated suppliers for the year ended December 31, 2020. Includes $78 million of decreases in fair value and an increase for
realized losses due to settlements of $26 million recorded in purchased power expense associated with floating-to-fixed energy swap contracts with unaffiliated suppliers
for the year ended December 31, 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.
The following tables present the income statement classification of the total realized and unrealized gains (losses) included in income for Level 3 assets and
liabilities measured at fair value on a recurring basis during the years ended December 31, 2020 and 2019:
Operating
Revenues
Purchased
Power and
Fuel
Operating and
Maintenance
Other, net
Operating
Revenues
Exelon
Generation
Purchased
Power and
Fuel
PHI and Pepco
Other, net
Operating and
Maintenance
Total (losses) gains included in net income
for the year ended December 31, 2020
Change in unrealized (losses) gains relating
to assets and liabilities held for the year
ended December 31, 2020
$
(404)
$
(10)
$
3
$
2
$
(404)
$
(10)
$
2
$
(31)
37
3
2
(31)
37
2
3
3
332
Table of Contents
Combined Notes to Consolidated Financial Statements
(Dollars in millions, except per share data unless otherwise noted)
Note 18 — Fair Value of Financial Assets and Liabilities
Exelon
Operating
Revenues
Purchased
Power and
Fuel
Operating and
Maintenance
Other, net
Operating
Revenues
Generation
Purchased
Power and
Fuel
PHI and Pepco
Other, net
Operating and
Maintenance
Total gains (losses) included in net income
for the year ended December 31, 2019
$
Change in unrealized gains (losses) relating
to assets and liabilities held for the year
ended December 31, 2019
219
$
(245)
$
3
$
5
$
219
$
(245)
$
5
$
546
(195)
3
5
546
(195)
5
3
3
Valuation Techniques Used to Determine Fair Value
Cash Equivalents (All Registrants). Investments with original maturities of three months or less when purchased, including mutual and money market
funds, are considered cash equivalents. The fair values are based on observable market prices and, therefore, are included in the recurring fair value
measurements hierarchy as Level 1.
NDT Fund Investments (Exelon and Generation). The trust fund investments have been established to satisfy Generation’s and CENG's nuclear
decommissioning obligations as required by the NRC. The NDT funds hold debt and equity securities directly and indirectly through commingled funds and
mutual funds, which are included in equities and fixed income. Generation’s and CENG's NDT fund investments policies outline investment guidelines for the
trusts and limit the trust funds’ exposures to investments in highly illiquid markets and other alternative investments, including private credit, private equity,
and real estate. Investments with maturities of three months or less when purchased, including certain short-term fixed income securities are considered
cash equivalents and included in the recurring fair value measurements hierarchy as Level 1 or Level 2.
Equities. These investments consist of individually held equity securities, equity mutual funds, and equity commingled funds in domestic and foreign markets.
With respect to individually held equity securities, the trustees obtain prices from pricing services, whose prices are generally obtained from direct feeds from
market exchanges, which Exelon and Generation are able to independently corroborate. Equity securities held individually, including real estate investment
trusts, rights, and warrants, are primarily traded on exchanges that contain only actively traded securities due to the volume trading requirements imposed by
these exchanges. The equity securities that are held directly by the trust funds are valued based on quoted prices in active markets and categorized as Level
1. Certain equity securities have been categorized as Level 2 because they are based on evaluated prices that reflect observable market information, such
as actual trade information or similar securities. Certain private placement equity securities are categorized as Level 3 because they are not publicly traded
and are priced using significant unobservable inputs.
Equity commingled funds and mutual funds are maintained by investment companies, and fund investments are held in accordance with a stated set of fund
objectives. The values of some of these funds are publicly quoted. For mutual funds which are publicly quoted, the funds are valued based on quoted prices
in active markets and have been categorized as Level 1. For equity commingled funds and mutual funds which are not publicly quoted, the fund
administrators value the funds using the NAV per fund share, derived from the quoted prices in active markets of the underlying securities and are not
classified within the fair value hierarchy. These investments typically can be redeemed monthly or more frequently, with 30 or less days of notice and without
further restrictions.
Fixed income. For fixed income securities, which consist primarily of corporate debt securities, U.S. government securities, foreign government securities,
municipal bonds, asset and mortgage-backed securities, commingled funds, mutual funds, and derivative instruments, the trustees obtain multiple prices
from pricing vendors whenever possible, which enables cross-provider validations in addition to checks for unusual daily movements. A primary price source
is identified based on asset type, class, or issue for each security. With respect to individually held fixed income securities, the trustees monitor prices
supplied by pricing services and may use a supplemental price source or change the primary price source of a given security if the portfolio managers
challenge an assigned price and the trustees determine that another price source is considered to be preferable. Exelon and Generation have obtained an
understanding of how these prices are derived, including the nature and observability of the inputs used in deriving such prices. Additionally, Exelon and
Generation selectively
333
Table of Contents
Combined Notes to Consolidated Financial Statements
(Dollars in millions, except per share data unless otherwise noted)
Note 18 — Fair Value of Financial Assets and Liabilities
corroborate the fair values of securities by comparison to other market-based price sources. Investments in U.S. Treasury securities have been categorized
as Level 1 because they trade in highly-liquid and transparent markets. Certain private placement fixed income securities have been categorized as Level 3
because they are priced using certain significant unobservable inputs and are typically illiquid. The remaining fixed income securities, including certain other
fixed income investments, are based on evaluated prices that reflect observable market information, such as actual trade information of similar securities,
adjusted for observable differences and are categorized as Level 2.
Other fixed income investments primarily consist of fixed income commingled funds and mutual funds, which are maintained by investment companies and
hold fund investments in accordance with a stated set of fund objectives. The values of some of these funds are publicly quoted. For mutual funds which are
publicly quoted, the funds are valued based on quoted prices in active markets and have been categorized as Level 1. For fixed income commingled funds
and mutual funds which are not publicly quoted, the fund administrators value the funds using the NAV per fund share, derived from the quoted prices in
active markets of the underlying securities and are not classified within the fair value hierarchy. These investments typically can be redeemed monthly or
more frequently, with 30 or less days of notice and without further restrictions.
Derivative instruments. These instruments, consisting primarily of futures and swaps to manage risk, are recorded at fair value. Over-the-counter derivatives
are valued daily, based on quoted prices in active markets and trade in open markets, and have been categorized as Level 1. Derivative instruments other
than over-the-counter derivatives are valued based on external price data of comparable securities and have been categorized as Level 2.
Private credit. Private credit investments primarily consist of investments in private debt strategies. These investments are generally less liquid assets with
an underlying term of 3 to 5 years and are intended to be held to maturity. The fair value of these investments is determined by the fund manager or
administrator 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 credit investments held directly by Exelon and Generation are categorized as Level 3 because they are based largely on
inputs that are unobservable and utilize complex valuation models. 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. Managed
private credit fund investments are not classified within the fair value hierarchy because their fair value is determined using NAV or its equivalent as a
practical expedient.
Private equity. These investments include those in limited partnerships that invest in operating companies that are not publicly traded on a stock exchange
such as leveraged buyouts, growth capital, venture capital, distressed investments, and investments in natural resources. 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 valuations are reported by the fund manager and are based on the valuation of the underlying investments, which
include unobservable inputs such as cost, operating results, discounted future cash flows, and market based comparable data. These valuation inputs are
unobservable. The fair value of private equity investments is determined using NAV or its equivalent as a practical expedient, and therefore, these
investments are not classified within the fair value hierarchy.
Real estate. These investments are funds with a direct investment in pools of real estate properties. These funds are reported by the fund manager and are
generally based on independent appraisals from sources with professional qualifications, typically using a combination of market comparables and
discounted cash flows. These valuation inputs are unobservable. The fair value of real estate investments is determined using NAV or its equivalent as a
practical expedient, and therefore, these investments are not classified within the fair value hierarchy.
Generation evaluated its NDT portfolios for the existence of significant concentrations of credit risk as of December 31, 2020. Types of concentrations that
were evaluated include, but are not limited to, investment concentrations in a single entity, type of industry, foreign country, and individual fund. As of
December 31, 2020, there were no significant concentrations (generally defined as greater than 10 percent) of risk in Generation's NDT assets.
See Note 10 — Asset Retirement Obligations for additional information on the NDT fund investments. See Note 15 — Retirement Benefits for the valuation
techniques used for hedge fund investments.
334
Table of Contents
Combined Notes to Consolidated Financial Statements
(Dollars in millions, except per share data unless otherwise noted)
Note 18 — Fair Value of Financial Assets and Liabilities
Rabbi Trust Investments (Exelon, Generation, PECO, BGE, PHI, Pepco, DPL, and ACE). The Rabbi trusts were established to hold assets related to
deferred compensation plans existing for certain active and retired members of Exelon’s executive management and directors. The Rabbi trusts' assets are
included in investments in the Registrants’ Consolidated Balance Sheets and consist primarily of money market funds, mutual funds, fixed income securities,
and life insurance policies. Money market funds and mutual funds are publicly quoted and have been categorized as Level 1 given the clear observability of
the prices. The fair values of fixed income securities are based on evaluated prices that reflect observable market information, such as actual trade
information or similar securities, adjusted for observable differences and are categorized in Level 2. The life insurance policies are valued using the cash
surrender value of the policies, net of loans against those policies, which is provided by a third-party. Certain life insurance policies, which consist primarily of
mutual funds that are priced based on observable market data, have been categorized as Level 2 because the life insurance policies can be liquidated at the
reporting date for the value of the underlying assets. Life insurance policies that are valued using unobservable inputs have been categorized as Level 3,
where the fair value is determined based on the cash surrender value of the policy, which contains unobservable inputs and assumptions. Because Exelon
relies on its third-party insurance provider to develop the inputs without adjustment for the valuations of its Level 3 investments, quantitative information
about significant unobservable inputs used in valuing these investments is not reasonably available to Exelon. Therefore, Exelon has not disclosed such
inputs.
Deferred Compensation Obligations (All Registrants). The Registrants’ deferred compensation plans allow participants to defer certain cash
compensation into a notional investment account. The Registrants include such plans in other current and noncurrent liabilities in their Consolidated Balance
Sheets. The value of the Registrants’ deferred compensation obligations is based on the market value of the participants’ notional investment accounts. The
underlying notional investments are comprised primarily of equities, mutual funds, commingled funds, and fixed income securities which are based on
directly and indirectly observable market prices. Since the deferred compensation obligations themselves are not exchanged in an active market, they are
categorized as Level 2 in the fair value hierarchy.
The value of certain employment agreement obligations (which are included with the Deferred Compensation Obligation in the tables above) are based on a
known and certain stream of payments to be made over time and are categorized as Level 2 within the fair value hierarchy.
Investments in Equities (Exelon and Generation). Exelon and Generation hold certain investments in equity securities with readily determinable fair
values in addition to those held within the NDT funds. These equity securities are valued based on quoted prices in active markets and are categorized as
Level 1.
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 6 — Accounts Receivable for additional information on the sale of certain receivables.
Mark-to-Market Derivatives (Exelon, Generation, and ComEd). Derivative contracts are traded in both exchange-based and non-exchange-based
markets. Exchange-based derivatives that are valued using unadjusted quoted prices in active markets are categorized in Level 1 in the fair value hierarchy.
Certain derivatives’ pricing is verified using indicative price quotations available through brokers or over-the-counter, on-line exchanges and are categorized
in Level 2. These price quotations reflect the average of the bid-ask, mid-point prices and are obtained from sources that the Registrants believe provide the
most liquid market for the commodity. The price quotations are reviewed and corroborated to ensure the prices are observable and representative of an
orderly transaction between market participants. This includes consideration of actual transaction volumes, market delivery points, bid-ask spreads, and
contract duration. The remainder of derivative contracts are valued using the Black model, an industry standard option valuation model. The Black model
takes into account inputs such as contract terms, including maturity, and market parameters, including assumptions of the future prices of energy, interest
rates, volatility, credit worthiness, and credit spread. For derivatives that trade in liquid markets, such as generic forwards, swaps, and options, model inputs
are generally observable. Such instruments are categorized in Level 2. The Registrants’ derivatives are predominantly at liquid trading points.
335
Table of Contents
Combined Notes to Consolidated Financial Statements
(Dollars in millions, except per share data unless otherwise noted)
Note 18 — Fair Value of Financial Assets and Liabilities
For derivatives that trade in less liquid markets with limited pricing information, model inputs generally would include both observable and unobservable
inputs. These valuations may include an estimated basis adjustment from an illiquid trading point to a liquid trading point for which active price quotations are
available. Such instruments are categorized in Level 3.
For valuations that include both observable and unobservable inputs, if the unobservable input is determined to be significant to the overall inputs, the entire
valuation is categorized in Level 3. This includes derivatives valued using indicative price quotations whose contract tenure extends into unobservable
periods. In instances where observable data is unavailable, consideration is given to the assumptions that market participants would use in valuing the asset
or liability. This includes assumptions about market risks such as liquidity, volatility, and contract duration. Such instruments are categorized in Level 3 as the
model inputs generally are not observable. Forward price curves for the power market utilized by the front office to manage the portfolio, are reviewed and
verified by the middle office, and used for financial reporting by the back office. The Registrants consider credit and nonperformance risk in the valuation of
derivative contracts categorized in Level 2 and 3, including both historical and current market data, in their assessment of credit and nonperformance risk by
counterparty. Due to master netting agreements and collateral posting requirements, the impacts of credit and nonperformance risk were not material to the
financial statements.
Disclosed below is detail surrounding the Registrants’ significant Level 3 valuations. The calculated fair value includes marketability discounts for margining
provisions and other attributes. Generation’s Level 3 balance generally consists of forward sales and purchases of power and natural gas and certain
transmission congestion contracts. Generation utilizes various inputs and factors including market data and assumptions that market participants would use
in pricing assets or liabilities as well as assumptions about the risks inherent in the inputs to the valuation technique. The inputs and factors include forward
commodity prices, commodity price volatility, contractual volumes, delivery location, interest rates, credit quality of counterparties, and credit enhancements.
For commodity derivatives, the primary input to the valuation models is the forward commodity price curve for each instrument. Forward commodity price
curves are derived by risk management for liquid locations and by the traders and portfolio managers for illiquid locations. All locations are reviewed and
verified by risk management considering published exchange transaction prices, executed bilateral transactions, broker quotes, and other observable or
public data sources. The relevant forward commodity curve used to value each of the derivatives depends on a number of factors, including commodity type,
delivery location, and delivery period. Price volatility varies by commodity and location. When appropriate, Generation discounts future cash flows using risk
free interest rates with adjustments to reflect the credit quality of each counterparty for assets and Generation’s own credit quality for liabilities. The level of
observability of a forward commodity price varies generally due to the delivery location and delivery period. Certain delivery locations including PJM West
Hub (for power) and Henry Hub (for natural gas) are more liquid and prices are observable for up to three years in the future. The observability period of
volatility is generally shorter than the underlying power curve used in option valuations. The forward curve for a less liquid location is estimated by using the
forward curve from the liquid location and applying a spread to represent the cost to transport the commodity to the delivery location. This spread does not
typically represent a majority of the instrument’s market price. As a result, the change in fair value is closely tied to liquid market movements and not a
change in the applied spread. The change in fair value associated with a change in the spread is generally immaterial. An average spread calculated across
all Level 3 power and gas delivery locations is approximately $2.49 and $0.38 for power and natural gas, respectively. Many of the commodity derivatives
are short term in nature and thus a majority of the fair value may be based on observable inputs even though the contract as a whole must be classified as
Level 3.
On December 17, 2010, ComEd entered into several 20-year floating to fixed energy swap contracts with unaffiliated suppliers for the procurement of long-
term renewable energy and associated RECs. See Note 16 — Derivative Financial Instruments for additional information. The fair value of these swaps has
been designated as a Level 3 valuation due to the long tenure of the positions and internal modeling assumptions. The modeling assumptions include using
natural gas heat rates to project long term forward power curves adjusted by a renewable factor that incorporates time of day and seasonality factors to
reflect accurate renewable energy pricing. In addition, marketability reserves are applied to the positions based on the tenor and supplier risk.
See Note 16 — Derivative Financial Instruments for additional information on mark-to-market derivatives.
336
Table of Contents
Combined Notes to Consolidated Financial Statements
(Dollars in millions, except per share data unless otherwise noted)
Note 18 — Fair Value of Financial Assets and Liabilities
The following table presents the significant inputs to the forward curve used to value these positions:
Type of trade
Mark-to-market derivatives—
Economic hedges (Exelon
and Generation)
(a)(b)
Mark-to-market derivatives—
Proprietary trading (Exelon
and Generation)
(a)(b)
Mark-to-market derivatives
(Exelon and ComEd)
$
$
$
Fair Value at
December 31,
2020
Fair Value at
December 31,
2019
Valuation
Technique
Unobservable
Input
245
$
Discounted Cash
Flow
Forward power
price
558
Option
Model
Forward gas
price
Volatility
percentage
23
$
Discounted Cash
Flow
Forward power
price
45
(301)
$
(301)
Discounted Cash
Flow
Forward heat rate
(c)
Marketability
reserve
Renewable
factor
2020 Range & Arithmetic Average
2019 Range & Arithmetic Average
$2.25
$1.57
11%
$10
8x
3%
91%
-
-
-
-
-
-
-
$163
$30
$9
$7.88
$2.59
$0.83
237%
32%
8%
$106
$27
$25
9x
8%
8.85x
4.93%
9x
3%
123%
99%
91%
-
-
-
-
-
-
-
$180
$29
$10.72
$2.55
236%
70%
$180
$33
10x
7%
9.68x
4.95%
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 posted on level three positions of $162 million and $214 million as of December 31, 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.
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.
337
Table of Contents
Combined Notes to Consolidated Financial Statements
(Dollars in millions, except per share data unless otherwise noted)
Note 19 — Commitments and Contingencies
19. Commitments and Contingencies (All Registrants)
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 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 December 31, 2020:
Description
Total commitments
Remaining commitments
(a)
Exelon
PHI
Pepco
DPL
ACE
$
513 $
320 $
120 $
82
67
55
89 $
7
111
5
__________
(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 $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 December 31, 2020, 27 MWs of new generation were developed and Exelon and Generation have incurred costs of $119 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 March 2019. The third and final 40 MW wind REC tranche will be
conducted in 2022.
338
Table of Contents
Combined Notes to Consolidated Financial Statements
(Dollars in millions, except per share data unless otherwise noted)
Note 19 — Commitments and Contingencies
Commercial Commitments (All Registrants). The Registrants' commercial commitments as of December 31, 2020, representing commitments potentially
triggered by future events, were as follows:
Exelon
Letters of credit
(a)
Surety bonds
Financing trust guarantees
Guaranteed lease residual values
(b)
Total commercial commitments
Generation
Letters of credit
(a)
Surety bonds
Total commercial commitments
ComEd
Letters of credit
(a)
Surety bonds
Financing trust guarantees
Total commercial commitments
PECO
Surety bonds
(a)
Financing trust guarantees
Total commercial commitments
BGE
Letters of credit
(a)
Surety bonds
Total commercial commitments
PHI
(a)
Surety bonds
Guaranteed lease residual values
(b)
Total commercial commitments
Pepco
Surety bonds
(a)
Guaranteed lease residual values
(b)
Total commercial commitments
DPL
(a)
Surety bonds
Guaranteed lease residual values
(b)
Total commercial commitments
ACE
Surety bonds
(a)
Guaranteed lease residual values
(b)
Total commercial commitments
Total
2021
2022
2023
2024
2025
2026 and
beyond
Expiration within
$
$
$
$
$
$
$
$
$
$
$
$
$
$
$
$
$
$
1,243 $
1,070
378
28
2,719 $
1,179 $
1,017
—
2
2,198 $
1,228
$
1,164
$
926
873
2,154 $
2,037 $
7
$
16
200
223 $
2
$
178
180 $
$
2
3
5 $
$
22
28
50 $
$
14
9
23 $
$
4
12
16 $
4
$
7
11 $
7
$
16
—
23 $
2
$
—
2 $
$
2
3
5 $
$
22
2
24 $
$
14
—
14 $
$
4
1
5 $
4
$
1
5 $
50 $
53
—
3
106 $
50
$
53
103 $
—
$
—
—
— $
—
$
—
— $
$
—
—
— $
$
—
3
3 $
$
—
1
1 $
$
—
1
1 $
—
$
1
1 $
14 $
—
—
3
17 $
14
$
—
14 $
—
$
—
—
— $
—
$
—
— $
$
—
—
— $
$
—
3
3 $
$
—
1
1 $
$
—
1
1 $
—
$
1
1 $
— $
—
—
6
6
—
—
—
—
—
—
—
—
—
—
—
—
—
—
6
6
—
2
2
—
3
3
—
1
1
$
$
$
$
$
$
$
$
$
$
$
$
$
$
$
$
$
—
—
—
5
5
—
—
—
—
—
—
—
—
—
—
—
—
—
—
5
5
—
2
2
—
2
2
—
1
1
$
$
$
$
$
$
$
$
$
$
$
$
$
$
$
$
$
$
—
—
378
9
387
—
—
—
—
—
200
200
—
178
178
—
—
—
—
9
9
—
3
3
—
4
4
—
2
2
__________
(a) Surety bonds—Guarantees issued related to contract and commercial agreements, excluding bid bonds.
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Note 19 — 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 $71 million
guaranteed by Exelon and PHI, of which $24 million, $30 million, and $17 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.
Nuclear Insurance (Exelon and Generation)
Generation is subject to liability, property damage, and other risks associated with major incidents at any of its nuclear stations. Generation has mitigated its
financial exposure to these risks through insurance and other industry risk-sharing provisions.
The Price-Anderson Act was enacted to ensure the availability of funds for public liability claims arising from an incident at any of the U.S. licensed nuclear
facilities and to limit the liability of nuclear reactor owners for such claims from any single incident. As of December 31, 2020, the current liability limit per
incident is $13.8 billion and is subject to change to account for the effects of inflation and changes in the number of licensed reactors at least once every five
years with the last adjustment effective November 1, 2018. In accordance with the Price-Anderson Act, Generation maintains financial protection at levels
equal to the amount of liability insurance available from private sources through the purchase of private nuclear energy liability insurance for public liability
claims that could arise in the event of an incident. Effective January 1, 2017, the required amount of nuclear energy liability insurance purchased is $450
million for each operating site. Claims exceeding that amount are covered through mandatory participation in a financial protection pool, as required by the
Price Anderson-Act, which provides the additional $13.3 billion per incident in funds available for public liability claims. Participation in this secondary
financial protection pool requires the operator of each reactor to fund its proportionate share of costs for any single incident that exceeds the primary layer of
financial protection. Generation’s share of this secondary layer would be approximately $2.9 billion, however any amounts payable under this secondary
layer would be capped at $434 million per year.
In addition, the U.S. Congress could impose revenue-raising measures on the nuclear industry to pay public liability claims exceeding the $13.8 billion limit
for a single incident.
As part of the execution of the NOSA on April 1, 2014, Generation executed an Indemnity Agreement pursuant to which Generation agreed to indemnify
EDF and its affiliates against third-party claims that may arise from any future nuclear incident (as defined in the Price-Anderson Act) in connection with the
CENG nuclear plants or their operations. Exelon guarantees Generation’s obligations under this indemnity. See Note 23 — Variable Interest Entities for
additional information on Generation’s operations relating to CENG.
Generation is required each year to report to the NRC the current levels and sources of property insurance that demonstrates Generation possesses
sufficient financial resources to stabilize and decontaminate a reactor and reactor station site in the event of an accident. The property insurance maintained
for each facility is currently provided through insurance policies purchased from NEIL, an industry mutual insurance company of which Generation is a
member.
NEIL may declare distributions to its members as a result of favorable operating experience. In recent years, NEIL has made distributions to its members,
but Generation cannot predict the level of future distributions or if they will continue at all. Generation's portion of the annual distribution declared by NEIL is
estimated to be $75 million for 2020, and was $136 million and $58 million for 2019 and 2018, respectively. In addition, in March 2018, NEIL declared a
supplemental distribution. Generation's portion of the supplemental distribution declared by NEIL was $31 million. The distributions were recorded as a
reduction to Operating and maintenance expense within Exelon and Generation’s Consolidated Statements of Operations and Comprehensive Income.
Premiums paid to NEIL by its members are also subject to a potential assessment for adverse loss experience in the form of a retrospective premium
obligation. NEIL has never assessed this retrospective premium since its formation in 1973, and Generation cannot predict the level of future assessments, if
any. The current maximum aggregate annual retrospective premium obligation for Generation is approximately $252 million. NEIL requires its members to
maintain an investment grade credit rating or to ensure collectability of their annual retrospective premium obligation by providing a financial guarantee, letter
of credit, deposit premium, or some other means of assurance.
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Note 19 — Commitments and Contingencies
NEIL provides “all risk” property damage, decontamination, and premature decommissioning insurance for each station for losses resulting from damage to
its nuclear plants, either due to accidents or acts of terrorism. If the decision is made to decommission the facility, a portion of the insurance proceeds will be
allocated to a fund, which Generation is required by the NRC to maintain, to provide for decommissioning the facility. In the event of an insured loss,
Generation is unable to predict the timing of the availability of insurance proceeds to Generation and the amount of such proceeds that would be available. In
the event that one or more acts of terrorism cause accidental property damage within a twelve-month period from the first accidental property damage under
one or more policies for all insured plants, the maximum recovery by Generation will be an aggregate of $3.2 billion plus such additional amounts as the
insurer may recover for all such losses from reinsurance, indemnity, and any other source, applicable to such losses.
For its insured losses, Generation is self-insured to the extent that losses are within the policy deductible or exceed the amount of insurance maintained.
Uninsured losses and other expenses, to the extent not recoverable from insurers or the nuclear industry, could also be borne by Generation. Any such
losses could have a material adverse effect on Exelon’s and Generation’s financial statements.
Spent Nuclear Fuel Obligation (Exelon and Generation)
Under the NWPA, the DOE is responsible for the development of a geologic repository for and the disposal of SNF and high-level radioactive waste. As
required by the NWPA, Generation is a party to contracts with the DOE (Standard Contracts) to provide for disposal of SNF from Generation’s nuclear
generating stations. In accordance with the NWPA and the Standard Contracts, Generation historically had paid the DOE one mill ($0.001) per kWh of net
nuclear generation for the cost of SNF disposal. Due to the lack of a viable disposal program, the DOE reduced the SNF disposal fee to zero in May 2014.
Until a new fee structure is in effect, Exelon and Generation will not accrue any further costs related to SNF disposal fees. This fee may be adjusted
prospectively to ensure full cost recovery.
Generation currently assumes the DOE will begin accepting SNF in 2035 and uses that date for purposes of estimating the nuclear decommissioning asset
retirement obligations. The SNF acceptance date assumption is based on management’s estimates of the amount of time required for DOE to select a site
location and develop the necessary infrastructure for long-term SNF storage.
The NWPA and the Standard Contracts required the DOE to begin taking possession of SNF generated by nuclear generating units by no later than January
31, 1998. The DOE, however, failed to meet that deadline and its performance is expected to be delayed significantly. In August 2004, Generation and the
DOJ, in close consultation with the DOE, reached a settlement under which the government agreed to reimburse Generation, subject to certain damage
limitations based on the extent of the government’s breach, for costs associated with storage of SNF at Generation’s nuclear stations pending the DOE’s
fulfillment of its obligations. Generation’s settlement agreement does not include FitzPatrick and FitzPatrick does not currently have a settlement agreement
in place. Calvert Cliffs, Ginna, and Nine Mile Point each have separate settlement agreements in place with the DOE which were extended during 2020 to
provide for the reimbursement of SNF storage costs through December 31, 2022. Generation submits annual reimbursement requests to the DOE for costs
associated with the storage of SNF. In all cases, reimbursement requests are made only after costs are incurred and only for costs resulting from DOE
delays in accepting the SNF.
Under the settlement agreements, Generation received total cumulative cash reimbursements of $1,455 million through December 31, 2020 for costs
incurred. After considering the amounts due to co-owners of certain nuclear stations and to the former owner of Oyster Creek, Generation received net
cumulative cash reimbursements of $1,266 million. As of December 31, 2020 and 2019, the amount of SNF storage costs for which reimbursement has
been or will be requested from the DOE under the DOE settlement agreements is as follows:
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(Dollars in millions, except per share data unless otherwise noted)
DOE receivable - current
(a)
DOE receivable - noncurrent
(b)
Amounts owed to co-owners
(c)
Note 19 — Commitments and Contingencies
December 31, 2020
December 31, 2019
$
129 $
70
(23)
249
30
(37)
__________
(a) Recorded in Accounts receivable, other.
(b) Recorded in Deferred debits and other assets, other.
(c) Recorded in Accounts receivable, other. Represents amounts owed to the co-owners of Peach Bottom, Quad Cities, and Nine Mile Point Unit 2 generating facilities.
The Standard Contracts with the DOE also required the payment to the DOE of a one-time fee applicable to nuclear generation through April 6, 1983. The
below table outlines the SNF liability recorded at Exelon and Generation as of December 31, 2020 and 2019:
Former ComEd units
(b)
Fitzpatrick
(a)
Total SNF Obligation
December 31, 2020
December 31, 2019
$
$
1,082 $
126
1,208 $
1,075
124
1,199
__________
(a) ComEd previously elected to defer payment of the one-time fee of $277 million for its units (which are now part of Generation), with interest to the date of payment, until
just prior to the first delivery of SNF to the DOE. The unfunded liabilities for SNF disposal costs, including the one-time fee, were transferred to Generation as part of
Exelon’s 2001 corporate restructuring.
(b) A prior owner of FitzPatrick elected to defer payment of the one-time fee of $34 million, with interest to the date of payment, for the FitzPatrick unit. As part of the
FitzPatrick acquisition on March 31, 2017, Generation assumed a SNF liability for the DOE one-time fee obligation with interest related to FitzPatrick along with an
offsetting asset, included in Other deferred debits and other assets, for the contractual right to reimbursement from NYPA, a prior owner of FitzPatrick, for amounts paid for
the FitzPatrick DOE one-time fee obligation.
Interest for Exelon's and Generation's SNF liabilities accrues at the 13-week Treasury Rate. The 13-week Treasury Rate in effect for calculation of the
interest accrual at December 31, 2020 was 0.096% for the deferred amount transferred from ComEd and 0.101% for the deferred FitzPatrick amount.
The following table summarizes sites for which Exelon and Generation do not have an outstanding SNF Obligation:
Description
Fees have been paid
Sites
Former PECO units, Clinton and Calvert Cliffs
Outstanding SNF Obligation remains with former owners
Nine Mile Point, Ginna and TMI
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.
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Note 19 — Commitments and Contingencies
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 2026.
PECO has 8 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 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 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.
As of December 31, 2020 and 2019, 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:
December 31, 2020
December 31, 2019
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
483 $
314 $
478 $
121
293
23
2
44
42
1
1
—
293
21
—
—
—
—
—
105
304
19
2
48
46
1
1
320
—
303
17
—
—
—
—
—
Exelon
Generation
$
ComEd
PECO
BGE
PHI
Pepco
DPL
ACE
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 for the selection of a final remedy. The ROD Amendment modified the
remedy previously selected by EPA in its 2008 ROD. While the 2008 ROD
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Note 19 — Commitments and Contingencies
required only that the radiological materials and other wastes at the site be capped, the 2018 ROD Amendment requires partial excavation of the radiological
materials in addition to the previously selected capping remedy. The ROD Amendment 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 the 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 have 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 Settlement Agreement and Order on Consent for the performance by the PRPs of the
groundwater Remedial Investigation (RI)/Feasibility Study (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 $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 that,
or the extent to which 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 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.
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
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Note 19 — Commitments and Contingencies
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 on
February 3, 2020. Pepco and Generation are 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 September 16, 2021. After completion and approval of the FS, DOEE will prepare a
Proposed Plan for public comment and then issue a ROD identifying any further response actions determined to be 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 Service 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. In April 2018, DOEE released a draft RI
report for public review and comment. Pepco submitted written comments on 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. On September 30, 2020, DOEE released its Interim ROD. The Interim ROD reflects an adaptive management approach
which will require 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 has concluded that incremental exposure remains reasonably possible, but management cannot reasonably estimate a range
of loss beyond the amounts recorded, which are included in the table above.
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. During the second quarter of 2018, Pepco became aware that the
Trustees are in the beginning stages of a 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 December 31, 2020 and 2019, Exelon and Generation recorded estimated liabilities of approximately $89 million and $83 million, respectively, in total for
asbestos-related bodily injury claims. As of December 31, 2020, approximately $25 million of this amount related to 261 open claims presented to
Generation, while the remaining $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
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Note 19 — Commitments and Contingencies
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.
Fund Transfer Restrictions (All Registrants). Under applicable law, Exelon may borrow or receive an extension of credit from its subsidiaries. Under the
terms of Exelon’s intercompany money pool agreement, Exelon can lend to, but not borrow from the money pool.
Under applicable law, Generation, ComEd, PECO, BGE, PHI, Pepco, DPL, and ACE can pay dividends only from retained, undistributed or current earnings.
A significant loss recorded at Generation, ComEd, PECO, BGE, PHI, Pepco, DPL, or ACE may limit the dividends that these companies can distribute to
Exelon.
ComEd has agreed in connection with financings arranged through ComEd Financing III that it will not declare dividends on any shares of its capital stock in
the event that: (1) it exercises its right to extend the interest payment periods on the subordinated debt securities issued to ComEd Financing III; (2) it
defaults on its guarantee of the payment of distributions on the preferred trust securities of ComEd Financing III; or (3) an event of default occurs under the
Indenture under which the subordinated debt securities are issued. No such event has occurred.
PECO has agreed in connection with financings arranged through PEC L.P. and PECO Trust IV that PECO will not declare dividends on any shares of its
capital stock in the event that: (1) it exercises its right to extend the interest payment periods on the subordinated debentures, which were issued to PEC L.P.
or PECO Trust IV; (2) it defaults on its guarantee of the payment of distributions on the Series D Preferred Securities of PEC L.P. or the preferred trust
securities of PECO Trust IV; or (3) an event of default occurs under the Indenture under which the subordinated debentures are issued. No such event has
occurred.
BGE is subject to restrictions established by the MDPSC that prohibit BGE from paying a dividend on its common shares if (a) after the dividend payment,
BGE’s equity ratio would be below 48% as calculated pursuant to the MDPSC’s ratemaking precedents or (b) BGE’s senior unsecured credit rating is rated
by two of the three major credit rating agencies below investment grade. No such event has occurred.
Pepco is subject to certain dividend restrictions established by settlements approved in Maryland and the District of Columbia. Pepco is prohibited from
paying a dividend on its common shares if (a) after the dividend payment, Pepco's equity ratio would be 48% as equity levels are calculated under the
ratemaking precedents of the MDPSC and DCPSC or (b) Pepco’s senior unsecured credit rating is rated by one of the three major credit rating agencies
below investment grade. No such event has occurred.
DPL is subject to certain dividend restrictions established by settlements approved in Delaware and Maryland. DPL is prohibited from paying a dividend on
its common shares if (a) after the dividend payment, DPL's equity ratio would be 48% as equity levels are calculated under the ratemaking precedents of the
DPSC and MDPSC or (b) DPL’s senior unsecured credit rating is rated by one of the three major credit rating agencies below investment grade. No such
event has occurred.
ACE is subject to certain dividend restrictions established by settlements approved in New Jersey. ACE is prohibited from paying a dividend on its common
shares if (a) after the dividend payment, ACE's equity ratio would be 48% as equity levels are calculated under the ratemaking precedents of the NJBPU or
(b) ACE's senior unsecured credit rating is rated by one of the three major credit rating agencies below investment grade. ACE is also subject to a dividend
restriction which requires ACE to obtain the prior approval of the NJBPU before dividends can be paid if its equity as a percent of its total capitalization,
excluding securitization debt, falls below 30%. No such events have occurred.
City of Everett Tax Increment Financing Agreement (Exelon 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
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Combined Notes to Consolidated Financial Statements
(Dollars in millions, except per share data unless otherwise noted)
Note 19 — Commitments and Contingencies
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 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.
Deferred Prosecution Agreement (DPA) and Related 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 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 U.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 expense in Exelon’s and ComEd’s Consolidated Statements of Operations and Comprehensive Income in the second quarter of 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 made equity contributions to ComEd of $200 million in 2020. On August 13, 2020, a motion was filed in the U.S. District Court for the
Northern District of Illinois by a ComEd customer and on behalf of ComEd customers seeking to enjoin ComEd from paying these funds to the U.S. Treasury
and requiring the U.S. government to establish a victims’ restitution fund from which the $200 million would be disbursed to ComEd customers. The motion
was denied without prejudice on November 6, 2020 and ComEd submitted the $200 million payment to the U.S. Treasury. On January 6, 2021, the customer
petitioned the Seventh Circuit for a writ of mandamus to seek review of the district court’s ruling, but on January 8, 2021, the Seventh Circuit denied the
petition. On January 22, 2021, the customer petitioned the Seventh Circuit for rehearing of its denial of his petition for a writ of mandamus. On February 5,
2021, the Seventh Circuit denied the petition for rehearing.
Exelon was not made a party to the DPA, and therefore the investigation by the USAO into Exelon’s activities ended 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 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.
Subsequent to Exelon announcing the receipt of the subpoenas, various lawsuits have been filed and various demand letters have been 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 against Exelon and certain officers of Exelon and ComEd was filed in federal court in December 2019 alleging
misrepresentations and omissions in Exelon’s SEC filings related to ComEd’s lobbying activities and the related investigations. The complaint was
amended on September 16, 2020, to dismiss two of the original defendants and add other defendants, including ComEd. Defendants filed a motion
to dismiss in November 2020. Briefing was completed on February 17, 2021.
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Combined Notes to Consolidated Financial Statements
(Dollars in millions, except per share data unless otherwise noted)
Note 19 — Commitments and Contingencies
•
•
•
•
A derivative shareholder lawsuit was filed against Exelon, its directors and certain officers of Exelon and ComEd in April 2020 alleging, among other
things, breaches of fiduciary duties also purporting to relate to matters that are the subject of the subpoenas and the SEC investigation. The plaintiff
voluntarily dismissed this derivative action without prejudice to refile on July 28, 2020.
Three putative class action lawsuits against ComEd and Exelon were filed in Illinois state court in the third quarter of 2020 seeking restitution and
compensatory damages on behalf of ComEd customers. These three state cases were consolidated into a single action in October of 2020. In
addition, on November 2, 2020, the Citizens Utility Board (CUB) filed a motion to intervene in the state 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 is ongoing.
Four putative class action lawsuits against ComEd and Exelon were filed in federal court in the third quarter of 2020 alleging, among other things,
civil violations of federal racketeering laws. In 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. On January 10, 2021, the Potter plaintiffs filed a motion asking the court to clarify that their
class action complaint against ComEd, Exelon and the individual named defendants remains in effect, notwithstanding the consolidated amended
complaint, and asked the court to stay the Potter case. On January 21, 2021, the court determined that the appointed lead counsel had sole
discretion to determine which parties to name as plaintiffs and defendants, and that the Potter plaintiffs have the option to opt-out of that class and
file a separate, individual action against the defendants named in their original complaint. The Potter plaintiffs have until March 23, 2021 to make
that decision.
Four shareholders sent letters to the Exelon Board of Directors in 2020 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 described in the DPA.
No loss contingencies have been reflected 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.
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 (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.
20. Shareholders' Equity (Exelon and Utility Registrants)
ComEd Common Stock Warrants
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Combined Notes to Consolidated Financial Statements
(Dollars in millions, except per share data unless otherwise noted)
Note 20 — Shareholders' Equity
The following table presents warrants outstanding to purchase ComEd common stock and shares of common stock reserved for the conversion of warrants.
The warrants entitle the holders to convert such warrants into common stock of ComEd at a conversion rate of one share of common stock for three
warrants.
Warrants outstanding
Common Stock reserved for conversion
Share Repurchases
December 31,
2020
2019
60,143
20,048
60,228
20,076
There currently is no Exelon Board of Director authority to repurchase shares. Any previous shares repurchased are held as treasury shares, at cost, unless
cancelled or reissued at the discretion of Exelon’s management.
Preferred and Preference Securities
The following table presents Exelon, ComEd, PECO, BGE, Pepco, and ACE's shares of preferred securities authorized, none of which were outstanding as
of December 31, 2020 and 2019. There are no shares of preferred securities authorized for DPL.
Exelon
ComEd
PECO
BGE
Pepco
(a)
ACE
Preferred Securities Authorized
100,000,000
850,000
15,000,000
1,000,000
6,000,000
2,799,979
__________
(a)
Includes 799,979 shares of cumulative preferred stock and 2,000,000 of no-par preferred stock as of December 31, 2020 and 2019.
The following table presents ComEd's, BGE's, and ACE's preference securities authorized, none of which were outstanding as of December 31, 2020 and
2019. There are no shares of preference securities authorized for Exelon, PECO, Pepco, and DPL.
ComEd
(a)
BGE
ACE
Preference Securities Authorized
6,810,451
6,500,000
3,000,000
__________
(a)
Includes 4,600,000 shares of unclassified preference securities and 1,900,000 shares of previously redeemed preference securities as of December 31, 2020 and 2019.
21. Stock-Based Compensation Plans (All Registrants)
Stock-Based Compensation Plans
Exelon grants stock-based awards through its LTIP, which primarily includes performance share awards, restricted stock units, and stock options. At
December 31, 2020, there were approximately 34 million shares authorized for issuance under the LTIP. For the years ended December 31, 2020, 2019, and
2018, exercised and distributed stock-based awards were primarily issued from authorized but unissued common stock shares.
The Registrants grant cash awards. The following table does not include expense related to these plans as they are not considered stock-based
compensation plans under the applicable authoritative guidance.
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Combined Notes to Consolidated Financial Statements
(Dollars in millions, except per share data unless otherwise noted)
Note 21 — Stock-Based Compensation Plans
The following table presents the stock-based compensation expense included in Exelon's and Generation's Consolidated Statements of Operations and
Comprehensive Income. The Utility Registrants' stock-based compensation expense for the years ended December 31, 2020, 2019, and 2018 was not
material.
Exelon
Total stock-based compensation expense included in operating and
maintenance expense
Income tax benefit
Total after-tax stock-based compensation expense
Generation
Total stock-based compensation expense included in operating and
maintenance expense
Income tax benefit
Total after-tax stock-based compensation expense
$
$
$
$
2020
2019
2018
Year Ended December 31,
64 $
(16)
48 $
27 $
(7)
20 $
77 $
(20)
57 $
37 $
(10)
27 $
208
(54)
154
77
(20)
57
Exelon receives a tax deduction based on the intrinsic value of the award on the exercise date for stock options and the distribution date for performance
share awards and restricted stock units. For each award, throughout the requisite service period, Exelon recognizes the tax benefit related to compensation
costs. The following table presents information regarding Exelon’s realized tax benefit when distributed:
Performance share awards
Restricted stock units
Performance Share Awards
2020
2019
2018
Year Ended December 31,
$
21 $
15
41 $
24
16
28
Performance share awards are granted under the LTIP. The performance share awards are settled 50% in common stock and 50% in cash at the end of the
three-year performance period, except for awards granted to vice presidents and higher officers that are settled 100% in cash if certain ownership
requirements are satisfied.
The common stock portion of the performance share awards is considered an equity award and is valued based on Exelon's stock price on the grant date.
The cash portion of the performance share awards is considered a liability award which is remeasured each reporting period based on Exelon’s current stock
price. As the value of the common stock and cash portions of the awards are based on Exelon’s stock price during the performance period, coupled with
changes in the total shareholder return modifier and expected payout of the award, the compensation costs are subject to volatility until payout is
established.
For nonretirement-eligible employees, stock-based compensation costs are recognized over the vesting period of three years using the straight-line method.
For performance share awards granted to retirement-eligible employees, the value of the performance shares is recognized ratably over the vesting period,
which is the year of grant.
Exelon processes forfeitures as they occur for employees who do not complete the requisite service period.
The following table summarizes Exelon’s nonvested performance share awards activity:
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Combined Notes to Consolidated Financial Statements
(Dollars in millions, except per share data unless otherwise noted)
Nonvested at December 31, 2019
(a)
Granted
Change in performance
Vested
Forfeited
Undistributed vested awards
(b)
Nonvested at December 31, 2020
(a)
Note 21 — Stock-Based Compensation Plans
Shares
Weighted Average
Grant Date Fair
Value (per share)
1,709,755 $
1,122,378
(751,309)
(747,551)
(67,964)
(334,917)
930,392 $
39.21
46.61
42.51
35.70
45.59
50.76
43.67
__________
(a) Excludes 1,414,661 and 2,017,870 of performance share awards issued to retirement-eligible employees as of December 31, 2020 and 2019, respectively, as they are fully
vested.
(b) Represents performance share awards that vested but were not distributed to retirement-eligible employees during 2020.
The following table summarizes the weighted average grant date fair value and the total fair value of performance share awards vested.
Weighted average grant date fair value (per share)
$
46.61 $
47.37 $
Total fair value of performance shares vested
Total fair value of performance shares settled in cash
39
63
158
131
38.15
61
49
__________
(a) As of December 31, 2020, $13 million of total unrecognized compensation costs related to nonvested performance shares are expected to be recognized over the
2020
(a)
2019
2018
Year Ended December 31,
remaining weighted-average period of 1.8 years.
Restricted Stock Units
Restricted stock units are granted under the LTIP with the majority being settled in a specific number of shares of common stock after the service condition
has been met. The corresponding cost of services is measured based on the grant date fair value of the restricted stock unit issued.
The value of the restricted stock units is expensed over the requisite service period using the straight-line method. The requisite service period for restricted
stock units is generally three to five years. However, certain restricted stock unit awards become fully vested upon the employee reaching retirement-
eligibility. The value of the restricted stock units granted to retirement-eligible employees is either recognized ratably over the first six months in the year of
grant if the employee reaches retirement eligibility prior to July 1st of the grant year or through the date of which the employee reaches retirement eligibility.
Exelon processes forfeitures as they occur for employees who do not complete the requisite service period.
The following table summarizes Exelon’s nonvested restricted stock unit activity:
Nonvested at December 31, 2019
(a)
Granted
Vested
Forfeited
Undistributed vested awards
(b)
Nonvested at December 31, 2020
(a)
Shares
Weighted Average
Grant Date Fair
Value (per share)
1,498,713 $
847,382
(725,151)
(52,046)
(454,768)
1,114,130 $
40.35
46.33
38.38
45.20
45.91
43.67
__________
(a) Excludes 748,165 and 863,196 of restricted stock units issued to retirement-eligible employees as of December 31, 2020 and 2019, respectively, as they are fully vested.
(b) Represents restricted stock units that vested but were not distributed to retirement-eligible employees during 2020.
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Combined Notes to Consolidated Financial Statements
(Dollars in millions, except per share data unless otherwise noted)
Note 21 — Stock-Based Compensation Plans
The following table summarizes the weighted average grant date fair value and the total fair value of restricted stock units vested.
Weighted average grant date fair value (per share)
Total fair value of restricted stock units vested
$
46.33 $
54
45.65 $
92
38.60
106
__________
(a) As of December 31, 2020, $23 million of total unrecognized compensation costs related to nonvested restricted stock units are expected to be recognized over the
2020
(a)
2019
2018
Year Ended December 31,
remaining weighted-average period of 2.3 years.
Stock Options
Non-qualified stock options to purchase shares of Exelon’s common stock were granted through 2012 under the LTIP. The exercise price of the stock options
is equal to the fair market value of the underlying stock on the date of option grant. Stock options will expire no later than ten years from the date of grant.
At December 31, 2020 all stock options were vested and there were no unrecognized compensation costs.
The following table presents information with respect to stock option activity:
Balance of shares outstanding at December 31, 2019
Options exercised
Options expired
Balance of shares outstanding at December 31, 2020
Exercisable at December 31, 2020
(a)
__________
(a)
Includes stock options issued to retirement eligible employees.
Weighted
Average
Exercise
Price
(per share)
Weighted
Average
Remaining
Contractual
Life
(years)
Aggregate
Intrinsic
Value
40.43
38.30
46.07
40.57
40.57
1.56 $
0.91 $
0.91 $
Shares
1,889,045 $
(475,827)
(147,808)
1,265,410 $
1,265,410 $
The following table summarizes additional information regarding stock options exercised:
Intrinsic value
(a)
Cash received for exercise price
2020
2019
2018
Year Ended December 31,
$
5 $
18
9 $
59
__________
(a) The difference between the market value on the date of exercise and the option exercise price.
352
10
5
3
3
12
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Combined Notes to Consolidated Financial Statements
(Dollars in millions, except per share data unless otherwise noted)
Note 22 — Changes in Accumulated Other Comprehensive Income
22. Changes in Accumulated Other Comprehensive Income (Exelon)
The following tables present changes in Exelon's AOCI, net of tax, by component:
Balance at December 31, 2017
OCI before reclassifications
Amounts reclassified from AOCI
Net current-period OCI
Impact of adoption of Recognition and
Measurement of Financial Assets and
Financial Liabilities standard
(c)
Balance at December 31, 2018
OCI before reclassifications
Amounts reclassified from AOCI
Net current-period OCI
Balance at December 31, 2019
OCI before reclassifications
Amounts reclassified from AOCI
Net current-period OCI
Balance at December 31, 2020
Gains and
(Losses) on
Cash Flow
Hedges
Unrealized
Gains and
(Losses) on
Marketable
Securities
Pension and
Non-Pension
Postretirement
Benefit Plan
Items
(a)
Foreign
Currency
Items
AOCI of Investments
Unconsolidated
Affiliates
(b)
Total
$
(14) $
10 $
(2,998) $
(23) $
(1) $
(3,026)
11
1
12
—
(2) $
—
—
—
—
—
—
(10)
— $
—
—
—
(143)
181
38
—
(10)
—
(10)
—
1
—
1
—
(141)
182
41
(10)
(2,960) $
(33) $
— $
(2,995)
(289)
84
(205)
6
—
6
(2)
2
—
(285)
86
(199)
(2) $
— $
(3,165) $
(27) $
— $
(3,194)
(3)
—
(3)
—
—
—
(357)
150
(207)
4
—
4
—
—
—
(356)
150
(206)
(5) $
— $
(3,372) $
(23) $
— $
(3,400)
$
$
$
__________
(a) This AOCI component is included in the computation of net periodic pension and OPEB cost. See Note 15 — 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.
(c) Exelon adopted the new standard Recognition and Measurement of Financial Assets and Financial Liabilities. The standard was adopted as of January 1, 2018, which
resulted in an increase to Retained earnings and Accumulated other comprehensive loss of $10 million for Exelon. The amounts reclassified related to Rabbi Trusts.
The following table presents income tax benefit (expense) allocated to each component of Exelon's other comprehensive income (loss):
Pension and non-pension postretirement benefit plans:
Prior service benefit reclassified to periodic benefit cost
Actuarial loss reclassified to periodic benefit cost
Pension and non-pension postretirement benefit plans valuation adjustment
23. Variable Interest Entities (Exelon, Generation, PHI, and ACE)
For the Year Ended December 31,
2020
2019
2018
$
16 $
(66)
122
23 $
(52)
100
24
(86)
50
At December 31, 2020 and 2019, 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.
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Consolidated VIEs
Combined Notes to Consolidated Financial Statements
(Dollars in millions, except per share data unless otherwise noted)
Note 23 — Variable Interest Entities
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 December 31, 2020 and 2019. 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 footnotes to the table below, are such that creditors, or beneficiaries, do
not have recourse to the general credit of Exelon, Generation, PHI, and ACE.
December 31, 2020
December 31, 2019
Exelon
Generation
PHI
(a)
ACE
Exelon
Generation
PHI
(a)
ACE
Cash and cash equivalents
$
Restricted cash and cash equivalents
98 $
47
Accounts receivable
Customer
Other
Unamortized energy contract assets
Inventories, net
Materials and supplies
Assets held for sale
(b)
Other current assets
Total current assets
Property, plant and equipment, net
Nuclear decommissioning trust funds
Unamortized energy contract assets
Other noncurrent assets
Total noncurrent assets
Total assets
(c)
Long-term debt due within one year
Accounts payable
Accrued expenses
Unamortized energy contract liabilities
Liabilities held for sale
(b)
Other current liabilities
Total current liabilities
Long-term debt
Asset retirement obligations
Unamortized energy contract liabilities
Other noncurrent liabilities
Total noncurrent liabilities
Total liabilities
(d)
98 $
— $
— $
163 $
163 $
— $
44
148
36
22
244
101
669
1,362
5,803
3,007
249
42
9,101
3
—
—
—
—
—
5
8
—
—
—
10
10
3
—
—
—
—
—
—
3
—
—
—
10
10
88
151
39
23
227
—
32
723
6,022
2,741
250
89
9,102
85
151
39
23
227
—
31
719
6,022
2,741
250
73
9,086
3
—
—
—
—
—
1
4
—
—
—
16
16
148
36
22
244
101
674
1,370
5,803
3,007
249
52
9,111
$
$
10,481 $
10,463 $
18 $
13 $
9,825 $
9,805 $
20 $
94 $
68 $
26 $
21 $
544 $
523 $
21 $
81
70
4
16
5
270
889
2,318
—
129
3,336
81
70
4
16
5
244
889
2,318
—
129
3,336
—
—
—
—
—
26
—
—
—
—
—
—
—
—
—
—
21
—
—
—
—
—
106
70
8
—
3
731
527
2,128
1
89
2,745
106
70
8
—
3
710
504
2,128
1
89
2,722
—
—
—
—
—
21
23
—
—
—
23
$
3,606 $
3,580 $
26 $
21 $
3,476 $
3,432 $
44 $
—
3
—
—
—
—
—
—
3
—
—
—
14
14
17
20
—
—
—
—
—
20
21
—
—
—
21
41
__________
(a)
(b) Generation entered into an agreement for the sale of a significant portion of Generation's solar business. As a result of this transaction, in the fourth quarter of 2020, Exelon
Includes certain purchase accounting adjustments from the PHI merger not pushed down to ACE.
and Generation reclassified the consolidated VIEs' solar assets and
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Combined Notes to Consolidated Financial Statements
(Dollars in millions, except per share data unless otherwise noted)
Note 23 — Variable Interest Entities
liabilities as held for sale. Refer to Note 2 — Mergers, Acquisitions, and Dispositions for additional information on the sale of the solar business.
(c) Exelon's and Generation's balances include unrestricted assets for current unamortized energy contract assets of $22 million and $23 million, Property, plant, and
equipment of $1 million and $20 million, non-current unamortized energy contract assets of $249 million and $250 million, and Assets held for sale of $9 million and
$0 million as of December 31, 2020 and 2019, respectively.
(d) Exelon's and Generation's balances include liabilities with recourse of $8 million and $3 million as of December 31, 2020 and 2019, respectively.
As of December 31, 2020 and 2019, 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.
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.
Bluestem Wind Energy Holdings, LLC - A Tax Equity structure
which is consolidated by EGRP. Generation is a minority
interest holder.
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.
Generation conducts the operational activities.
Generation conducts the operational activities.
The PPA contract absorbs variability through a performance
guarantee.
Generation conducts all activities.
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.
Equity capitalization is insufficient to support its operations.
Generation conducts all 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.
Equity investment in distributed energy company - Generation
has a 31% equity ownership. This distributed energy company
has an interest in an unconsolidated VIE. (See
Unconsolidated VIEs disclosure below).
Generation fully impaired this investment in the third quarter of
2019. Refer to Note 12 — Asset Impairments for additional
information.
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. Refer to Note 6 —Accounts
Receivable for additional information on the sale of
receivables.
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. 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. Refer to Note 2 — Mergers,
Acquisitions, and Dispositions for additional information.
Exelon and Generation, where indicated, provide the following support to CENG:
355
Table of Contents
Combined Notes to Consolidated Financial Statements
(Dollars in millions, except per share data unless otherwise noted)
Note 23 — Variable Interest Entities
•
•
•
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 19 — Commitments and Contingencies for more details,
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 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. There is limited recourse to Generation related to certain solar and wind entities.
In 2017, Generation’s interests in EGRP were contributed to and are pledged for the EGR IV non-recourse debt project financing structure. Refer to Note 17
— Debt and Credit Agreements for additional information.
As of December 31, 2020 and 2019, 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.
Unconsolidated VIEs
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.
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 December 31, 2020 and 2019, 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.
356
Table of Contents
Combined Notes to Consolidated Financial Statements
(Dollars in millions, except per share data unless otherwise noted)
Note 23 — Variable Interest Entities
The following table presents summary information about Exelon's and Generation’s significant unconsolidated VIE entities:
Total assets
(a)
Total liabilities
(a)
Exelon's ownership interest in VIE
(a)
Other ownership interests in VIE
(a)
December 31, 2020
December 31, 2019
Commercial
Agreement
VIEs
Equity
Investment
VIEs
Total
Commercial
Agreement
VIEs
Equity
Investment
VIEs
Total
$
777 $
401 $
1,178 $
636 $
443 $
1,079
61
—
716
223
157
21
284
157
737
33
—
604
227
191
25
260
191
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 December 31, 2020 and 2019.
As of December 31, 2020 and 2019, 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. Refer
to Note 12 — Asset Impairments 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.
357
Table of Contents
Combined Notes to Consolidated Financial Statements
(Dollars in millions, except per share data unless otherwise noted)
Note 24 — Supplemental Financial Information
24. 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.
Exelon
Generation
ComEd
PECO
BGE
PHI
Pepco
DPL
ACE
Taxes other than income taxes
For the year ended December 31, 2020
Utility
(a)
Property
Payroll
For the year ended December 31, 2019
(a)
Utility
Property
Payroll
For the year ended December 31, 2018
(a)
Utility
Property
Payroll
$
$
$
$
$
$
859
602
235
881
595
232
919
557
247
265
113
112
274
115
114
273
130
99
$
238
$
135
$
87
$
30
27
16
16
164
17
$
242
$
132
$
90
$
29
27
17
15
153
17
299
126
25
304
122
24
$
275
$
84
7
$
286
$
85
7
$
243
$
131
$
94
$
337
$
316
$
30
27
15
16
143
17
94
24
58
5
$
$
$
21
39
5
18
34
4
21
32
3
3
3
3
—
2
2
—
3
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.
358
Table of Contents
Combined Notes to Consolidated Financial Statements
(Dollars in millions, except per share data unless otherwise noted)
Note 24 — Supplemental Financial Information
Exelon
Generation
ComEd
PECO
BGE
PHI
Pepco
DPL
ACE
Other, Net
For the year ended December 31, 2020
Decommissioning-related activities:
Net realized income on NDT funds
Regulatory Agreement Units
(a)
Non-regulatory Agreement Units
Net unrealized gains on NDT funds
Regulatory Agreement Units
Non-regulatory Agreement Units
Regulatory offset to NDT fund-related activities
(b)
Decommissioning-related activities
AFUDC—Equity
Non-service net periodic benefit cost
Unrealized gains from equity investments
(c)
For the year ended December 31, 2019
Decommissioning-related activities:
Net realized income on NDT funds
Regulatory Agreement Units
(a)
Non-regulatory Agreement Units
Net unrealized gains on NDT funds
Regulatory Agreement Units
Non-regulatory Agreement Units
Regulatory offset to NDT fund-related activities
(b)
Decommissioning-related activities
AFUDC—Equity
Non-service net periodic benefit cost
For the year ended December 31, 2018
Decommissioning-related activities:
Net realized income on NDT funds
Regulatory Agreement Units
(a)
Non-regulatory Agreement Units
Net unrealized losses on NDT funds
Regulatory Agreement Units
Non-regulatory Agreement Units
Regulatory offset to NDT fund-related activities
(b)
Decommissioning-related activities
AFUDC—Equity
Non-service net periodic benefit cost
$
$
185
160
$
185
160
724
391
(729)
731
104
53
186
724
391
(729)
731
—
—
186
$
$
297
363
$
297
363
795
411
(876)
990
85
13
795
411
(876)
990
—
—
$
$
506
302
$
506
302
(715)
(483)
171
(219)
69
(47)
(715)
(483)
171
(219)
—
—
$
$
$
—
—
—
—
—
—
29
—
—
—
—
—
—
—
—
17
—
—
—
—
—
—
—
19
—
$
$
$
—
—
—
—
—
—
17
—
—
—
—
—
—
—
—
13
—
—
—
—
—
—
—
7
—
$
$
$
—
—
—
—
—
—
22
—
—
—
—
—
—
—
—
21
—
—
—
—
—
—
—
18
—
$
$
$
—
—
—
—
—
—
36
—
—
—
—
—
—
—
—
34
—
—
—
—
—
—
—
25
—
$
$
$
—
—
—
—
—
—
28
—
—
—
—
—
—
—
—
25
—
—
—
—
—
—
—
22
—
$
$
$
—
—
—
—
—
—
4
—
—
—
—
—
—
—
—
4
—
—
—
—
—
—
—
2
—
—
—
—
—
—
—
4
—
—
—
—
—
—
—
—
5
—
—
—
—
—
—
—
1
—
__________
(a) Realized income includes interest, dividends, and realized gains and losses on sales of NDT fund investments.
359
Table of Contents
Combined Notes to Consolidated Financial Statements
(Dollars in millions, except per share data unless otherwise noted)
Note 24 — Supplemental Financial Information
(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 10 — Asset Retirement Obligations for additional information regarding the accounting for nuclear decommissioning.
(c) Unrealized gains resulting from equity investments without readily determinable fair values that became publicly traded entities in the fourth quarter of 2020 and were fair
valued based on quoted market prices of the stocks as of December 31, 2020.
Supplemental Cash Flow Information
The following tables provide additional information about material items recorded in the Registrants' Consolidated Statements of Cash Flows.
Exelon
Generation
ComEd
PECO
BGE
PHI
Pepco
DPL
ACE
Depreciation, amortization, and accretion
For the year ended December 31, 2020
Property, plant, and equipment
(a)
Amortization of regulatory assets
(a)
Amortization of intangible assets, net
Amortization of energy contract assets and
liabilities
(b)
(a)
Nuclear fuel
(c)
(d)
ARO accretion
Total depreciation, amortization, and accretion $
$
4,364
$
2,070
$
588
62
30
983
500
—
53
30
983
500
922
211
—
—
—
—
$
319
$
28
—
—
—
—
$
397
153
$
586
196
—
—
—
—
—
—
—
—
257
120
—
—
—
—
$
155
$
140
36
—
—
—
—
40
—
—
—
—
6,527
$
3,636
$
1,133
$
347
$
550
$
782
$
377
$
191
$
180
For the year ended December 31, 2019
Property, plant, and equipment
(a)
Amortization of regulatory assets
(a)
Amortization of intangible assets, net
Amortization of energy contract assets and
liabilities
(b)
(a)
Nuclear fuel
(c)
(d)
ARO accretion
Total depreciation, amortization, and accretion $
$
3,665
$
1,485
$
528
59
21
1,016
491
—
50
21
1,016
491
886
147
—
—
—
—
$
303
$
30
—
—
—
—
$
359
143
$
547
207
—
—
—
—
—
—
—
—
239
135
—
—
—
—
$
146
$
123
38
—
—
—
—
34
—
—
—
—
5,780
$
3,063
$
1,033
$
333
$
502
$
754
$
374
$
184
$
157
For the year ended December 31, 2018
Property, plant, and equipment
(a)
Amortization of regulatory assets
(a)
Amortization of intangible assets, net
Amortization of energy contract assets and
liabilities
(b)
(a)
Nuclear fuel
(c)
(d)
ARO accretion
Total depreciation, amortization, and accretion $
$
3,740
$
1,748
$
555
58
14
1,115
489
—
49
14
1,115
489
820
120
—
—
—
—
$
274
$
27
—
—
—
—
$
335
148
$
480
260
—
—
—
—
—
—
—
—
218
167
—
—
—
—
$
131
$
51
—
—
—
—
94
42
—
—
—
—
5,971
$
3,415
$
940
$
301
$
483
$
740
$
385
$
182
$
136
__________
(a)
(b)
(c)
Included in Depreciation and amortization in the Registrants' Consolidated Statements of Operations and Comprehensive Income.
Included in Operating revenues or Purchased power and fuel expense in the Registrants’ Consolidated Statements of Operations and Comprehensive Income.
Included in Purchased power and fuel expense in the Registrants’ Consolidated Statements of Operations and Comprehensive Income.
360
Table of Contents
Combined Notes to Consolidated Financial Statements
(Dollars in millions, except per share data unless otherwise noted)
Note 24 — Supplemental Financial Information
(d)
Included in Operating and maintenance expense in the Registrants’ Consolidated Statements of Operations and Comprehensive Income.
Exelon
Generation
ComEd
PECO
BGE
PHI
Pepco
DPL
ACE
Cash paid (refunded) during the year:
For the year ended December 31, 2020
Interest (net of amount capitalized)
Income taxes (net of refunds)
For the year ended December 31, 2019
Interest (net of amount capitalized)
Income taxes (net of refunds)
For the year ended December 31, 2018
Interest (net of amount capitalized)
Income taxes (net of refunds)
$
$
$
1,521
$
10
1,470
$
265
$
1,421
95
$
$
$
371
(61)
343
(42)
332
(153)
$
144
(37)
125
(57)
$
257
$
129
$
46
40
129
$
106
$
255
$
130
$
82
$
125
(2)
17
94
14
29
7
$
$
250
(32)
$
123
41
$
$
$
61
12
59
19
56
(6)
57
(3)
55
(5)
61
(12)
331
$
70
$
$
373
(44)
369
746
361
Table of Contents
Combined Notes to Consolidated Financial Statements
(Dollars in millions, except per share data unless otherwise noted)
Note 24 — Supplemental Financial Information
Exelon
Generation
ComEd
PECO
BGE
PHI
Pepco
DPL
ACE
Other non-cash operating activities:
For the year ended December 31, 2020
Pension and non-pension postretirement benefit
costs
$
Allowance for credit losses
Other decommissioning-related activity
(a)
Energy-related options
True-up adjustments to decoupling mechanisms
and formula rates
(c)
(b)
Severance costs
Provision for excess and obsolete inventory
Long-term incentive plan
Amortization of operating ROU asset
Asset impairments
AFUDC - Equity
For the year ended December 31, 2019
Pension and non-pension postretirement benefit
costs
$
Allowance for credit losses
Other decommissioning-related activity
(a)
Energy-related options
True-up adjustments to decoupling mechanisms
and formula rates
(d)
(b)
Long-term incentive plan
Amortization of operating ROU asset
Change in environmental liabilities
AFUDC - Equity
For the year ended December 31, 2018
Pension and non-pension postretirement benefit
costs
$
(a)
(b)
Allowance for credit losses
Other decommissioning-related activity
Energy-related options
True-up adjustments to decoupling mechanisms
and formula rates
Asset retirement costs
Long-term incentive plan
AFUDC - Equity
(d)
411
150
(659)
104
(6)
105
131
56
222
—
(104)
438
120
(506)
22
124
10
244
23
(85)
583
159
(2)
10
49
20
140
(69)
$
115
$
114
$
5
$
17
(659)
104
—
90
128
—
155
—
—
32
—
—
47
1
2
—
2
15
42
—
—
(16)
1
1
—
1
—
(29)
(17)
$
12
31
—
—
—
—
—
—
$
135
$
31
(506)
22
—
—
172
—
—
204
48
(2)
10
—
—
—
—
$
$
$
$
96
33
—
—
128
—
3
—
(17)
177
40
—
—
28
—
—
(19)
$
$
62
15
—
—
(16)
—
—
—
31
—
(22)
61
8
—
—
—
—
30
—
$
$
70
43
—
—
(21)
—
—
—
28
13
(36)
95
17
—
—
(4)
—
33
23
15
24
—
—
(40)
—
—
—
7
—
(28)
25
7
—
—
(4)
—
8
23
(13)
(21)
(34)
(25)
$
18
33
—
—
—
—
—
(7)
$
59
10
—
—
—
—
—
(18)
$
67
28
—
—
21
20
—
(25)
15
11
—
—
21
22
—
(22)
$
7
$
16
—
—
7
—
—
—
8
7
(4)
15
4
—
—
—
—
8
—
(4)
6
6
—
—
—
(1)
—
(2)
$
$
$
$
14
2
—
—
12
—
—
—
3
6
(4)
16
5
—
—
—
—
4
—
(5)
12
11
—
—
—
(1)
—
(1)
__________
(a)
Includes the elimination of decommissioning-related activities for the Regulatory Agreement Units, including the elimination of operating revenues, ARO updates and
accretion, ARC amortization, investment income, and income taxes related to all NDT fund activity for these units. See Note 10 — Asset Retirement Obligations for
additional information regarding the accounting for nuclear decommissioning.
Includes option premiums reclassified to realized at the settlement of the underlying contracts and recorded to results of operations.
(b)
362
Table of Contents
Combined Notes to Consolidated Financial Statements
(Dollars in millions, except per share data unless otherwise noted)
Note 24 — Supplemental Financial Information
(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) 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 3 — Regulatory Matters for additional information.
The following tables provide a reconciliation of cash, restricted cash, and cash equivalents reported within the Registrants' Consolidated Balance Sheets that
sum to the total of the same amounts in their Consolidated Statements of Cash Flows.
December 31, 2020
Cash and cash equivalents
Restricted cash and cash equivalents
Restricted cash included in other long-
term assets
Cash, restricted cash, and cash
equivalents - Held for Sale
Total cash, restricted cash, and cash
equivalents
December 31, 2019
Cash and cash equivalents
Restricted cash and cash equivalents
Restricted cash included in other long-
term assets
Total cash, restricted cash, and cash
equivalents
December 31, 2018
Cash and cash equivalents
Restricted cash and cash equivalents
Restricted cash included in other long-
term assets
Total cash, restricted cash, and cash
equivalents
December 31, 2017
Cash and cash equivalents
Restricted cash and cash equivalents
Restricted cash included in other long-
term assets
Total cash, restricted cash, and cash
equivalents
Exelon
Generation
ComEd
PECO
BGE
PHI
Pepco
DPL
ACE
$
$
$
$
$
$
$
$
663
438
53
12
226
$
83
$
19
$
144
$
111
$
89
—
12
279
43
—
7
—
—
1
—
—
39
10
—
$
30
35
—
—
$
15
—
—
—
1,166
$
327
$
405
$
26
$
145
$
160
$
65
$
15
$
$
587
358
177
303
146
—
$
90
$
21
$
24
$
131
$
150
163
6
—
1
—
36
14
$
30
33
—
$
13
—
—
1,122
$
449
$
403
$
27
$
25
$
181
$
63
$
13
$
1,349
$
247
185
750
153
—
$
135
$
130
$
29
166
5
—
7
6
—
$
124
$
43
19
16
37
—
$
23
$
1
—
1,781
$
903
$
330
$
135
$
13
$
186
$
53
$
24
$
$
898
207
85
416
138
—
$
76
$
271
$
17
$
5
63
4
—
1
—
30
42
23
$
5
$
35
—
$
2
—
—
$
1,190
$
554
$
144
$
275
$
18
$
95
$
40
$
2
$
17
3
10
—
30
12
2
14
28
7
4
19
30
2
6
23
31
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Combined Notes to Consolidated Financial Statements
(Dollars in millions, except per share data unless otherwise noted)
Note 24 — Supplemental Financial Information
Supplemental Balance Sheet Information
The following tables provide additional information about material items recorded in the Registrants' Consolidated Balance Sheets.
Exelon
Generation
ComEd
PECO
BGE
PHI
Pepco
DPL
ACE
Investments
December 31, 2020
Equity method investments:
Other equity method investments
$
81
$
65
$
6
$
8
$
—
$
—
$
—
$
—
$
—
Other investments:
Employee benefit trusts and
(a)
investments
Equity investments without readily
determinable fair values
Other available for sale debt security
investments
283
73
3
61
55
3
—
—
—
Total investments
$
440
$
184
$
6
$
22
—
—
30
$
10
—
—
10
140
115
—
—
—
—
$
140
$
115
$
—
—
—
—
$
—
—
—
—
December 31, 2019
Equity method investments:
Other equity method investments
$
92
$
71
$
6
$
8
$
—
$
—
$
—
$
—
$
—
Other investments:
Employee benefit trusts and
(a)
investments
Equity investments without readily
determinable fair values
Other available for sale debt security
investments
262
69
41
54
69
41
—
—
—
Total investments
$
464
$
235
$
6
$
__________
(a) The Registrants’ debt and equity security investments are recorded at fair market value.
19
—
—
27
7
—
—
135
110
—
—
—
—
$
7
$
135
$
110
$
—
—
—
—
$
Exelon
Generation
ComEd
PECO
BGE
PHI
Pepco
DPL
ACE
Accrued expenses
December 31, 2020
Compensation-related accruals
Taxes accrued
(a)
Interest accrued
December 31, 2019
Compensation-related accruals
Taxes accrued
(a)
Interest accrued
$
1,069
$
527
331
$
1,052
$
414
337
$
$
426
229
44
422
222
65
170
$
94
109
$
73
16
37
171
$
58
$
83
110
3
37
$
$
84
73
46
78
26
46
$
$
109
117
51
101
117
49
$
$
36
90
26
28
90
23
$
$
18
18
7
19
14
8
__________
(a) Primarily includes accrued payroll, bonuses and other incentives, vacation, and benefits.
—
—
—
—
17
12
12
15
8
12
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Combined Notes to Consolidated Financial Statements
(Dollars in millions, except per share data unless otherwise noted)
Note 25 — Related Party Transactions
25. 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:
Operating revenues from affiliates:
(a)(b)
ComEd
(c)
PECO
(d)
BGE
PHI
(e)
Pepco
(f)
DPL
ACE
(g)
Other
Total operating revenues from affiliates (Generation)
For the Years Ended
December 31,
2020
2019
2018
330 $
369 $
190
315
367
279
75
13
9
158
289
353
264
70
19
3
523
128
260
355
206
120
29
2
1,211 $
1,172 $
1,268
$
$
__________
(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 2020, ComEd’s Purchased power from Generation of $345 million is recorded as Operating revenues from ComEd of $330 million and Purchased power and fuel from
ComEd of $15 million at Generation. For 2019, ComEd’s Purchased power from Generation of $376 million is recorded as Operating revenues from ComEd of $369 million
and Purchased power and fuel from ComEd of $7 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.
(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 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 affiliates
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.
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Combined Notes to Consolidated Financial Statements
(Dollars in millions, except per share data unless otherwise noted)
Note 25 — Related Party Transactions
The following table presents the service company costs allocated to the Registrants:
Exelon
BSC
PHISCO
Generation
BSC
ComEd
BSC
PECO
BSC
BGE
BSC
PHI
BSC
PHISCO
Pepco
BSC
PHISCO
DPL
BSC
PHISCO
ACE
BSC
PHISCO
Operating and maintenance from affiliates
Capitalized costs
For the years ended December 31,
For the years ended December 31,
2020
2019
2018
2020
2019
2018
$
585 $
516 $
$
552 $
570 $
652
283
150
170
152
—
85
120
54
97
45
87
263
149
157
139
—
85
124
52
100
42
90
265
146
157
147
—
89
137
51
111
42
98
61
54
186
76
132
149
61
55
27
51
18
40
16
72
66
148
88
126
88
72
38
33
25
20
19
19
448
79
67
135
64
79
102
79
40
32
28
25
20
21
Current Receivables from/Payables to affiliates
The following tables present current receivables from affiliates and current payables to affiliates:
December 31, 2020
Payables to
affiliates:
Generation
ComEd
PECO
BGE
PHI
Pepco
DPL
ACE
Other
Total
$
$
Generation
ComEd
PECO
BGE
Pepco
DPL
ACE
BSC
PHISCO
Other
Total
Receivables from affiliates:
(a)
78
17
11
—
13
3
6
25
153
$
13 $
— $
— $
— $ — $
— $
72 $
— $
22 $
1
—
—
2
1
—
5
—
—
—
—
—
—
2
—
—
—
1
—
—
2
—
—
—
—
—
—
2
—
—
—
—
—
—
1
—
—
—
—
—
—
6
59
28
47
4
25
21
15
—
—
—
—
—
14
10
9
—
9
4
3
11
—
1
1
107
146
50
61
15
55
36
31
43
$
22 $
2 $
3 $
2 $
1 $
6 $
271 $
33 $
51 $
544
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Table of Contents
December 31, 2019
Combined Notes to Consolidated Financial Statements
(Dollars in millions, except per share data unless otherwise noted)
Note 25 — Related Party Transactions
Payables to affiliates:
Generation
ComEd
PECO
BGE
ACE
BSC
PHISCO
Other
Total
Receivables from affiliates:
Generation
ComEd
PECO
BGE
PHI
Pepco
DPL
ACE
Other
Total
$
27 $
— $
— $
— $
67 $
— $
23 $
$
(a)
78
27
28
—
34
7
7
9
—
—
—
—
—
—
1
—
—
—
—
—
—
1
—
—
—
—
—
—
1
—
—
—
—
—
3
1
54
25
34
4
16
10
7
—
—
—
—
—
15
11
10
—
8
3
4
10
1
1
1
117
140
55
66
14
66
32
25
13
$
190
$
28 $
1 $
1 $
4 $
217 $
36 $
51 $
528
__________
(a) At December 31, 2020 and 2019, Generation also had a contract liability with ComEd for $50 million and $37 million, respectively, that was included in Other liabilities on
Generation’s Consolidated Balance Sheets. At December 31, 2020 and 2019, ComEd had a Current Payable to Generation of $28 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
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 10 — Asset Retirement Obligations for additional information.
The following table presents noncurrent receivables from affiliates at ComEd and PECO which are recorded as noncurrent payables to affiliates at
Generation:
ComEd
PECO
Long-term debt to financing trusts
The following table presents Long-term debt to financing trusts:
ComEd Financing III
PECO Trust III
PECO Trust IV
Total
Long-term debt to affiliates
December 31,
2020
2019
$
2,541 $
475
2,622
480
Exelon
2020
ComEd
As of December 31,
PECO
Exelon
2019
ComEd
PECO
$
$
206 $
205 $
— $
206 $
205 $
81
103
—
—
81
103
81
103
—
—
390 $
205 $
184 $
390 $
205 $
—
81
103
184
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Combined Notes to Consolidated Financial Statements
(Dollars in millions, except per share data unless otherwise noted)
Note 25 — Related Party Transactions
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.
26. Subsequent Events (Exelon and Generation)
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. Under the separation plan, Exelon shareholders will retain their current shares of Exelon stock and receive a pro-rata distribution of shares of the
new company’s stock in a transaction that is expected to be tax-free to Exelon and its shareholders 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 separation in the first quarter of 2022, subject to final approval by Exelon’s Board of Directors, a Form 10 registration
statement being declared effective by the SEC, regulatory approvals, and satisfaction of other conditions. The 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. There can be no assurance that any
separation transaction will ultimately occur or, if one does occur, of its terms or timing.
Impacts of February 2021 Weather Events and Texas-based Generating Assets Outages
Beginning on February 15, 2021, Generation’s Texas-based generating assets within the ERCOT market, specifically Colorado Bend II, Wolf Hollow II, and
Handley, experienced periodic outages as a result of historically severe cold weather conditions. In addition, those weather conditions drove increased
demand for service, limited the availability of natural gas to fuel power plants, 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, ERCOT implemented load reductions to
maintain the reliability of the grid and required the use of an administrative price cap of $9,000 per megawatt hour during load shedding events.
Exelon and Generation estimate the impact to their Net income for the first quarter of 2021 arising from these market and weather conditions to be
approximately $560 million to $710 million. The estimated impact includes favorable results in certain regions within Generation’s wholesale gas business.
The ultimate impact to Exelon’s and Generation’s consolidated financial statements may be affected by a number of factors, including final settlement data,
the impacts of customer and counterparty credit losses, any state sponsored solutions to address the financial challenges caused by the event, and litigation
and contract disputes which may result.
Generation used a combination of commercial paper and letters of credit to manage collateral needs and has posted approximately $1.4 billion of collateral
with ERCOT as of February 22, 2021. Generation continues to believe it has sufficient cash on hand and available capacity on its revolver, which was $2.4
billion as of February 22, 2021, to meet its liquidity requirements.
ITEM 9.
CHANGES IN AND DISAGREEMENTS WITH ACCOUNTANTS ON ACCOUNTING AND FINANCIAL DISCLOSURE
All Registrants
None.
ITEM 9A.
CONTROLS AND PROCEDURES
All Registrants—Disclosure Controls and Procedures
During the fourth quarter of 2020, each registrant’s management, including its principal executive officer and principal financial officer, evaluated the
effectiveness of that registrant’s disclosure controls and procedures
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related to the recording, processing, summarizing, and reporting of information in that registrant’s periodic reports that it files with the SEC. These disclosure
controls and procedures have been designed by each registrant to ensure that (a) information relating to that registrant, including its consolidated
subsidiaries, that is required to be included in filings under the Securities Exchange Act of 1934, is accumulated and made known to that registrant’s
management, including its principal executive officer and principal financial officer, by other employees of that registrant and its subsidiaries as appropriate to
allow timely decisions regarding required disclosure, and (b) this information is recorded, processed, summarized, evaluated, and reported, as applicable,
within the time periods specified in the SEC’s rules and forms. Due to the inherent limitations of control systems, not all misstatements may be detected.
These inherent limitations include the realities that judgments in decision-making can be faulty and that breakdowns can occur because of simple error or
mistake. Additionally, controls could be circumvented by the individual acts of some persons or by collusion of two or more people.
Accordingly, as of December 31, 2020, the principal executive officer and principal financial officer of each registrant concluded that such registrant’s
disclosure controls and procedures were effective to accomplish their objectives.
All Registrants—Changes in Internal Control Over Financial Reporting
Each registrant continually strives to improve its disclosure controls and procedures to enhance the quality of its financial reporting and to maintain dynamic
systems that change as conditions warrant. However, there have been no changes in internal control over financial reporting that occurred during the fourth
quarter of 2020 that have materially affected, or are reasonably likely to materially affect, any of the Registrant's internal control over financial reporting,
including no changes resulting from COVID-19. See ITEM 7. MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS
OF OPERATIONS - Executive Overview for additional information on COVID-19.
All Registrants—Internal Control Over Financial Reporting
Management is required to assess and report on the effectiveness of its internal control over financial reporting as of December 31, 2020. As a result of that
assessment, management determined that there were no material weaknesses as of December 31, 2020 and, therefore, concluded that each registrant’s
internal control over financial reporting was effective. Management’s Report on Internal Control Over Financial Reporting is included in ITEM 8. FINANCIAL
STATEMENTS AND SUPPLEMENTARY DATA.
ITEM 9B.
OTHER INFORMATION
All Registrants
On February 22, 2021, ComEd adopted Amended and Restated Bylaws to amend the standard for independent directors.
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Exelon Generation Company, LLC, PECO Energy Company, Baltimore Gas and Electric Company, Pepco Holdings LLC, Potomac Electric Power Company,
Delmarva Power & Light Company, and Atlantic City Electric Company meet the conditions set forth in General Instruction I(1)(a) and (b) of Form 10-K for a
reduced disclosure format. Accordingly, all items in this section relating to Generation, PECO, BGE, PHI, Pepco, DPL, and ACE are not presented.
PART III
ITEM 10.
DIRECTORS, EXECUTIVE OFFICERS, AND CORPORATE GOVERNANCE
Executive Officers
The information required by ITEM 10 relating to executive officers is set forth above in ITEM 1. BUSINESS—Executive officers of the Registrants at
February 24, 2021.
Directors, Director Nomination Process and Audit Committee
The information required under ITEM 10 concerning directors and nominees for election as directors at the annual meeting of shareholders (Item 401 of
Regulation S-K), the director nomination process (Item 407(c)(3)), the audit committee (Item 407(d)(4) and (d)(5)), and the beneficial reporting compliance
(Sec. 16(a)) is incorporated herein by reference to information to be contained in Exelon’s definitive 2021 proxy statement (2021 Exelon Proxy Statement)
and the ComEd information statement (2021 ComEd Information Statement) to be filed with the SEC on or before April 30, 2021 pursuant to Regulation 14A
or 14C, as applicable, under the Securities Exchange Act of 1934.
Code of Ethics
Exelon’s Code of Business Conduct is the code of ethics that applies to Exelon’s and ComEd’s Chief Executive Officer, Chief Financial Officer, Corporate
Controller, and other finance organization employees. The Code of Business Conduct is filed as Exhibit 14 to this report and is available on Exelon’s website
at www.exeloncorp.com. The Code of Business Conduct will be made available, without charge, in print to any shareholder who requests such document
from Carter C. Culver, Senior Vice President and Deputy General Counsel, Exelon Corporation, P.O. Box 805398, Chicago, Illinois 60680-5398.
If any substantive amendments to the Code of Business Conduct are made or any waivers are granted, including any implicit waiver, from a provision of the
Code of Business Conduct, to its Chief Executive Officer, Chief Financial Officer or Corporate Controller, Exelon will disclose the nature of such amendment
or waiver on Exelon’s website, www.exeloncorp.com, or in a report on Form 8-K.
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ITEM 11.
EXECUTIVE COMPENSATION
The information required by this item will be set forth under Executive Compensation Data and Report of the Compensation Committee in the Exelon Proxy
Statement for the 2021 Annual Meeting of Shareholders or the ComEd 2021 Information Statement, which are incorporated herein by reference.
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ITEM 12.
SECURITY OWNERSHIP OF CERTAIN BENEFICIAL OWNERS AND MANAGEMENT AND RELATED STOCKHOLDER
MATTERS
The additional information required by this item will be set forth under Ownership of Exelon Stock in the 2021 Exelon Proxy Statement or the ComEd 2021
Information Statement and incorporated herein by reference.
Securities Authorized for Issuance under Exelon Equity Compensation Plans
Plan Category
Equity compensation plans approved by
security holders
[A]
[B]
Number of securities to
be issued upon
exercise of outstanding
Options, warrants and
rights (Note 1)
Weighted-average
price of outstanding
Options, warrants
and rights (Note 2)
[C]
Number of securities
remaining available
for future issuance
under equity
compensation plans
(excluding securities
reflected in
column [A]) (Note 3)
7,130,386 $
16.29
46,987,104
__________
(1) Balance includes stock options, unvested performance shares, and unvested restricted stock units that were granted under the Exelon LTIP or predecessor company plans
(including shares awarded under those plans and deferred into the stock deferral plan) and deferred stock units granted to directors as part of their compensation.
Unvested performance shares are subject to performance metrics and to a total shareholder return modifier. Additionally, pursuant to the terms of the Exelon LTIP plan,
50% of final payouts are made in the form of shares of common stock and 50% is made in form of in cash, or if the participant has exceeded 200% of their stock ownership
requirement, 100% of the final payout is made in cash. For performance shares granted in 2018, 2019, and 2020, the total includes the maximum number of shares that
could be issued assuming all participants receive 50% of payouts in shares and assuming the performance and total shareholder return modifier metrics were both at
maximum, representing best case performance, for a total of 6,988,082 shares. If the performance and total shareholder return modifier metrics were at "target", the
number of securities to be issued for such awards would be 3,494,041. The balance also includes 450,154 shares to be issued upon the conversion of deferred stock units
awarded to members of the Exelon board of directors. Conversion of the deferred stock units to shares of common stock occurs after a director terminates service to the
Exelon board or the board of any of its subsidiary companies. See Note 21 — Stock-Based Compensation Plans of the Combined Notes to Consolidated Financial
Statements for additional information about the material features of the plans.
(2) The weighted-average price reported in column B does not take the performance shares and shares credited to deferred compensation plans into account.
(3)
Includes 15,229,957 shares remaining available for issuance from the employee stock purchase plan and 4,729,509 shares remaining available for issuance to former
Constellation employees with outstanding awards made under the prior Constellation LTIP.
No ComEd securities are authorized for issuance under equity compensation plans.
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ITEM 13.
CERTAIN RELATIONSHIPS AND RELATED TRANSACTIONS AND DIRECTOR INDEPENDENCE
The additional information required by this item will be set forth under Related Persons Transactions and Director Independence in the Exelon Proxy
Statement for the 2021 Annual Meeting of Shareholders or the ComEd 2021 Information Statement, which are incorporated herein by reference.
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ITEM 14.
PRINCIPAL ACCOUNTING FEES AND SERVICES
The information required by this item will be set forth under The Ratification of PricewaterhouseCoopers LLP as Exelon’s Independent Accountant for 2021
in the Exelon Proxy Statement for the 2021 Annual Meeting of Shareholders and the ComEd 2021 Information Statement, which are incorporated herein by
reference.
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PART IV
ITEM 15.
EXHIBITS, FINANCIAL STATEMENT SCHEDULES
(a)
The following documents are filed as a part of this report:
(1) Exelon
(i)
Financial Statements (Item 8):
Report of Independent Registered Public Accounting Firm dated February 24, 2021 of PricewaterhouseCoopers LLP
Consolidated Statements of Operations and Comprehensive Income for the Years Ended December 31, 2020, 2019, and 2018
Consolidated Statements of Cash Flows for the Years Ended December 31, 2020, 2019, and 2018
Consolidated Balance Sheets at December 31, 2020 and 2019
Consolidated Statements of Changes in Equity for the Years Ended December 31, 2020, 2019, and 2018
Notes to Consolidated Financial Statements
(ii)
Financial Statement Schedules:
Schedule I—Condensed Financial Information of Parent (Exelon Corporate) at December 31, 2020 and 2019 and for the Years Ended
December 31, 2020, 2019, and 2018
Schedule II—Valuation and Qualifying Accounts for the Years Ended December 31, 2020, 2019, and 2018
Schedules not included are omitted because of the absence of conditions under which they are required or because the required information
is provided in the consolidated financial statements, including the notes thereto.
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Table of Contents
Exelon Corporation and Subsidiary Companies
Schedule I – Condensed Financial Information of Parent (Exelon Corporate)
Condensed Statements of Operations and Other Comprehensive Income
(In millions)
Operating expenses
Operating and maintenance
Operating and maintenance from affiliates
Other
Total operating expenses
Operating loss
Other income and (deductions)
Interest expense, net
Equity in earnings of investments
Interest income from affiliates, net
Other, net
Total other income
Income before income taxes
Income taxes
Net income
Other comprehensive income (loss)
Pension and non-pension postretirement benefit plans:
Prior service benefit reclassified to periodic costs
Actuarial loss reclassified to periodic cost
Pension and non-pension postretirement benefit plan valuation adjustment
Unrealized (loss) gain on cash flow hedges
Unrealized gain on equity investments
Unrealized (loss) on foreign currency translation
Other comprehensive income (loss)
Comprehensive income
2020
For the Years Ended
December 31,
2019
2018
$
$
$
$
(2) $
10
2
10
(10)
(378)
2,313
30
15
1,980
1,970
7
1,963 $
(40) $
190
(357)
(1)
—
—
(208)
1,755 $
33 $
9
1
43
(43)
(321)
3,254
39
14
2,986
2,943
7
2,936 $
(64) $
148
(289)
1
—
—
(204)
2,732 $
(5)
9
4
8
(8)
(312)
2,183
42
3
1,916
1,908
(97)
2,005
(66)
247
(143)
12
1
(10)
41
2,046
See the Notes to Financial Statements
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Exelon Corporation and Subsidiary Companies
Schedule I – Condensed Financial Information of Parent (Exelon Corporate)
Condensed Statements of Cash Flows
(In millions)
Net cash flows provided by operating activities
Cash flows from investing activities
Changes in Exelon intercompany money pool
Notes receivable from affiliates
Investment in affiliates
Net cash flows used in investing activities
Cash flows from financing activities
Changes in short-term borrowings
Issuance of long-term debt
Retirement of long-term debt
Dividends paid on common stock
Proceeds from employee stock plans
Other financing activities
Net cash flows used in financing activities
Increase (Decrease) in cash, restricted cash, and cash equivalents
Cash, restricted cash, and cash equivalents at beginning of period
Cash, restricted cash, and cash equivalents at end of period
2020
For the Years Ended
December 31,
2019
2018
$
3,018 $
1,948 $
2,576
(477)
550
(1,969)
(1,896)
(136)
2,000
(1,450)
(1,492)
45
(27)
(1,060)
62
1
95
—
(1,071)
(976)
136
—
—
(1,408)
112
—
(1,160)
(188)
189
$
63 $
1 $
1
—
(1,231)
(1,230)
—
—
—
(1,332)
105
(4)
(1,231)
115
74
189
See the Notes to Financial Statements
377
Table of Contents
Exelon Corporation and Subsidiary Companies
Schedule I – Condensed Financial Information of Parent (Exelon Corporate)
Condensed Balance Sheets
ASSETS
(In millions)
Current assets
Cash and cash equivalents
Accounts receivable, net
Other accounts receivable
Accounts receivable from affiliates
Mark-to-market derivative assets
Notes receivable from affiliates
Regulatory assets
Other
Total current assets
Property, plant, and equipment, net
Deferred debits and other assets
Regulatory assets
Investments in affiliates
Deferred income taxes
Notes receivable from affiliates
Other
Total deferred debits and other assets
Total assets
December 31,
2020
2019
$
63 $
354
11
—
598
315
4
1,345
46
3,816
43,149
1,625
324
312
49,226
50,617 $
$
1
168
41
3
679
253
4
1,149
47
3,772
42,245
1,524
329
308
48,178
49,374
See the Notes to Financial Statements
378
Table of Contents
Exelon Corporation and Subsidiary Companies
Schedule I – Condensed Financial Information of Parent (Exelon Corporate)
Condensed Balance Sheets
(In millions)
Current liabilities
LIABILITIES AND SHAREHOLDERS’ EQUITY
December 31,
2020
2019
Short-term borrowings
Long-term debt due within one year
Accounts payable
Accrued expenses
Payables to affiliates
Regulatory liabilities
Pension obligations
Other
Total current liabilities
Long-term debt
Deferred credits and other liabilities
Regulatory liabilities
Pension obligations
Non-pension postretirement benefit obligations
Deferred income taxes
Other
Total deferred credits and other liabilities
Total liabilities
Commitments and contingencies
Shareholders’ equity
Common stock (No par value, 2,000 shares authorized, 976 shares and 973 shares outstanding at
December 31, 2020 and 2019, respectively)
Treasury stock, at cost (2 shares at December 31, 2020 and 2019)
Retained earnings
Accumulated other comprehensive loss, net
Total shareholders’ equity
Total liabilities and shareholders’ equity
See the Notes to Financial Statements
379
$
$
500 $
300
1
76
457
4
92
4
1,434
7,418
32
8,351
387
348
62
9,180
18,032
19,373
(123)
16,735
(3,400)
32,585
50,617 $
636
1,458
1
131
363
13
77
10
2,689
5,717
31
7,960
403
263
87
8,744
17,150
19,274
(123)
16,267
(3,194)
32,224
49,374
Table of Contents
1. Basis of Presentation
Exelon Corporation and Subsidiary Companies
Schedule I – Condensed Financial Information of Parent (Exelon Corporate)
Notes to Financial Statements
Exelon Corporate is a holding company that conducts substantially all of its business operations through its subsidiaries. These condensed financial
statements and related footnotes have been prepared in accordance with Rule 12-04, Schedule I of Regulation S-X. These statements should be read in
conjunction with the consolidated financial statements and notes thereto of Exelon Corporation.
Exelon Corporate owns 100% of all of its significant subsidiaries, either directly or indirectly, except for Commonwealth Edison Company (ComEd), of which
Exelon Corporate owns more than 99%.
2. Debt and Credit Agreements
Short-Term Borrowings
Exelon Corporate meets its short-term liquidity requirements primarily through the issuance of commercial paper. Exelon Corporate had no outstanding
commercial paper borrowings and $136 million at December 31, 2020 and 2019, respectively.
Short-Term Loan Agreements
On March 23, 2017, Exelon Corporate entered into a 12-month term loan agreement for $500 million, which was renewed annually on March 22, 2018,
March 20, 2019, and March 19, 2020, respectively. The loan agreement will expire on March 18, 2021. Pursuant to the loan agreement, as of December 31,
2020, loans made thereunder bear interest at a variable rate equal to LIBOR plus 0.65% and all indebtedness thereunder is unsecured. The loans beared
interest at LIBOR plus 0.95% as of December 31, 2019 as part of the March 20, 2019 renewal. The loan agreement is reflected in Exelon’s Consolidated
Balance Sheet within Short-Term borrowings.
Revolving Credit Agreements
On May 26, 2018, Exelon Corporate's syndicated revolving credit facility of $600 million had its maturity date extended to May 26, 2023. As of December 31,
2020, Exelon Corporation had available capacity under those commitments of $594 million. See Note 17—Debt and Credit Agreements of the Combined
Notes to Consolidated Financial Statements for additional information regarding Exelon Corporation’s credit agreement.
On April 24, 2020, Exelon Corporate entered into a credit agreement establishing a $550 million 364-day revolving credit facility at a variable interest rate of
LIBOR plus 1.75%. This facility will be used by Exelon as an additional source of short-term liquidity as needed.
380
Table of Contents
Long-Term Debt
Exelon Corporation and Subsidiary Companies
Schedule I – Condensed Financial Information of Parent (Exelon Corporate)
Notes to Financial Statements
The following tables present the outstanding long-term debt for Exelon Corporate as of December 31, 2020 and December 31, 2019:
Rates
Maturity
Date
December 31,
2020
2019
Long-term debt
Junior subordinated notes
Senior unsecured notes
(a)
Total long-term debt
Unamortized debt discount and premium, net
Unamortized debt issuance costs
Fair value adjustment
Long-term debt due within one year
Long-term debt
2.45 % -
3.50 %
7.60 %
2022 $
1,150 $
2021 - 2050
6,439
7,589
(10)
(47)
186
(300)
$
7,418 $
__________
(a) Senior unsecured notes include mirror debt that is held on both Generation and Exelon Corporation's balance sheets.
The debt maturities for Exelon Corporate for the periods 2021, 2022, 2023, 2024, 2025, and thereafter are as follows:
2021
2022
2023
2024
2025
Thereafter
Total long-term debt
$
$
1,150
5,889
7,039
(7)
(39)
182
(1,458)
5,717
300
1,150
—
—
807
5,332
7,589
3. Commitments and Contingencies
See Note 19—Commitments and Contingencies of the Combined Notes to Consolidated Financial Statements for Exelon Corporate’s commitments and
contingencies related to environmental matters and fund transfer restrictions.
381
Table of Contents
Exelon Corporation and Subsidiary Companies
Schedule I – Condensed Financial Information of Parent (Exelon Corporate)
Notes to Financial Statements
4. Related Party Transactions
The financial statements of Exelon Corporate include related party transactions as presented in the tables below:
(In millions)
Operating and maintenance from affiliates:
(a)
BSC
Other
Total operating and maintenance from affiliates:
Interest income from affiliates, net:
Generation
BSC
EEDC
(b)
Total interest income from affiliates, net:
Equity in earnings (losses) of investments:
EEDC
(b)
Generation
UII
PCI
Exelon Enterprises
Exelon INQB8R
Exelon Transmission Company
Other
Total equity in earnings of investments:
Cash contributions received from affiliates
For the Years Ended
December 31,
2020
2019
2018
10 $
—
10 $
29 $
1
—
30 $
9 $
—
9 $
36 $
3
—
39 $
1,729 $
589
2,054 $
1,125
—
—
—
(6)
—
1
97
1
(16)
(8)
(2)
3
2,313 $
3,254 $
3,372 $
2,514 $
11
(2)
9
36
4
2
42
1,830
369
—
(17)
—
—
1
—
2,183
2,302
$
$
$
$
$
$
$
382
Table of Contents
Exelon Corporation and Subsidiary Companies
Schedule I – Condensed Financial Information of Parent (Exelon Corporate)
Notes to Financial Statements
(in millions)
Accounts receivable from affiliates (current):
(a)
BSC
Generation
ComEd
PECO
BGE
PHISCO
Exelon Enterprises
Exelon VTI, LLC
Total accounts receivable from affiliates (current):
Notes receivable from affiliates (current):
BSC
(a)
(c)
Generation
PECO
PHI
Total notes receivable from affiliates (current):
Investments in affiliates:
BSC
(a)
EEDC
(b)
Generation
PCI
UII
Voluntary Employee Beneficiary Association trust
Exelon Enterprises
Exelon INQB8R, LLC
Other
Total investments in affiliates:
Notes receivable from affiliates (non-current):
Generation
(c)
Accounts payable to affiliates (current):
UII
BSC
EEDC
(b)
Generation
(c)
Exelon Enterprises
Total accounts payable to affiliates (current):
December 31,
2020
2019
— $
3
—
1
—
6
1
—
11 $
252 $
285
40
21
598 $
196 $
30,103
12,400
62
365
—
3
23
(3)
11
13
2
2
1
7
—
5
41
109
558
—
12
679
197
28,147
13,484
62
365
(4)
6
(8)
(4)
43,149 $
42,245
324 $
360 $
91
4
2
—
457 $
329
360
—
—
—
3
363
$
$
$
$
$
$
$
$
$
__________
(a) Exelon Corporate receives a variety of corporate support services from BSC, including legal, human resources, financial, information technology, and supply management
services. All services are provided at cost, including applicable overhead.
(b) EEDC consists of ComEd, PECO, BGE, PHI, Pepco, DPL, and ACE.
(c)
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, which are eliminated in consolidation
in Exelon’s Consolidated Balance Sheets.
383
Table of Contents
Exelon Corporation and Subsidiary Companies
Schedule II – Valuation and Qualifying Accounts
Column A
Description
Column B
Balance at
Beginning
of Period
Column C
Column D
Column E
Additions and adjustments
Charged to
Costs and
Expenses
Charged
to Other
Accounts
Deductions
Balance at
End
of Period
(In millions)
For the year ended December 31, 2020
Allowance for credit losses
(a)
Deferred tax valuation allowance
Reserve for obsolete materials
For the year ended December 31, 2019
Allowance for credit losses
(a)
Deferred tax valuation allowance
Reserve for obsolete materials
For the year ended December 31, 2018
Allowance for credit losses
(a)
Deferred tax valuation allowance
Reserve for obsolete materials
$
$
$
294 $
240
(b)
$
(18)
(c)
$
79
(d)
$
26
155
—
128
(e)
319 $
119
(b)
$
35
156
—
6
322 $
159
(b)
$
37
174
—
25
1
(1)
26
(9)
—
35
5
(31)
(f)
$
$
—
6
170
(d)
$
—
7
197
(d)
$
7
12
437
27
276
294
26
155
319
35
156
__________
(a) Excludes the non-current allowance for credit losses related to PECO’s installment plan receivables of $5 million, $9 million, and $13 million for the years ended
December 31, 2020, 2019, and 2018, respectively.
(b) The amount charged to costs and expenses includes the amount that was reclassified to regulatory assets/liabilities under different mechanisms applicable to the different
(c)
jurisdictions the Utility Registrants operate in.
Includes a decrease related to the sale of customer accounts receivable at Generation in the second quarter of 2020. See Note 6—Accounts Receivable of the Combined
Notes to Consolidated Financial Statements for additional information.
(d) Primarily reflects write-offs, net of recoveries of individual accounts receivable.
(e) Primarily reflects expense resulting from materials and supplies inventory reserve adjustments as a result of the decision to early retire Byron, Dresden, and Mystic 8 and 9.
See Note 7—Early Plant Retirements of the Combined Notes to Consolidated Financial Statements for additional information.
(f) Primarily reflects the reclassification of assets as held for sale at Generation.
384
Table of Contents
Exelon Generation Company, LLC and Subsidiary Companies
(2) Generation
(i)
Financial Statements (Item 8):
Report of Independent Registered Public Accounting Firm dated February 24, 2021 of PricewaterhouseCoopers LLP
Consolidated Statements of Operations and Comprehensive Income for the Years Ended December 31, 2020, 2019, and 2018
Consolidated Statements of Cash Flows for the Years Ended December 31, 2020, 2019, and 2018
Consolidated Balance Sheets at December 31, 2020 and 2019
Consolidated Statements of Changes in Equity for the Years Ended December 31, 2020, 2019, and 2018
Notes to Consolidated Financial Statements
(ii)
Financial Statement Schedule:
Schedule II—Valuation and Qualifying Accounts for the Years Ended December 31, 2020, 2019, and 2018
Schedules not included are omitted because of the absence of conditions under which they are required or because the required information
is provided in the consolidated financial statements, including the notes thereto
385
Table of Contents
Exelon Generation Company, LLC and Subsidiary Companies
Schedule II – Valuation and Qualifying Accounts
Column A
Description
Column B
Balance at
Beginning
of Period
Column C
Column D
Column E
Additions and adjustments
Charged to
Costs and
Expenses
Charged
to Other
Accounts
Deductions
Balance at
End
of Period
(In millions)
For the year ended December 31, 2020
Allowance for credit losses
Deferred tax valuation allowance
Reserve for obsolete materials
For the year ended December 31, 2019
Allowance for credit losses
Deferred tax valuation allowance
Reserve for obsolete materials
For the year ended December 31, 2018
Allowance for credit losses
Deferred tax valuation allowance
Reserve for obsolete materials
$
$
$
81 $
24
143
104 $
26
145
114 $
23
166
$
$
$
12
—
123
(c)
27
—
—
44
—
20
(56)
(a)
$
5
(b)
$
(1)
(1)
(11)
(2)
—
4
3
(32)
(d)
$
$
—
—
39
(b)
$
—
2
58
(b)
$
—
9
32
23
265
81
24
143
104
26
145
__________
(a) Reflects the sale of customer accounts receivable at Generation in the second quarter of 2020. See Note 6—Accounts Receivable of the Combined Notes to Consolidated
Financial Statements for additional information.
(b) Write-offs, net of recoveries of individual accounts receivable.
(c) Primarily reflects expense resulting from materials and supplies inventory reserve adjustments as a result of the decision to early retire Byron, Dresden, and Mystic 8 and 9.
See Note 7—Early Plant Retirements of the Combined Notes to Consolidated Financial Statements for additional information.
(d) Primarily reflects the reclassification of assets as held for sale.
386
Table of Contents
Commonwealth Edison Company and Subsidiary Companies
(3) ComEd
(i)
Financial Statements (Item 8):
Report of Independent Registered Public Accounting Firm dated February 24, 2021 of PricewaterhouseCoopers LLP
Consolidated Statements of Operations and Comprehensive Income for the Years Ended December 31, 2020, 2019, and 2018
Consolidated Statements of Cash Flows for the Years Ended December 31, 2020, 2019, and 2018
Consolidated Balance Sheets at December 31, 2020 and 2019
Consolidated Statements of Changes in Shareholders’ Equity for the Years Ended December 31, 2020, 2019, and 2018
Notes to Consolidated Financial Statements
(ii)
Financial Statement Schedule:
Schedule II—Valuation and Qualifying Accounts for the Years Ended December 31, 2020, 2019, and 2018
Schedules not included are omitted because of the absence of conditions under which they are required or because the required information
is provided in the consolidated financial statements, including the notes thereto
387
Table of Contents
Commonwealth Edison Company and Subsidiary Companies
Schedule II – Valuation and Qualifying Accounts
Column A
Description
Column B
Balance at
Beginning
of Period
Column C
Column D
Column E
Additions and adjustments
Charged to
Costs and
Expenses
Charged
to Other
Accounts
Deductions
Balance at
End
of Period
(In millions)
For the year ended December 31, 2020
Allowance for credit losses
Reserve for obsolete materials
For the year ended December 31, 2019
Allowance for credit losses
Reserve for obsolete materials
For the year ended December 31, 2018
Allowance for credit losses
Reserve for obsolete materials
$
$
$
79 $
7
81 $
6
73 $
5
54
(a)
$
3
35
(a)
$
6
44
3
(a)
$
13 $
—
20 $
—
23 $
1
28
(b)
$
4
57
(b)
$
5
59
3
(b)
$
118
6
79
7
81
6
__________
(a) ComEd is allowed to recover from or refund to customers the difference between its annual credit loss expense and the amounts collected in rates annually through a rider
mechanism. The amount charged to costs and expenses includes the amount that was reclassified to regulatory assets/liabilities under such mechanism. See Note 3 –
Regulatory Matters of the Combined Notes to Consolidated Financial Statements for additional information.
(b) Write-offs, net of recoveries of individual accounts receivable.
388
Table of Contents
(4) PECO
(i)
Financial Statements (Item 8):
PECO Energy Company and Subsidiary Companies
Report of Independent Registered Public Accounting Firm dated February 24, 2021 of PricewaterhouseCoopers LLP
Consolidated Statements of Operations and Comprehensive Income for the Years Ended December 31, 2020, 2019, and 2018
Consolidated Statements of Cash Flows for the Years Ended December 31, 2020, 2019, and 2018
Consolidated Balance Sheets at December 31, 2020 and 2019
Consolidated Statements of Changes in Shareholder's Equity for the Years Ended December 31, 2020, 2019, and 2018
Notes to Consolidated Financial Statements
(ii)
Financial Statement Schedule:
Schedule II—Valuation and Qualifying Accounts for the Years Ended December 31, 2020, 2019, and 2018
Schedules not included are omitted because of the absence of conditions under which they are required or because the required information
is provided in the consolidated financial statements, including the notes thereto
389
Table of Contents
PECO Energy Company and Subsidiary Companies
Schedule II – Valuation and Qualifying Accounts
Column A
Column B
Column C
Column D
Column E
Description
(In millions)
For the year ended December 31, 2020
Allowance for credit losses
Deferred tax valuation allowance
(a)
Reserve for obsolete materials
For the year ended December 31, 2019
Allowance for credit losses
(a)
Reserve for obsolete materials
For the year ended December 31, 2018
Allowance for credit losses
(a)
Reserve for obsolete materials
Additions and adjustments
Balance at
Beginning
of Period
Charged to
Costs and
Expenses
Charged
to Other
Accounts
Deductions
Balance at
End
of Period
$
$
$
62 $
—
2
61 $
2
56 $
2
76
—
1
31
—
33
—
(b)
$
6 $
1
—
3 $
—
3 $
—
$
$
$
$
(c)
20
—
1
33
(c)
$
—
31
(c)
$
—
124
1
2
62
2
61
2
__________
(a) Excludes the non-current allowance for credit losses related to PECO’s installment plan receivables of $5 million, $9 million, and $13 million for the years ended
December 31, 2020, 2019, and 2018, respectively.
(b) The amount charged to costs and expenses includes the amount that was reclassified to the COVID-19 regulatory asset. See Note 3 – Regulatory Matters of the Combined
Notes to Consolidated Financial Statements for additional information.
(c) Write-offs, net of recoveries of individual accounts receivable.
390
Table of Contents
(5) BGE
(i)
Financial Statements (Item 8):
Baltimore Gas and Electric Company
Report of Independent Registered Public Accounting Firm dated February 24, 2021 of PricewaterhouseCoopers LLP
Statements of Operations and Comprehensive Income for the Years Ended December 31, 2020, 2019 and 2018
Statements of Cash Flows for the Years Ended December 31, 2020, 2019 and 2018
Balance Sheets at December 31, 2020 and 2019
Statements of Changes in Shareholder's Equity for the Years Ended December 31, 2020, 2019 and 2018
Notes to Financial Statements
(ii)
Financial Statement Schedule:
Schedule II—Valuation and Qualifying Accounts for the Years Ended December 31, 2020, 2019, and 2018
Schedules not included are omitted because of the absence of conditions under which they are required or because the required information
is provided in the consolidated financial statements, including the notes thereto
391
Table of Contents
Baltimore Gas and Electric Company
Schedule II – Valuation and Qualifying Accounts
Column A
Column B
Column C
Column D
Column E
Description
(In millions)
For the year ended December 31, 2020
Allowance for credit losses
Deferred tax valuation allowance
Reserve for obsolete materials
For the year ended December 31, 2019
Allowance for credit losses
Deferred tax valuation allowance
Reserve for obsolete materials
For the year ended December 31, 2018
Allowance for credit losses
Deferred tax valuation allowance
Reserve for obsolete materials
Additions and adjustments
Balance at
Beginning
of Period
Charged to
Costs and
Expenses
Charged
to Other
Accounts
Deductions
Balance at
End
of Period
$
$
$
17 $
31
(a)
$
6 $
10
(b)
$
1
1
—
—
(1)
—
—
—
20 $
8
(a)
$
7 $
18
(b)
$
1
1
—
—
—
—
—
—
24 $
10
(a)
$
(2) $
12
(b)
$
1
—
—
1
—
—
—
—
44
—
1
17
1
1
20
1
1
__________
(a) The amount charged to costs and expenses includes the amount that was reclassified to regulatory assets/liabilities under different mechanisms as approved by the
MDPSC.
(b) Write-offs, net of recoveries of individual accounts receivable.
392
Table of Contents
(6) PHI
(i)
Financial Statements (Item 8):
Pepco Holdings LLC and Subsidiary Companies
Report of Independent Registered Public Accounting Firm dated February 24, 2021 of PricewaterhouseCoopers LLP
Consolidated Statements of Operations and Comprehensive Income for the Years Ended December 31, 2020, 2019, and 2018
Consolidated Statements of Cash Flows for the Years Ended December 31, 2020, 2019, and 2018
Consolidated Balance Sheets at December 31, 2020 and 2019
Consolidated Statements of Changes in Equity for the Years Ended December 31, 2020, 2019, and 2018
Notes to Consolidated Financial Statements
(ii)
Financial Statement Schedule:
Schedule II—Valuation and Qualifying Accounts for the Years Ended December 31, 2020, 2019, and 2018
Schedules not included are omitted because of the absence of conditions under which they are required or because the required information
is provided in the consolidated financial statements, including the notes thereto
393
Table of Contents
Pepco Holdings LLC and Subsidiary Companies
Schedule II – Valuation and Qualifying Accounts
Column A
Column B
Column C
Column D
Column E
Description
(In millions)
For the year ended December 31, 2020
Allowance for credit losses
Reserve for obsolete materials
For the year ended December 31, 2019
Allowance for credit losses
Deferred tax valuation allowance
Reserve for obsolete materials
For the year ended December 31, 2018
Allowance for credit losses
Deferred tax valuation allowance
Reserve for obsolete materials
Additions and adjustments
Balance at
Beginning
of Period
Charged to
Costs and
Expenses
Charged
to Other
Accounts
Deductions
Balance at
End
of Period
$
$
$
53 $
3
69
(a)
$
—
13 $
—
16
(b)
$
1
53 $
17
(a)
$
7 $
24
(c)
$
8
2
—
1
(8)
—
—
—
55 $
28
(a)
$
7 $
37
(c)
$
13
2
—
—
2
—
7
—
119
2
53
—
3
53
8
2
__________
(a) The amount charged to costs and expenses includes the amount that was reclassified to regulatory assets/liabilities under different mechanisms applicable to the different
jurisdictions Pepco, DPL, and ACE operate in.
(b) Write-offs, net of recoveries of individual accounts receivable.
(c) Write-offs of individual accounts receivable.
394
Table of Contents
(7) Pepco
(i)
Financial Statements (Item 8):
Potomac Electric Power Company
Report of Independent Registered Public Accounting Firm dated February 24, 2021 of PricewaterhouseCoopers LLP
Statements of Operations and Comprehensive Income for the Years Ended December 31, 2020, 2019 and 2018
Statements of Cash Flows for the Years Ended December 31, 2020, 2019 and 2018
Balance Sheets at December 31, 2020 and 2019
Statements of Changes in Shareholder's Equity for the Years Ended December 31, 2020, 2019 and 2018
Notes to Financial Statements
(ii)
Financial Statement Schedule:
Schedule II—Valuation and Qualifying Accounts for the Years Ended December 31, 2020, 2019, and 2018
Schedules not included are omitted because of the absence of conditions under which they are required or because the required information
is provided in the consolidated financial statements, including the notes thereto
395
Table of Contents
Potomac Electric Power Company
Schedule II – Valuation and Qualifying Accounts
Column A
Column B
Column C
Column D
Column E
Description
(In millions)
For the year ended December 31, 2020
Allowance for credit losses
Reserve for obsolete materials
For the year ended December 31, 2019
Allowance for credit losses
Reserve for obsolete materials
For the year ended December 31, 2018
Allowance for credit losses
Reserve for obsolete materials
Additions and adjustments
Balance at
Beginning
of Period
Charged to
Costs and
Expenses
Charged
to Other
Accounts
Deductions
Balance at
End
of Period
$
$
$
20 $
1
21 $
1
21 $
1
25
(a)
$
—
7
(a)
$
—
11
(a)
$
—
5 $
—
2 $
—
3 $
—
5
(b)
$
—
10
(c)
$
—
14
(c)
$
—
45
1
20
1
21
1
__________
(a) The amount charged to costs and expenses includes the amount that was reclassified to regulatory assets/liabilities under different mechanisms as approved by the
DCPSC and MDPSC.
(b) Write-offs, net of recoveries of individual accounts receivable.
(c) Write-off of individual accounts receivable.
396
Table of Contents
(8) DPL
(i)
Financial Statements (Item 8):
Delmarva Power & Light Company
Report of Independent Registered Public Accounting Firm dated February 24, 2021 of PricewaterhouseCoopers LLP
Statements of Operations and Comprehensive Income for the Years Ended December 31, 2020, 2019 and 2018
Statements of Cash Flows for the Years Ended December 31, 2020, 2019 and 2018
Balance Sheets at December 31, 2020 and 2019
Statements of Changes in Shareholder's Equity for the Years Ended December 31, 2020, 2019 and 2018
Notes to Financial Statements
(ii)
Financial Statement Schedule:
Schedule II—Valuation and Qualifying Accounts for the Years Ended December 31, 2020, 2019, and 2018
Schedules not included are omitted because of the absence of conditions under which they are required or because the required information
is provided in the consolidated financial statements, including the notes thereto
397
Table of Contents
Delmarva Power & Light Company
Schedule II – Valuation and Qualifying Accounts
Column A
Column B
Column C
Column D
Column E
Description
(In millions)
For the year ended December 31, 2020
Allowance for credit losses
For the year ended December 31, 2019
Allowance for credit losses
For the year ended December 31, 2018
Allowance for credit losses
Additions and adjustments
Balance at
Beginning
of Period
Charged to
Costs and
Expenses
Charged
to Other
Accounts
Deductions
Balance at
End
of Period
$
$
$
15 $
16
(a)
13 $
16 $
4
(a)
6
(a)
$
$
$
4 $
3 $
2 $
4
(b)
5
(c)
11
(c)
$
$
$
31
15
13
__________
(a) The amount charged to costs and expenses includes the amount that was reclassified to regulatory assets/liabilities under different mechanisms as approved by the DPSC
and MDPSC.
(b) Write-offs, net of recoveries of individual accounts receivable.
(c) Write-off of individual accounts receivable.
398
Table of Contents
(9) ACE
(i)
Financial Statements (Item 8):
Atlantic City Electric Company and Subsidiary Company
Report of Independent Registered Public Accounting Firm dated February 24, 2021 of PricewaterhouseCoopers LLP
Consolidated Statements of Operations and Comprehensive Income for the Years Ended December 31, 2020, 2019, and 2018
Consolidated Statements of Cash Flows for the Years Ended December 31, 2020, 2019, and 2018
Consolidated Balance Sheets at December 31, 2020 and 2019
Consolidated Statements of Changes in Shareholder's Equity for the Years Ended December 31, 2020, 2019, and 2018
Notes to Consolidated Financial Statements
(ii)
Financial Statement Schedule:
Schedule II—Valuation and Qualifying Accounts for the Years Ended December 31, 2020, 2019, and 2018
Schedules not included are omitted because of the absence of conditions under which they are required or because the required information
is provided in the consolidated financial statements, including the notes thereto
399
Table of Contents
Atlantic City Electric Company and Subsidiary Company
Schedule II – Valuation and Qualifying Accounts
Column A
Column B
Column C
Column D
Column E
Description
(In millions)
For the year ended December 31, 2020
Allowance for credit losses
Reserve for obsolete materials
For the year ended December 31, 2019
Allowance for credit losses
Reserve for obsolete materials
For the year ended December 31, 2018
Allowance for credit losses
Reserve for obsolete materials
Additions and adjustments
Balance at
Beginning
of Period
Charged to
Costs and
Expenses
Charged
to Other
Accounts
Deductions
Balance at
End
of Period
$
$
$
18 $
1
19 $
1
18 $
1
28
(a)
$
—
5
(a)
$
—
11
—
(a)
$
4 $
—
2 $
—
2 $
—
(b)
$
7
1
8
(c)
$
—
12
—
(c)
$
43
—
18
1
19
1
__________
(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 amount charged to costs and expenses includes the amount that was reclassified to regulatory assets/liabilities under such mechanism. See
Note 3 – Regulatory Matters of the Combined Notes to Consolidated Financial Statements for additional information.
(b) Write-offs, net of recoveries of individual accounts receivable.
(c) Write-off of individual accounts receivable.
400
Table of Contents
Exhibits required by Item 601 of Regulation S-K:
Certain of the following exhibits are incorporated herein by reference under Rule 12b-32 of the Securities and Exchange Act of 1934, as amended. Certain
other instruments which would otherwise be required to be listed below have not been so listed because such instruments do not authorize securities in an
amount which exceeds 10% of the total assets of the applicable registrant and its subsidiaries on a consolidated basis and the relevant registrant agrees to
furnish a copy of any such instrument to the Commission upon request.
Exhibit No.
Description
2-1
2-2
2-3
2-4
2-5
2-6
2-7
2-8
2-9
3-1
3-2
3-3
3-4
Agreement and Plan of Merger dated as of April 28, 2011 by and among Exelon Corporation, Bolt Acquisition Corporation and
Constellation Energy Group, Inc. (File No. 001-16169, Form 8-K dated April 28, 2011, Exhibit 2.1).
Distribution and Assignment Agreement, dated as of March 12, 2012, by and among Exelon Corporation, Constellation Energy Group,
Inc. and RF HoldCo LLC (File No. 001-16169, Form 8-K dated March 14, 2012, Exhibit 2.3).
Contribution and Assignment Agreement, dated as of March 12, 2012, by and among Exelon Corporation, Exelon Energy Delivery
Company, LLC and RF HoldCo LLC (File No. 001-16169, Form 8-K dated March 14, 2012, Exhibit 2.4).
Contribution Agreement, dated as of March 12, 2012, by and among Exelon Corporation, Exelon Ventures Company, LLC and Exelon
Generation Company, LLC (File No. 001-16169, Form 8-K dated March 14, 2012, Exhibit 2.5).
Purchase Agreement dated as of August 8, 2012 by and between Constellation Power Source Generation, Inc. and Raven Power
Holdings, LLC. (File No. 333-85496, Form 10-Q dated November 7, 2012, Exhibit 2.1).
Master Agreement, dated as of October 26, 2010, by and between Electricite de France, S.A. and Constellation Energy Group, Inc. (File
No. 001-12869, Form 8-K dated November 1, 2010, Exhibit 2.1).
Put Termination Agreement dated as of November 3, 2010, by and among EDF Inc. (formerly known as EDF Development, Inc.), E.D.F.
International S.A., Constellation Nuclear, LLC, and Constellation Energy Nuclear Group, LLC. (File No. 001-12869, Form 8-K dated
November 8, 2010, Exhibit 2.1).
Contribution Agreement, dated as of February 4, 2010, by and among Constellation Energy Group, Inc., Baltimore Gas and Electric
Company and RF HoldCo LLC. (File No. 001-12869, Form 8-K dated February 4, 2010, Exhibit 99.2).
Amended and Restated Agreement and Plan of Merger, dated as of July 18, 2014, among Pepco Holdings, Inc., Exelon Corporation and
Purple Acquisition Corp. (File No. 001-16169, Form 8-K dated July 21, 2014, Exhibit 2.1).
Amended and Restated Articles of Incorporation of Exelon Corporation, as amended July 24, 2018 (File No. 001-16169, Form 8-K dated
July 27, 2018, Exhibit 3.1).
Exelon Corporation Amended and Restated Bylaws, as amended on August 3, 2020 (File No. 001-16169, Form 10-Q dated August 4,
2020, Exhibit 3.1).
Certificate of Formation of Exelon Generation Company, LLC (Registration Statement No. 333-85496, Form S-4 dated December 27,
2000, Exhibit 3.1).
Second Amended and Restated Operating Agreement of Exelon Generation Company, LLC dated of October 30, 2019 (File No. 333-
85496, Form 10-Q dated October 31, 2019, Exhibit 3.1).
401
Table of Contents
Exhibit No.
Description
3-5
3-6
3-7
3-8
3-9
3-10
3-11
3-12
3-13
3-14
3-15
3-16
3-17
3-18
3-19
3-20
Restated Articles of Incorporation of Commonwealth Edison Company Effective February 20, 1985, including Statements of Resolution
Establishing Series, relating to the establishment of three new series of Commonwealth Edison Company preference stock known as the
“$9.00 Cumulative Preference Stock,” the “$6.875 Cumulative Preference Stock” and the “$2.425 Cumulative Preference Stock” (File No.
001-01839, Form 10-K dated March 30, 1995, Exhibit 3.2).
Commonwealth Edison Company Amended and Restated By-Laws, Effective February 22, 2021.**
Amended and Restated Articles of Incorporation of PECO Energy Company (File No. 001-01401, Form 10-K dated April 2, 2001, Exhibit
3.3).
PECO Energy Company Amended and Restated Bylaws dated August 3, 2020 (File 000-16844, Form 10-Q dated August 4, 2020, Exhibit
3.3).
Articles of Amendment to the Charter of Baltimore Gas and Electric Company as of February 2, 2010. (File No. 001-01910, Form 8-K
dated February 4, 2010, Exhibit 3.1).
Articles of Restatement to the Charter of Baltimore Gas and Electric Company, restated as of August 16, 1996. (File No. 001-01910, Form
10-Q dated November 14, 1996, Exhibit 3).
Amended and Restated Bylaws of Baltimore Gas and Electric Company dated August 3, 2020 (File No. 001-01910, Form 10-Q dated
August 4, 2020, Exhibit 3.4).
Certificate of Formation of Pepco Holdings LLC, dated March 23, 2016 (File No. 001-31403, Form 8-K dated March 24, 2016, Exhibit 3.2).
Amended and Restated Limited Liability Company Agreement of Pepco Holdings LLC, dated August 3, 2020 (File No. 001-31403, Form
10-Q dated August 4, 2020, Exhibit 3.5).
Potomac Electric Power Company Restated Articles of Incorporation and Articles of Restatement of (as filed in the District of Columbia)
(File No. 001-31403, Form 10-Q dated May 5, 2006, Exhibit 3.1).
Potomac Electric Power Company Restated Articles of Incorporation and Articles of Restatement of (as filed in Virginia) (File No. 001-
01072, Form 10-Q dated November 4, 2011, Exhibit 3.3).
Delmarva Power & Light Company Articles of Restatement of Certificate and Articles of Incorporation (filed in Delaware and Virginia
02/22/07) (File No. 001-01405, Form 10-K dated March 1, 2007, Exhibit 3.3).
Atlantic City Electric Company Restated Certificate of Incorporation (filed in New Jersey on August 9, 2002) (File No. 001-03559,
Amendment No. 1 to Form U5B dated February 13, 2003, Exhibit B.8.1).
Bylaws of Potomac Electric Power Company (File No. 001-01072, Form 10-Q dated May 5, 2006, Exhibit 3.2).
Bylaws of Delmarva Power & Light Company (File No. 001-01405, Form 10-Q dated May 9, 2005, Exhibit 3.2.1).
Bylaws of Atlantic City Electric Company (File No. 001-03559, Form 10-Q dated May 9, 2005, Exhibit 3.2.2).
402
Table of Contents
Exhibit No.
Description
4-1
First and Refunding Mortgage dated May 1, 1923 between The Counties Gas and Electric Company (predecessor to PECO Energy
Company) and Fidelity Trust Company, Trustee (U.S. Bank National Association, as current successor trustee), (Registration No. 2-2281,
Exhibit B-1).
(a)
4-1-1
Supplemental Indentures to PECO Energy Company’s First and Refunding Mortgage:
Dated as of
December 1, 1941
April 15, 2004
September 15, 2006
File Reference
2-4863
(a)
000-16844, Form 10-Q dated
September 30, 2004
Exhibit No.
B-1(h)
4-1-1
000-16844, Form 8-K dated September 25,
2006
4.1
March 1, 2007
000-16844, Form 8-K dated March 19, 2007
4.1
September 1, 2012
September 15, 2013
September 1, 2014
000-16844, Form 8-K dated September 17,
2012
000-16844, Form 8-K dated September 23,
2013
000-16844, Form 8-K dated September 15,
2014
4.1
4.1
4.1
September 15, 2015
000-16844, Form 8-K dated October 5, 2015
4.1
September 1, 2016
September 1, 2017
February 1, 2018
September 1, 2018
August 15, 2019
June 1, 2020
000-16844, Form 8-K dated September 21,
2016
000-16844, Form 8-K dated September 18,
2017
000-16844, Form 8-K dated February 23,
2018
000-16844, Form 8-K dated September 11,
2018
000-16844, Form 8-K dated September 10,
2019
000-16844, Form 8-K dated June 8, 2020
4.1
4.1
4.1
4.1
4.1
4.1
Exhibit No.
Description
4-2
4-3
Exelon Corporation Direct Stock Purchase Plan (Registration Statement No. 333-206474, Form S-3, Prospectus).
Mortgage of Commonwealth Edison Company to Illinois Merchants Trust Company, Trustee (BNY Mellon Trust Company of Illinois, as
current successor Trustee), dated July 1, 1923, as supplemented and amended by Supplemental Indenture thereto dated August 1, 1944.
(Registration No. 2-60201, Form S-7, Exhibit 2-1).
(a)
403
Table of Contents
Exhibit No.
Description
4-3-1
Supplemental Indentures to Commonwealth Edison Company Mortgage.
Dated as of
January 13, 2003
February 22, 2006
August 1, 2006
File Reference
Exhibit No.
001-01839, Form 8-K dated February 13,
2003
4-4
001-01839, Form 8-K dated March 6, 2006
4.1
001-01839, Form 8-K dated August 28, 2006 4.1
September 15, 2006
001-01839, Form 8-K dated October 2, 2006 4.1
March 1, 2007
001-01839, Form 8-K dated March 23, 2007 4.1
August 30, 2007
001-01839, Form 8-K dated September 10,
2007
4.1
December 20, 2007
001-01839, Form 8-K dated January 16, 2008 4.1
March 10, 2008
July 12, 2010
August 22, 2011
001-01839, Form 8-K dated March 27, 2008 4.1
001-01839, Form 8-K dated August 2, 2010
4.1
001-01839, Form 8-K dated September 7,
2011
4.1
September 17, 2012
001-01839, Form 8-K dated October 1, 2012 4.1
August 1, 2013
January 2, 2014
October 28, 2014
001-01839, Form 8-K dated August 19, 2013 4.1
001-01839, Form 8-K dated January 10, 2014 4.1
001-01839, Form 8-K dated November 10,
2014
February 18, 2015
001-01839, Form 8-K dated March 2, 2015
November 4, 2015
June 15, 2016
August 9, 2017
001-01839, Form 8-K dated November 19,
2015
001-01839, Form 8-K dated June 27, 2016
001-01839, Form 8-K dated August 23, 2017
404
4.1
4.1
4.1
4.1
4.1
Table of Contents
Dated as of
February 6, 2018
File Reference
001-01839, Form 8-K dated February 20,
2018
Exhibit No.
4.1
July 26, 2018
001-01839, Form 8-K dated August 14, 2018
4.1
February 7, 2019
October 29, 2019
February 10, 2020
001-01839, Form 8-K dated February 19,
2019
001-01839, Form 8-K dated November 12,
2019
001-01839, Form 8-K dated February 10,
2020
4.1
4.1
4.1
Exhibit No.
Description
4-4
4-5
4-6
4-7
4-8
4-9
4-10
4-11
4-12
4-13
4-14
4-15
Instrument of Resignation, Appointment and Acceptance dated as of February 20, 2002, under the provisions of the Mortgage of
Commonwealth Edison Company dated July 1, 1923, and Indentures Supplemental thereto, regarding corporate trustee (File No. 001-
01839, Form 10-K dated April 1, 2002, Exhibit 4.4.2).
Instrument dated as of January 31, 1996, under the provisions of the Mortgage of Commonwealth Edison Company dated July 1, 1923
and Indentures Supplemental thereto, regarding individual trustee (File No. 001-01839, Form 10-K dated March 29, 1996, Exhibit 4.29).
Indenture to Subordinated Debt Securities dated as of June 24, 2003 between PECO Energy Company, as Issuer, and U.S. Bank
National Association, as Trustee (File No. 000-16844, Form 10-Q dated July 30, 2003, Exhibit 4.1).
Form of 4.25% Senior Note due 2022 issued by Exelon Generation Company, LLC. (File No. 333-85496, Form 8-K dated June 18, 2012,
Exhibit 4.1).
Form of 5.60% Senior Note due 2042 issued by Exelon Generation Company, LLC. (File No. 333-85496, Form 8-K dated June 18, 2012,
Exhibit 4.2).
Form of 2.80% Senior Note due 2022 issued by Baltimore Gas and Electric Company. (File No. 001-01910, Form 8-K dated August 17,
2012, Exhibit 4.1).
Form of 3.35% Senior Note due 2023 Baltimore Gas and Electric Company. (File No. 001-01910, Form 8-K dated June 17, 2013, Exhibit
4.1).
Form of 6.000% Senior Notes due 2033 issued by Exelon Generation Company, LLC (File No. 333-85496, Form 8-K dated September
30, 2013, Exhibit No. 4.1).
Preferred Securities Guarantee Agreement between PECO Energy Company, as Guarantor, and U.S. Bank National Association, as
Trustee, dated as of June 24, 2003 (File No. 000-16844, Form 10-Q dated July 30, 2003, Exhibit 4.2).
PECO Energy Capital Trust IV Amended and Restated Declaration of Trust among PECO Energy Company, as Sponsor, U.S. Bank Trust
National Association, as Delaware Trustee and Property Trustee, and J. Barry Mitchell, George R. Shicora and Charles S. Walls as
Administrative Trustees dated as of June 24, 2003 (File No. 000-16844, Form 10-Q dated July 30, 2003, Exhibit 4.3).
Indenture dated May 1, 2001 between Exelon Corporation and The Bank of New York Mellon Trust Company, National Association, as
trustee (File No. 001-16169, Form 10-Q dated July 26, 2005, Exhibit 4.10).
Form of $500,000,000 5.625% senior notes due 2035 dated June 9, 2005 issued by Exelon Corporation (File No. 001-16169, Form 8-K
dated June 9, 2005, Exhibit 99.3).
405
Table of Contents
Exhibit No.
Description
4-16
4-17
4-18
4-19
4-20
4-21
4-22
4-23
4-24
4-25
4-26
4-27
4-28
4-29
4-30
Indenture dated as of September 28, 2007 from Exelon Generation Company, LLC to U.S. Bank National Association, as trustee (File No.
333-85496, Form 8-K dated September 28, 2007, Exhibit 4.1).
Form of 6.25% Exelon Generation Company, LLC Senior Note due 2039 (File No. 333-85496, Form 8-K dated September 23, 2009,
Exhibit 4.2).
Form of 4.00% Exelon Generation Company, LLC Senior Note due 2020 (File No. 333-85496, Form 8-K dated September 30, 2010,
Exhibit 4.1).
Form of 5.75% Exelon Generation Company, LLC Senior Note due 2041 (File No. 333-85496, Form 8-K dated September 30, 2010,
Exhibit 4.2).
Indenture between Constellation Energy Group, Inc. and the Bank of New York, Trustee dated as of March 24, 1999. (File No. 333-75217,
Registration Statement on Form S-3 dated March 29, 1999, Exhibit 4(a)).
First Supplemental Indenture between Constellation Energy Group, Inc. and the Bank of New York, Trustee dated as of January 24, 2003.
(File No. 333-102723, Registration Statement on Form S-3 dated January 24, 2003, Exhibit 4(b)).
Indenture dated as of July 24, 2006 between Constellation Energy Group, Inc. and Deutsche Bank Trust Company Americas, as trustee.
(File No. 333-135991, Registration Statement on Form S-3 dated July 24, 2006, Exhibit 4(a)).
First Supplemental Indenture between Constellation Energy Group, Inc. and Deutsche Bank Trust Company Americas, as trustee, dated
as of June 27, 2008. (File No. 001-12869, Form 8-K dated June 30, 2008, Exhibit 4(a)).
Indenture dated June 19, 2008 between Constellation Energy Group, Inc. and Deutsche Bank Trust Company Americas, as trustee. (File
No. 001-12869, Form 10-Q dated August 11, 2008, Exhibit 4(a)).
Indenture, dated as of September 30, 2013, among Continental Wind, LLC, the guarantors party thereto and Wilmington Trust, National
Association, as trustee (File No. 333-85496, Form 8-K dated September 30, 2013, Exhibit 4.1).
Indenture dated July 1, 1985, between Baltimore Gas and Electric Company and The Bank of New York (Successor to Mercantile-Safe
Deposit and Trust Company), Trustee. (Designated as Exhibit 4(a) to the Registration Statement on Form S-3, File No. 2-98443); as
supplemented by Supplemental Indentures dated as of October 1, 1987 (Designated as Exhibit 4(a) to the Current Report on Form 8-K,
dated November 13, 1987, File No. 1-1910) and as of January 26, 1993 (Designated as Exhibit 4(b) to the Current Report on Form 8-K,
dated January 29, 1993, filed by Baltimore Gas and Electric Company, File No. 1-1910).
(a)
Indenture dated as of July 24, 2006 between Baltimore Gas and Electric Company and Deutsche Bank Trust Company Americas, as
trustee. (File No. 333-135991, Registration Statement on Form S-3 dated July 24, 2006, Exhibit 4(b)).
Indenture dated as of June 29, 2007, by and between RSB BondCo LLC and Deutsche Bank Trust Company Americas, as Trustee and
Securities Intermediary. (File No. 001-01910, Form 8-K dated July 5, 2007, Exhibit 4.1).
Series Supplement to Indenture dated as of June 29, 2007 by and between RSB BondCo LLC and Deutsche Bank Trust Company
Americas, as Trustee and Securities Intermediary (File No. 001-01910, Form 10-Q dated November 6, 2009, Exhibit 4(b)).
Replacement Capital Covenant dated June 27, 2008. (File No. 001-12869, Form 8-K dated June 30, 2008, Exhibit No. 4(b)).
406
Table of Contents
Exhibit No.
Description
4-31
4-32
4-33
4-34
4-35-1
4-35-2
4-35-3
4-35-4
4-35-5
4-35-6
4-36
4-36-1
4-36-2
4-37
4-38
4-39
Amendment to Replacement Capital Covenant, dated as of March 12, 2012, amending the Replacement Capital Covenant, dated as of
June 27, 2008 (File No. 001-16169, Form 8-K dated March 14, 2012, Exhibit 99.4).
Officers’ Certificate, dated December 14, 2010, establishing the 5.15% Notes due December 1, 2020 of Constellation Energy Group, Inc.,
with the form of Notes attached thereto. (File No. 001-12869, Form 8-K dated December 14, 2010, Exhibit 4 (b)).
Officers’ Certificate, November 16, 2011, establishing the 3.50% Notes due November 15, 2021 of Baltimore Gas and Electric Company,
with the form of Notes attached thereto. (File No. 001-01910, Form 8-K dated November 16, 2011, Exhibit 4(b)).
Indenture, dated as of June 17, 2014, between Exelon Corporation and The Bank of New York Mellon Trust Company, N.A., as Trustee.
(File No. 001-16169, Form 8-K dated June 23, 2014, Exhibit 4.1).
First Supplemental Indenture, dated as of June 17, 2014, between Exelon Corporation and The Bank of New York Mellon Trust Company,
N.A., as Trustee. (File No. 001-16169, Form 8-K dated June 23, 2014, Exhibit 4.2).
Form of 2.50% Notes due 2024 (File No. 001-16169, Form 8-K dated June 23, 2014, Exhibit 4.2, Exhibit A).
Purchase Contract and Pledge Agreement, between Exelon Corporation and The Bank of New York Mellon Trust Company, N.A., as
Purchase Contract Agent, Collateral Agent, Custodial Agent and Securities Intermediary. (File No. 001-16169, Form 8-K dated June 23,
2014, Exhibit 4.4).
Form of Remarketing Agreement (File No. 001-16169, Form 8-K dated June 23, 2014, Exhibit 4.4, Exhibit P).
Form of Corporate Unit (File No. 001-16169, Form 8-K dated June 23, 2014, Exhibit 4.4, Exhibit A).
Form of Treasury Unit (File No. 001-16169, Form 8-K dated June 23, 2014, Exhibit 4.4, Exhibit B).
Indenture, dated as of June 11, 2015, among Exelon Corporation and The Bank of New York Mellon Trust Company, National
Association, as trustee (File No. 001-16169, Form 8-K dated June 11, 2015, Exhibit 4.1).
First Supplemental Indenture, dated as of June 11, 2015, among Exelon Corporation and The Bank of New York Mellon Trust Company,
National Association, as trustee (File No. 001-16169, Form 8-K dated June 11, 2015, Exhibit 4.2).
Second Supplemental Indenture, dated as of December 2, 2015, among Exelon Corporation and The Bank of New York Mellon Trust
Company, National Association, as trustee (File No. 001-16169, Form 8-K dated December 2, 2015, Exhibit 4.1).
Form of Conversion Supplemental Indenture, dated March 23, 2016 (File No. 001-31403, Form 8-K dated March 24, 2016, Exhibit 4.1).
Third Supplemental Indenture, dated as of April 7, 2016, among Exelon Corporation and The Bank of New York Mellon Trust Company,
N.A., as trustee (File No. 001-16169, Form 8-K dated April 7, 2016, Exhibit 4.2).
Mortgage and Deed of Trust, dated July 1, 1936, of Potomac Electric Power Company to The Bank of New York Mellon as successor
trustee, securing First Mortgage Bonds of Potomac Electric Power Company, and Supplemental Indenture dated July 1, 1936 (File No. 2-
2232, Registration Statement dated June 19, 1936, Exhibit B-4).(a)
407
Table of Contents
Exhibit No.
Description
4-39-1
Supplemental Indentures to Potomac Electric Power Company Mortgage.
Dated as of
December 10, 1939
March 16, 2004
May 24, 2005
November 13, 2007
File Reference
Form 8-K dated January 3, 1940
(a)
Exhibit No.
B
001-01072, Form 8-K dated March 23, 2004
4.3
001-01072, Form 8-K dated May 26, 2005
4.2
001-01072, Form 8-K dated November 15,
2007
4.2
March 24, 2008
001-01072, Form 8-K dated March 28, 2008
4.1
December 3, 2008
March 28, 2012
March 11, 2013
November 14, 2013
March 11, 2014
March 9, 2015
May 15, 2017
June 1, 2018
May 2, 2019
February 12, 2020
001-01072, Form 8-K dated December 8,
2008
4.2
001-01072, Form 8-K dated March 29, 2012
4.2
001-01072, Form 8-K dated March 12, 2013
4.2
001-01072, Form 8-K dated November 15,
2013
4.2
001-01072, Form 8-K dated March 12, 2014
4.2
001-01072, Form 8-K dated March 10, 2015
4.3
001-01072, Form 8-K dated May 22, 2017
001-01072, Form 8-K dated June 21, 2018
001-01072, Form 8-K dated June 13, 2019
001-01072, Form 8-K dated February 25,
2020
4.2
4.2
4.2
4.2
Exhibit No.
Description
4-40
4-41
4-41-1
Indenture, dated as of July 28, 1989, between Potomac Electric Power Company and The Bank of New York Mellon, Trustee, with respect
to Medium-Term Note Program (File No. 001-01072, Form 8-K dated June 21, 1990, Exhibit 4).
(a)
Senior Note Indenture, dated November 17, 2003 between Potomac Electric Power Company and The Bank of New York Mellon (File No.
001-01072, Form 8-K dated November 21, 2003, Exhibit 4.2).
Supplemental Indenture, dated March 31, 2008, to Senior Note Indenture between Potomac Electric Power Company and The Bank of
New York Mellon (File No. 001-01072, Form 10-K dated March 2, 2009, Exhibit 4.3).
408
Table of Contents
Exhibit No.
Description
4-42
Mortgage and Deed of Trust of Delaware Power & Light Company to The Bank of New York Mellon (ultimate successor to the New York
Trust Company), as trustee, dated as of October 1, 1943, and copies of the First through Sixty-Eighth Supplemental Indentures thereto
(File No. 33-1763, Registration Statement dated November 27, 1985, Exhibit 4-A)
(a)
4-42-1
Supplemental Indentures to Delmarva Power & Light Company Mortgage.
Dated as of
October 1, 1993
October 1, 1994
January 1, 1997
November 7, 2013
June 2, 2014
May 4, 2015
December 5, 2016
April 5, 2017
April 3, 2018
June 1, 2018
April 3, 2019
May 2, 2019
March 18, 2020
June 1, 2020
File Reference
Exhibit No.
33-53855, Registration Statement dated
January 30, 1995
(a)
33-53855, Registration Statement dated
January 30, 1995
(a)
001-01405, Form 10-K dated February 24,
2012
001-01405, Form 8-K dated November 8,
2013
001-01405, Form 8-K dated June 3, 2014
001-01405, Form 8-K dated May 5, 2015
001-01405, Form 8-K dated December 12,
2016
001-01405, Form 10-Q dated May 3, 2017
000-01405, Form 10-Q dated May 2, 2018
000-01405, Form 8-K dated June 21, 2018
001-01405, Form 10-Q dated May 2, 2019
001-01405, Form 8-K dated December 12,
2019
001-01405, Form 10-Q dated May 8, 2020
001-01405, Form 8-K dated June 9, 2020
4-L
4-N
4.4
4.2
4.3
4.2
4.2
4.5
4.3
4.2
4.2
4.2
4.4
4.4
409
Table of Contents
Exhibit No.
Description
4-43
4-44
Indenture between Delmarva Power & Light Company and The Bank of New York Mellon Trust Company, N.A. (ultimate successor to
Manufacturers Hanover Trust Company), as trustee, dated as of November 1, 1988 (File No. 33-46892, Registration Statement dated
April 1, 1992, Exhibit 4-G).
(a)
Mortgage and Deed of Trust, dated January 15, 1937, between Atlantic City Electric Company and The Bank of New York Mellon
(a)
(formerly Irving Trust Company), as trustee (File No. 2-66280, Registration Statement dated December 21, 1979, Exhibit 2(a)).
4-44-1
Supplemental Indentures to Atlantic City Electric Company Mortgage.
Dated as of
June 1, 1949
March 1, 1991
April 1, 2004
March 8, 2006
March 29, 2011
August 18, 2014
December 1, 2015
October 9, 2018
May 2, 2019
June 1, 2020
File Reference
2-66280, Registration Statement dated
December 21, 1979
(a)
Exhibit No.
2(b)
Form 10-K dated March 28, 1991
(a)
4(d)(1)
001-03559, Form 8-K dated April 6, 2004
4.3
001-03559, Form 8-K dated March 17,
2006
4
001-03559, Form 8-K dated April 1, 2011
4.2
001-03559, Form 8-K dated August 19,
2014
001-03559, Form 8-K dated December 2,
2015
001-03559, Form 8-K dated October 16,
2018
4.2
4.2
4.1
001-03559, Form 8-K dated May 21, 2019
4.3
001-03559, Form 8-K dated June 9, 2020
4.2
Exhibit No.
Description
4-45
4-46
4-47
4-48
Indenture, dated as of March 1, 1997, between Atlantic City Electric Company and The Bank of New York Mellon, as trustee (File No.
001-03559, Form 8-K dated March 24, 1997, Exhibit 4.2).
Senior Note Indenture, dated as of April 1, 2004, between Atlantic City Electric Company and The Bank of New York Mellon, as trustee
(File No. 001-03559, Form 8-K dated April 6, 2004, Exhibit 4.2).
Indenture, dated as of December 19, 2002 between Atlantic City Electric Transition Funding LLC and The Bank of New York Mellon, as
trustee (File No. 333-59558, Form 8-K dated December 23, 2002, Exhibit 4.1).
2002-1 Series Supplement, dated as of December 19, 2002 between Atlantic City Electric Transition Funding LLC and The Bank of New
York Mellon, as trustee (File No. 333-59558, Form 8-K dated December 23, 2002, Exhibit 4.2).
410
Table of Contents
Exhibit No.
Description
4-49
4-50
4-51
4-52
4-53
4-54
4-55
4-56
4-57
4-58
4-59
4-60
4-61
4-62
4-63
4-64
4-65
4-66
2003-1 Series Supplement, dated as of December 23, 2003 between Atlantic City Electric Transition Funding LLC and The Bank of New
York Mellon, as trustee (File No. 333-59558, Form 8-K dated December 23, 2003, Exhibit 4.2).
Indenture, dated September 6, 2002, between Pepco Holdings, Inc. and The Bank of New York Mellon, as trustee (File No. 333-100478,
Registration Statement on Form S-3 dated October 10, 2002, Exhibit 4.03).
Corporate Commercial Paper Master Note (File No. 001-31403, Form 10-K dated February 24, 2012, Exhibit 4.13).
Pepco Holdings, Inc. Certificate of Series A Non-Voting Non-Convertible Preferred Stock (File No. 001-31403, Form 8-K dated April 30,
2014, Exhibit 3.1).
Form of 2.400% notes due 2026 (File No. 001-01910, Form 8-K dated August 18, 2016, Exhibit 4.1).
Form of 3.500% notes due 2046 (File No. 001-01910, Form 8-K dated August 18, 2016, Exhibit 4.2).
Form of Exelon Generation Company, LLC 2.950% senior notes due 2020 (File No. 333-85496, Form 8-K dated March 10, 2017, Exhibit
4.1).
Form of Exelon Generation Company, LLC 3.400% notes due 2022 (File No. 333-85496, Form 8-K dated March 10, 2017, Exhibit 4.2).
Second Supplemental Indenture, dated April 3, 2017, between Exelon and The Bank of New York Mellon Trust Company, N.A., as
trustee, to that certain Indenture (For Unsecured Subordinated Debt Securities), dated June 17, 2014 (File No. 001-16169, Form 8-K
dated April 4, 2017, Exhibit 4.3).
Form of Exelon Corporation 3.497% junior subordinated notes due 2022 (File No. 001-16169, Form 8-K dated April 4, 2017, Exhibit 4.4).
Form of First Mortgage Bond, 4.15% Series due March 15, 2043 (File No. 001-01072, Form 8-K dated May 22, 2017, Exhibit 4.2).
BGE Form of 3.750% notes due 2047 (File No. 001-01910, Form 8-K dated August 24, 2017, Exhibit 4.1).
Exempt Facilities Loan Agreement dated as of June 1, 2019 between the Maryland Economic Development Corporation and Potomac
Electric Power Company (File No. 001-01072, Form 8-K dated June 27, 2019, Exhibit 4.1).
Indenture, dated as of September 1, 2019, between Baltimore Gas and Electric Company and U.S. Bank National Association, as trustee
(File No. 001-01910, Form 8-K dated September 12, 2019, Exhibit 4.1).
Description of Exelon Securities (File No. 001-16169, Form 10-K dated February 11, 2020, Exhibit 4.63).
Description of PECO Securities (File No. 001-16169, Form 10-K dated February 11, 2020, Exhibit 4.64).
Description of ComEd Securities (File No. 001-16169, Form 10-K dated February 11, 2020, Exhibit 4.65).
Fourth Supplemental Indenture, dated as of April 1, 2020, among Exelon Corporation and The Bank of New York Mellon Trust Company,
N.A., as trustee (File No. 001-16169, Form 8-K dated April 1, 2020, Exhibit 4.2).
411
Table of Contents
Exhibit No.
Description
4-67
4-68
4-69
10-1
10-2
10-3
10-4
10-5
10-6
10-7
10-8
10-9
10-10
10-11
10-12
10-13
10-14
10-15
Form of Exelon Generation Company LLC 3.250% Senior Notes due 2025 (File No. 333-85496, Form 8-K dated May 15, 2020, Exhibit
4.1).
Pollution Control Facilities Loan Agreement, dated as of June 1, 2020, between The Pollution Control Financing Authority of Salem
County and Atlantic City Electric (File No. 001-03559, Form 8-K dated June 2, 2020, Exhibit 4.1).
Gas Facilities Loan Agreement, dated as of July 1, 2020, between The Delaware Economic Development Authority and Delmarva Power
(File No. 001-01405, Form 8-K dated July 1, 2020, Exhibit 4.1).
Exelon Corporation Non-Employee Directors’ Deferred Stock Unit Plan (As Amended and Restated Effective April 28, 2020). (File No.
001-16169, Form 10-Q dated August 4, 2020, Exhibit 10.1).
Form of Exelon Corporation Unfunded Deferred Compensation Plan for Directors (as amended and restated Effective March 12, 2012) *
(File No. 001-16169, Form 10-K dated February 10, 2016, Exhibit 10.3).
Form of Restricted Stock Award Agreement under the Exelon Corporation Long-Term Incentive Plan* (File No. 1-16169, Form 10-Q dated
October 31, 2019, Exhibit 10.2).
Unicom Corporation Deferred Compensation Unit Plan, as amended (File No. 001-11375, Form 10-K dated March 29, 1996, Exhibit
10.12).
Amendment Number One to the Unicom Corporation Deferred Compensation Unit Plan, as amended January 1, 2008 * (File No. 001-
16169, Form 10-K dated February 6, 2009, Exhibit 10.16).
Exelon Corporation Supplemental Management Retirement Plan (As Amended and Restated Effective January 1, 2009) * (File No. 001-
16169, Form 10-K dated February 6, 2009, Exhibit 10.19).
PECO Energy Company Supplemental Pension Benefit Plan (As Amended and Restated Effective January 1, 2009) (File No. 000-16844,
Form 10-K dated February 6, 2009, Exhibit 10.20).
Exelon Corporation Annual Incentive Plan for Senior Executives (As Amended Effective January 1, 2014 * (File No. 001-16169, Proxy
Statement dated April 1, 2014, Appendix A).
Exelon Corporation Employee Stock Purchase Plan, as amended and restated effective September 25, 2019 (File No. 001-16169, Form
10-Q dated October 31, 2019, Exhibit 10.3).
Exelon Corporation 2006 Long-Term Incentive Plan (Registration Statement No. 333-122704, Form S-4, Joint Proxy Statement-
Prospectus pursuant to Rule 424(b)(3) filed June 3, 2005, Annex H).
Form of Stock Option Grant Instrument under the Exelon Corporation 2006 Long-Term Incentive Plan (File No. 001-16169, Form 8-K
dated January 27, 2006, Exhibit 99.2).
Exelon Corporation Employee Stock Purchase Plan for Unincorporated Subsidiaries, as amended and restated effective September 25,
2019 (File No. 001-16169, Form 10-Q dated October 31, 2019, Exhibit 10.4).
Exelon Corporation Senior Management Severance Plan (As Amended and Restated Effective January 1, 2020) * (File No. 001-16169,
Form 10-K dated February 11, 2020, Exhibit 10.13).
Exelon Corporation Executive Death Benefits Plan dated as of January 1, 2003 * (File No. 001-16169, Form 10-K dated February 13,
2007, Exhibit 10.52).
First Amendment to Exelon Corporation Executive Death Benefits Plan, Effective January 1, 2006 * (File No. 001-16169, Form 10-K
dated February 13, 2007, Exhibit 10.53).
412
Table of Contents
Exhibit No.
Description
10-16
10-17
10-18
10-19
10-20
10-20-1
10-20-2
10-21
10-22
10-23
10-24
10-25
10-26
10-27
10-28
10-29
10-30
Amendment Number One to the Exelon Corporation 2006 Long-Term Incentive Plan, Effective December 4, 2006 (File No. 001-16169,
Form 10-K dated February 13, 2007, Exhibit 10.54).
Exelon Corporation Deferred Compensation Plan (As Amended and Restated Effective January 1, 2005) (File No. 001-16169, Form 10-K
dated February 13, 2007, Exhibit 10.56).
Exelon Corporation Stock Deferral Plan (As Amended and Restated Effective September 25, 2019) (File No. 001-16169, Form 10-Q
dated October 31, 2019, Exhibit 10.5).
Restricted stock unit award agreement (File 001-16169, Form 8-K dated August 31, 2007, Exhibit 99.1).
Form of Exelon Corporation 2011 Long-Term Incentive Plan, as amended effective December 18, 2014. * (File No. 001-16169, Form 10-K
dated February 10, 2016, Exhibit 10.34).
Form of Exelon Corporation Long-Term Incentive Program, as amended and restated as of January 1, 2020. * (File No. 001-16169, Form
10-K dated February 11, 2020, Exhibit 10.21).
Amendment Number Two to the Exelon Corporation 2011 Long-Term Incentive Plan (As Amended and Restated Effective January 21,
2014), Effective October 26, 2015. * (File No. 001-16169, Form 10-K dated February 10, 2016, Exhibit 10.34.3).
Form of Separation Agreement under Exelon Corporation Senior Management Severance Plan (As Amended and Restated Effective
January 1, 2020) (File No. 001-16169, Form 10-K dated February 11, 2020, Exhibit 10.21).
Credit Agreement for $500,000,000 dated as of March 23, 2011 between Exelon Corporation and Various Financial Institutions (File No.
001-16169, Form 8-K dated March 23, 2011, Exhibit 99.1).
Credit Agreement for $5,300,000,000 dated as of March 23, 2011 between Exelon Generation Company, LLC and Various Financial
Institutions (File No. 333-85496, Form 8-K dated March 23, 2011, Exhibit 99.2).
Credit Agreement for $600,000,000 dated as of March 23, 2011 between PECO Energy Company and Various Financial Institutions (File
No. 000-16844, Form 8-K dated March 23, 2011, Exhibit 99.3).
Credit Agreement dated as of March 28, 2012 among Commonwealth Edison Company, Various Financial Institutions, as Lenders, and
JP Morgan Chase Bank, N.A., as Administrative Agent (File No. 001-01839, Form 8-K dated March 28, 2012, Exhibit 99.1).
Amendment No. 3 to Credit Agreement dated as of March 23, 2011 among Exelon Corporation, as Borrower, the various financial
institutions named therein, as Lenders, and JPMorgan Chase Bank, N.A., as Administrative Agent (File No. 001-16169, Form 8-K dated
August 10, 2013, Exhibit 99.1).
Amendment No. 1 to Credit Agreement dated as of March 28, 2012 among Commonwealth Edison Company, as Borrower, the various
financial institutions named therein, as Lenders and JPMorgan Chase Bank, N.A., as Administrative Agent (File No. 001-1839, Form 8-K
dated August 10, 2013, Exhibit 99.2).
Amendment No. 1 to Credit Agreement, dated as of December 21, 2011, to the Credit Agreement dated as of March 23, 2011, among
Exelon Generation Company, LLC, the lenders party thereto and JPMorgan Chase Bank, N.A., as Administrative Agent (File No. 001-
16169, Form 8-K dated March 14, 2012, Exhibit 4.6).
Constellation Energy Group, Inc. Nonqualified Deferred Compensation Plan, as amended and restated. * (File No. 001-12869, Form 10-K
dated February 27, 2009, Exhibit 10(b)).
Constellation Energy Group, Inc. Deferred Compensation Plan for Non-Employee Directors, as amended and restated. * (File No. 001-
12869, Form 10-K dated February 27, 2009, Exhibit 10(c)).
413
Table of Contents
Exhibit No.
Description
10-31
10-32
10-33
10-34
10-35
10-36
10-37
10-38
10-39
10-40
10-41
10-42-1
10-42-2
10-42-3
10-42-4
Constellation Energy Group, Inc. Benefits Restoration Plan, amended and restated effective June 1, 2010. * (File No. 001-12869, Form
10-Q dated August 6, 2010, Exhibit 10(b)).
Constellation Energy Group, Inc. Supplemental Pension Plan, as amended and restated. * (File No. 001-12869, Form 10-K dated
February 27, 2009, Exhibit 10(e)).
Constellation Energy Group, Inc. Senior Executive Supplemental Plan, as amended and restated. * (File No. 001-12869, Form 10-K dated
February 27, 2009, Exhibit 10(f)).
Constellation Energy Group, Inc. Executive Supplemental Benefits Plan, as amended and restated. * (File No. 001-12869, Form 10-Q
dated August 11, 2008, Exhibit No. 10(a)).
Constellation Energy Group, Inc. Amended and Restated 2007 Long-Term Incentive Plan. * (File No. 001-12869, Form 8-K dated June 4,
2010, Exhibit 10.1).
Second Amended and Restated Operating Agreement, dated as of November 6, 2009, by and among Constellation Energy Nuclear
Group, LLC, Constellation Nuclear, LLC, CE Nuclear, LLC, EDF Development Inc., and for certain limited purposes, E.D.F. International
S.A. and Constellation Energy Group, Inc. (File No. 001-12869, Form 8-K dated November 12, 2009, Exhibit 10.1).
Amendment No. 1 to the Second Amended and Restated Operating Agreement of Constellation Energy Nuclear Group, LLC, by and
among Constellation Nuclear, LLC, CE Nuclear, LLC, EDF Inc. (formerly known as EDF Development, Inc.), and E.D.F. International S.A.
(File No. 001-12869, Form 10-K dated March 3, 2011, Exhibit 10(s)).
Amendment No. 2 to the Second Amended and Restated Operating Agreement of Constellation Energy Nuclear Group, LLC, by and
among Constellation Nuclear, LLC, CE Nuclear, LLC, EDF Inc. (formerly known as EDF Development, Inc.), and E.D.F. International S.A.
(File No. 001-12869, Form 10-K dated March 3, 2011, Exhibit 10(t)).
Amendment No. 3 to the Second Amended and Restated Operating Agreement of Constellation Energy Nuclear Group, LLC, by and
among Constellation Nuclear, LLC, CE Nuclear, LLC, EDF Inc. (formerly known as EDF Development, Inc.), and E.D.F. International S.A.
(File No. 001-12869, Form 8-K dated November 3, 2010, Exhibit 10.1).
Termination Agreement dated as of November 3, 2010, by and among EDF Inc. (formerly known as EDF Development, Inc.), E.D.F.
International S.A., and Constellation Energy Group, Inc. (File No. 001-12869, Form 8-K dated November 3, 2010, Exhibit 10.2).
Settlement Agreement between EDF Inc., Exelon Corporation, Exelon Energy Delivery Company, LLC, Constellation Energy Group, Inc.
and Baltimore Gas and Electric Company dated January 16, 2012. (File No. 001-12869, Form 8-K dated January 19, 2012, Exhibit 10.1).
Confirmation of Base Issuer Forward Transaction, dated June 11, 2014, between Exelon Corporation and Barclays Capital, Inc., acting as
Agent for Barclays Bank PLC (File No. 001-16169, Form 8-K dated June 17, 2014, Exhibit 10.1).
Confirmation of Base Issuer Forward Transaction, dated June 11, 2014, between Exelon Corporation and Goldman Sachs & Co. (File No.
001-16169, Form 8-K dated June 17, 2014, Exhibit 10.2).
Confirmation of Additional Issuer Forward Transaction, dated June 13, 2014, between Exelon Corporation and Barclays Capital, Inc.,
acting as Agent for Barclays Bank PLC (File No. 001-16169, Form 8-K dated June 17, 2014, Exhibit 10.3).
Confirmation of Additional Issuer Forward Transaction, dated June 13, 2014, between Exelon Corporation and Goldman Sachs & Co.
(File No. 001-16169, Form 8-K dated June 17, 2014, Exhibit 10.4).
414
Table of Contents
Exhibit No.
Description
10-43
10-44
10-45
10-46
10-47
10-48
10-49
10-50
10-51
10-52
10-52-1
10-52-2
Bondable Transition Property Sale Agreement, dated as of December 19, 2002, between ACE Funding and ACE (File No. 333-59558,
Form 8-K dated December 23, 2002, Exhibit 10.1).
Bondable Transition Property Servicing Agreement, dated as of December 19, 2002, between ACE Funding and ACE (File No. 333-
59558, Form 8-K dated December 23, 2002, Exhibit 10.2).
Purchase Agreement, dated as of April 20, 2010, by and among Pepco Holdings, Inc., Conectiv, LLC, Conectiv Energy Holding Company,
LLC and New Development Holdings, LLC (File No. 001-31403, Form 8-K dated July 8, 2010, Exhibit 2.1).
Purchase Agreement, dated March 9, 2015, among Potomac Electric Power Company and BNY Mellon Capital Markets, LLC, Morgan
Stanley & Co. LLC, and RBS Securities Inc., as representatives of the several underwriters named therein (File No. 001-01072, Form 8-K
dated March 10, 2015, Exhibit 1.1).
Purchase Agreement, May 4, 2015, among Delmarva Power & Light Company and J.P. Morgan Securities LLC, Merrill Lynch, Pierce,
Fenner & Smith Incorporated, and Scotia Capital (USA) Inc., as representatives of the several underwriters named therein (File No. 001-
01405, Form 8-K dated May 5, 2015, Exhibit 1.1).
Bond Purchase Agreement, dated December 1, 2015, among Atlantic City Electric Company and the purchasers signatory thereto (File
No. 001-03559, Form 8-K dated December 2, 2015, Exhibit 1.1).
$300,000,000 Term Loan Agreement by and among PHI, The Bank of Nova Scotia, as Administrative Agent, and the lenders party
thereto, dated July 30, 2015 (File No. 001-31403, Form 8-K dated July 30, 2015, Exhibit 10).
First Amendment to Term Loan Agreement, dated as of October 29, 2015, by and among PHI, The Bank of Nova Scotia, as
Administrative Agent, and the lenders party thereto (File No. 001-31403, Form 8-K dated October 29, 2015, Exhibit 10.2).
$500,000,000 Term Loan Agreement by and among PHI, The Bank of Nova Scotia, as Administrative Agent, and the lenders party
thereto, dated January 13, 2016 (File No. 001-31403, Form 8-K dated January 14, 2016, Exhibit 10).
Second Amended and Restated Credit Agreement, dated as of August 1, 2011, by and among Pepco Holdings, Inc., Potomac Electric
Power Company, Delmarva Power & Light Company and Atlantic City Electric Company, the lenders party thereto, Wells Fargo Bank,
National Association, as agent, issuer and swingline lender, Bank of America, N.A., as syndication agent and issuer, The Royal Bank of
Scotland plc and Citicorp USA, Inc., as co-documentation agents, Wells Fargo Securities, LLC and Merrill Lynch, Pierce, Fenner and
Smith Incorporated, as active joint lead arrangers and joint book runners, and Citigroup Global Markets Inc. and RBS Securities, Inc. as
passive joint lead arrangers and joint book runners (File No. 001-31403, Form 10-Q dated August 3, 2011, Exhibit 10.1).
First Amendment, dated as of August 2, 2012, to Second Amended and Restated Credit Agreement, dated as of August 1, 2011, by and
among Pepco Holdings, Inc., Potomac Electric Power Company, Delmarva Power & Light Company and Atlantic City Electric Company,
the various financial institutions party thereto, Wells Fargo Bank, National Association, as agent, issuer of letters of credit and swingline
lender, Bank of America, N.A., as syndication agent and issuer of letters of credit, and The Royal Bank of Scotland plc and Citibank, N.A.,
as co-documentation agents (File No. 001-31403, Form 10-K dated March 1, 2013, Exhibit 10.25.1).
Amendment and Consent to Second Amended and Restated Credit Agreement, dated as of May 20, 2014, by and among Pepco
Holdings, Inc., Potomac Electric Power Company, Delmarva Power & Light Company and Atlantic City Electric Company, the various
financial institutions from time to time party thereto, Bank of America, N.A. and Wells Fargo Bank, National Association (File No. 001-
31403, Form 8-K dated May 20, 2014, Exhibit 10.1).
415
Table of Contents
Exhibit No.
Description
10-52-3
10-52-4
10-53
10-53-1
10-53-2
10-54
10-55
10-56
10-57
10-58
10-59
10-60
Third Amendment to Second Amended and Restated Credit Agreement, dated as of May 1, 2015, by and among Pepco Holdings, Inc.,
Potomac Electric Power Company, Delmarva Power & Light Company and Atlantic City Electric Company, the various financial institutions
from time to time party thereto, Bank of America, N.A. and Wells Fargo Bank, National Association (File No. 001-31403, Form 8-K dated
May 1, 2015, Exhibit 10.1).
Consent, dated as of October 29, 2015, by and among Pepco Holdings, Inc., Potomac Electric Power Company, Delmarva Power & Light
Company and Atlantic City Electric Company, the various financial institutions from time to time party thereto, Bank of America, N.A. and
Wells Fargo Bank, National Association (File No. 001-31403, Form 8-K dated October 29, 2015, Exhibit 10.1).
Asset Purchase and Sale Agreement for Generating Plants and Related Assets, dated as of June 7, 2000, by and between Pepco and
Southern Energy, Inc. (File No. 001-01072, Form 8-K dated June 13, 2000, Exhibit 10).
Amendment No. 1 to the Asset Purchase and Sale Agreement for Generating Plants and Related Assets, dated September 18, 2000, by
and between Potomac Electric Power Company and Southern Energy, Inc. (File No. 001-01072, Form 8-K dated December 19, 2000,
Exhibit 10.1).
Amendment No. 2 to the Asset Purchase and Sale Agreement for Generating Plants and Related Assets, dated December 19, 2000, by
and between Potomac Electric Power Company and Southern Energy, Inc. (File No. 001-01072, Form 8-K dated December 19, 2000,
Exhibit 10.2).
First Amendment to Loan Agreement, by and between Pepco Holdings LLC and The Bank of Nova Scotia, as administrative agent and
lender, dated March 28, 2016 (File No. 001-31403, Form 8-K dated March 28, 2016, Exhibit 10).
Amendment No. 7 to Credit Agreement, dated as of March 23, 2011, among Exelon Corporation, as Borrower, the various financial
institutions named therein, as Lenders, and JPMorgan Chase Bank, N.A., as Administrative Agent (File No. 001-16169, Form 8-K dated
May 27, 2016, Exhibit 99.1).
Amendment No. 7 to Credit Agreement, dated as of March 23, 2011, among Exelon Generation Company, LLC, as Borrower, the various
financial institutions named therein, as Lenders, and JPMorgan Chase Bank, N.A., as Administrative Agent (File No. 333-85496, Form 8-
K dated May 27, 2016, Exhibit 99.2).
Amendment No. 4 to Credit Agreement, dated as of March 23, 2011, among Commonwealth Edison Company, as Borrower, the various
financial institutions named therein, as Lenders, and JPMorgan Chase Bank, N.A., as Administrative Agent (File No. 333-85496, Form 8-
K dated May 27, 2016, Exhibit 99.3).
Amendment No. 6 to Credit Agreement, dated as of March 23, 2011, among PECO Energy Company, as Borrower, the various financial
institutions named therein, as Lenders, and JPMorgan Chase Bank, N.A., as Administrative Agent (File No. 000-16844, Form 8-K dated
May 27, 2016, Exhibit 99.4).
Amendment No. 5 to Credit Agreement, dated as of March 23, 2011, among Baltimore Gas and Electric Company, as Borrower, the
various financial institutions named therein, as Lenders, and JPMorgan Chase Bank, N.A., as Administrative Agent (File No. 001-01910,
Form 8-K dated May 27, 2016, Exhibit 99.5).
Fourth Amendment to Second Amended and Restated Credit Agreement, dated as of August 1, 2011, among Pepco Holdings LLC,
Potomac Electric Power Company, Delmarva Power & Light Company and Atlantic City Electric Company, as Borrowers, the various
financial institutions named therein, as Lenders, and Wells Fargo Bank, National Association, as Administrative Agent (File No. 001-
31403, Form 8-K dated May 27, 2016, Exhibit 99.6).
416
Table of Contents
Exhibit No.
Description
10-61
10-62
10-63
10-64
10-65
10-66
10-67
10-68
10.69
10.70
10.71
10.72
10.73
10.74
10.75
10.76
2016 Form of Exelon Corporation Change in Control Agreement (File No. 001-16169, Form 10-Q dated October 26, 2016, Exhibit 10.1).
Execution Version-ZEC Standard Contract by and between the NYSERDA and Nine Mile Point Nuclear Station, LLC dated Nov. 18, 2016
(File No. 001-16169, Form 8-K dated November 18, 2016, Exhibit 10.1).
Execution Version-ZEC Standard Contract by and between the NYSERDA and R. E. Ginna Nuclear Power Plant, LLC dated Nov. 18,
2016 (File No. 001-16169, Form 8-K dated November 18, 2016, Exhibit 10.2).
Credit Agreement, dated as of November 28, 2017, as thereafter amended and conformed among ExGen Renewables IV, LLC, ExGen
Renewables IV Holding, LLC, Morgan Stanley Senior Funding, Inc. as administrative agent, Wilmington Trust, National Association, as
depository bank and collateral agent, and the lenders and other agents party thereto. (Certain portions of this exhibit have been omitted
by redacting a portion of text, as indicated by asterisks in the text. This exhibit has been filed separately with the U.S. Securities and
Exchange Commission pursuant to a request for confidential treatment.) (File No. 001-16169, Form 10-K dated February 9, 2018, Exhibit
10.94).
Purchase Agreement, dated June 8, 2018 among Delmarva Power & Light Company and the purchasers signatory thereto (File No. 001-
01405, Form 8-K dated June 21, 2018, Exhibit 1.1).
Purchase Agreement, dated June 8, 2018, among Potomac Electric Power Company and the purchasers signatory thereto (File No. 001-
01072, Form 8-K dated June 21, 2018, Exhibit 1.1).
Letter Agreement, dated May 7, 2018, between Exelon Corporation and Denis P. O’Brien (File No. 001-16169, Form 10-Q dated August
2, 2018, Exhibit 10.3).
Letter Agreement, dated May 7, 2018, between Exelon Corporation and Jonathan W. Thayer (File No. 001-16169, Form 10-Q dated
August 2, 2018, Exhibit 10.4).
Exelon Corporation 2020 Long-Term Incentive Plan (Effective April 28, 2020) (File No. 001-16169, Proxy Statement dated March 18,
2020, Appendix A).
Exelon Corporation 2020 Long-Term Incentive Plan Prospectus, dated May 27, 2020 (File No. 001-16169, Form 10-Q dated August 4,
2020, Exhibit 10.3).
Form of Restricted Stock Unit Award Notice and Agreement under the Exelon Corporation 2020 Long-Term Incentive Plan (File No. 001-
16169, Form 10-Q dated August 4, 2020, Exhibit 10.4).
Form of Performance Share Award Notice and Agreement under the Exelon Corporation 2020 Long-Term Incentive Plan (File No. 001-
16169, Form 10-Q dated August 4, 2020, Exhibit 10.5).
Receivables Purchase Agreement, dated as of April 8, 2020, among Constellation NewEnergy, Inc. as servicer, and NewEnergy
Receivables LLC, as seller, MUFG Bank, LTD., as Agent, the Conduits party thereto, the Financial Institutions party thereto and the
Purchaser Agents party thereto (File No. 001-16169, Form 8-K dated April 9, 2020, Exhibit 10.1).
Letter Agreement, dated Jun 4, 2020, between Exelon Corporation and William A. Von Hoene, Jr.**
Deferred Prosecution Agreement, dated July 17, 2020, between Commonwealth Edison Company and the U.S. Department of Justice
and the U.S. Attorney for the Northern District of Illinois (File No. 001-16169, Form 8-K dated July 17, 2020, Exhibit 10.1).
Credit Agreement, among ExGen Renewables IV, LLC, the lenders party thereto, Jefferies Finance LLC, as administrative agent, and
Wilmington Trust, National Association, as depositary ban and collateral agent, dated December 15, 2020 (File No. 333-85496, Form 8-K
dated December 15, 2020, Exhibit 1.1).
417
Table of Contents
Exhibit No.
Description
14
Exelon Code of Conduct, as amended March 12, 2012 (File No. 1-16169, Form 8-K dated March 14, 2012, Exhibit No. 14-1).
21-1
21-2
21-3
21-4
21-5
21-6
21-7
21-8
21-9
23-1
23-2
23-3
23-4
23-5
23-6
23-7
23-8
24-1
24-2
24-3
24-4
24-5
24-6
24-7
24-8
24-9
24-10
24-11
24-12
24-13
Subsidiaries
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
Atlantic City Electric Company
Consent of Independent Registered Public Accountants
Exelon Corporation
Exelon Generation Company, LLC
Commonwealth Edison Company
PECO Energy Company
Baltimore Gas and Electric Company
Potomac Electric Power Company
Delmarva Power & Light Company
Atlantic City Electric Company
Power of Attorney (Exelon Corporation)
Anthony K. Anderson
Ann C. Berzin
Laurie Brlas
Christopher M. Crane
Yves C. de Balmann
Nicholas DeBenedictis
Linda P. Jojo
Paul Joskow
Robert J. Lawless
Marjorie Rodgers Cheshire
Reserved.
Mayo A. Shattuck III
Reserved.
418
Table of Contents
Exhibit No.
Description
24-14
24-15
24-16
24-17
24-18
24-19
24-20
24-21
24-22
24-23
24-24
24-25
24-26
24-27
24-28
24-29
24-30
24-31
24-32
24-33
24-34
24-35
24-36
24-37
24-38
24-39
24-40
24-41
24-42
John F. Young
John Richardson
Power of Attorney (Commonwealth Edison Company)
James W. Compton
Christopher M. Crane
A. Steven Crown
Nicholas DeBenedictis
Joseph Dominguez
Peter V. Fazio, Jr.
Michael H. Moskow
Calvin G. Butler
Reserved.
Power of Attorney (PECO Energy Company)
Christopher M. Crane
Reserved.
Nicholas DeBenedictis
Nelson A. Diaz
John S. Grady
Rosemarie B. Greco
Michael A. Innocenzo
Charisse R. Lillie
Calvin G. Butler
Power of Attorney (Baltimore Gas and Electric Company)
Ann C. Berzin
Carim V. Khouzami
Christopher M. Crane
Michael E. Cryor
James R. Curtiss
Joseph Haskins, Jr.
Calvin G. Butler
Michael D. Sullivan
Maria Harris Tildon
Power of Attorney (Pepco Holdings LLC)
24-43
Christopher M. Crane
419
Table of Contents
Exhibit No.
Description
24-44
24-45
24-46
24-47
24-48
24-49
24-50
24-51
24-52
24-53
24-54
24-55
24-56
24-57
24-58
Linda W. Cropp
Michael E. Cryor
Ernest Dianastasis
Debra P. DiLorenzo
Calvin G. Butler
David M. Velazquez
Power of Attorney (Potomac Electric Power Company)
J. Tyler Anthony
Phillip S. Barnett
Christopher M. Crane
Melissa A. Lavinson
Kevin M. McGowan
Calvin G. Butler
David M. Velazquez
Power of Attorney (Delmarva Power & Light Company)
Calvin G. Butler
David M. Velazquez
Power of Attorney (Atlantic City Electric Company)
24-59
David M. Velazquez
Certifications Pursuant to Rule 13a-14(a) and 15d-14(a) of the Securities and Exchange Act of 1934 as to the Annual Report on Form 10-K for the year
ended December 31, 2020 filed by the following officers for the following registrants:
Exhibit No.
Description
31-1
31-2
31-3
31-4
31-5
31-6
31-7
31-8
31-9
31-10
31-11
31-12
Filed by Christopher M. Crane for Exelon Corporation
Filed by Joseph Nigro for Exelon Corporation
Filed by Christopher M. Crane for Exelon Generation Company, LLC
Filed by Bryan P. Wright for Exelon Generation Company, LLC
Filed by Joseph Dominguez for Commonwealth Edison Company
Filed by Jeanne M. Jones for Commonwealth Edison Company
Filed by Michael A. Innocenzo for PECO Energy Company
Filed by Robert J. Stefani for PECO Energy Company
Filed by Carim V. Khouzami for Baltimore Gas and Electric Company
Filed by David M. Vahos for Baltimore Gas and Electric Company
Filed by David M. Velazquez for Pepco Holdings LLC
Filed by Phillip S. Barnett for Pepco Holdings LLC
420
Table of Contents
Exhibit No.
Description
31-13
31-14
31-15
31-16
31-17
31-18
Filed by David M. Velazquez for Potomac Electric Power Company
Filed by Phillip S. Barnett for Potomac Electric Power Company
Filed by David M. Velazquez for Delmarva Power & Light Company
Filed by Phillip S. Barnett for Delmarva Power & Light Company
Filed by David M. Velazquez for Atlantic City Electric Company
Filed by Phillip S. Barnett for Atlantic City Electric Company
Certifications Pursuant to Section 1350 of Chapter 63 of Title 18 United States Code as to the Annual Report on Form 10-K for the year ended December
31, 2020 filed by the following officers for the following registrants:
Exhibit No.
Description
32-1
32-2
32-3
32-4
32-5
32-6
32-7
32-8
32-9
32-10
32-11
32-12
32-13
32-14
32-15
32-16
32-17
32-18
Filed by Christopher M. Crane for Exelon Corporation
Filed by Joseph Nigro for Exelon Corporation
Filed by Christopher M. Crane for Exelon Generation Company, LLC
Filed by Bryan P. Wright for Exelon Generation Company, LLC
Filed by Joseph Dominguez for Commonwealth Edison Company
Filed by Jeanne M. Jones for Commonwealth Edison Company
Filed by Michael A. Innocenzo for PECO Energy Company
Filed by Robert J. Stefani for PECO Energy Company
Filed by Carim V. Khouzami for Baltimore Gas and Electric Company
Filed by David M. Vahos for Baltimore Gas and Electric Company
Filed by David M. Velazquez for Pepco Holdings LLC
Filed by Phillip S. Barnett for Pepco Holdings LLC
Filed by David M. Velazquez for Potomac Electric Power Company
Filed by Phillip S. Barnett for Potomac Electric Power Company
Filed by David M. Velazquez for Delmarva Power & Light Company
Filed by Phillip S. Barnett for Delmarva Power & Light Company
Filed by David M. Velazquez for Atlantic City Electric Company
Filed by Phillip S. Barnett for Atlantic City Electric Company
101.INS
Inline 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.SCH
Inline XBRL Taxonomy Extension Schema Document.
101.CAL
Inline XBRL Taxonomy Extension Calculation Linkbase Document.
101.DEF
Inline XBRL Taxonomy Extension Definition Linkbase Document.
101.LAB
Inline 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)
421
Table of Contents
__________
* Compensatory plan or arrangements in which directors or officers of the applicable registrant participate and which are not available to all employees.
** Filed herewith.
(a) These filings are not available electronically on the SEC website as they were filed in paper previous to the electronic system that is currently in place.
422
Table of Contents
ITEM 16.
FORM 10-K SUMMARY
All Registrants
Registrants may voluntarily include a summary of information required by Form 10-K under this Item 16. The Registrants have elected not to include such
summary information.
423
Table of Contents
Pursuant to the requirements of Section 13 or 15(d) of the Securities Exchange Act of 1934, the Registrant has duly caused this report to be signed on its
behalf by the undersigned, thereunto duly authorized, in the City of Chicago and State of Illinois on the 24th day of February, 2021.
SIGNATURES
EXELON CORPORATION
By:
Name:
Title:
/s/ CHRISTOPHER M. CRANE
Christopher M. Crane
President and Chief Executive Officer
Pursuant to the requirements of the Securities Exchange Act of 1934, this report has been signed by the following persons on behalf of the Registrant and in
the capacities indicated on the 24th day of February, 2021.
Signature
Title
/s/ CHRISTOPHER M. CRANE
Christopher M. Crane
/s/ JOSEPH NIGRO
Joseph Nigro
/s/ FABIAN E. SOUZA
Fabian E. Souza
President, Chief Executive Officer (Principal Executive Officer) and Director
Senior Executive Vice President and Chief Financial Officer (Principal
Financial Officer)
Senior Vice President and Corporate Controller (Principal Accounting
Officer)
This annual report has also been signed below by Gayle E. Littleton, Attorney-in-Fact, on behalf of the following Directors on the date indicated:
Anthony K. Anderson
Ann C. Berzin
Laurie Brlas
Yves C. de Balmann
Nicholas DeBenedictis
Linda P. Jojo
Paul L. Joskow
Robert J. Lawless
John M. Richardson
Marjorie Rodgers Cheshire
Mayo A. Shattuck III
John F. Young
By:
Name:
/s/ GAYLE E. LITTLETON
Gayle E. Littleton
February 24, 2021
424
Table of Contents
Pursuant to the requirements of Section 13 or 15(d) of the Securities Exchange Act of 1934, the Registrant has duly caused this report to be signed on its
behalf by the undersigned, thereunto duly authorized, in the City of Chicago and State of Illinois on the 24th day of February, 2021.
SIGNATURES
EXELON GENERATION COMPANY, LLC
By:
Name:
Title:
/s/ CHRISTOPHER M. CRANE
Christopher M. Crane
Principal Executive Officer
Pursuant to the requirements of the Securities Exchange Act of 1934, this report has been signed by the following persons on behalf of the Registrant and in
the capacities indicated on the 24th day of February, 2021.
/s/ CHRISTOPHER M. CRANE
Christopher M. Crane
/s/ BRYAN P. WRIGHT
Bryan P. Wright
/s/ MATTHEW N. BAUER
Matthew N. Bauer
Signature
Title
Principal Executive Officer
Senior Vice President and Chief Financial Officer (Principal Financial
Officer)
Vice President and Controller (Principal Accounting Officer)
425
Table of Contents
Pursuant to the requirements of Section 13 or 15(d) of the Securities Exchange Act of 1934, the Registrant has duly caused this report to be signed on its
behalf by the undersigned, thereunto duly authorized, in the City of Chicago and State of Illinois on the 24th day of February, 2021.
SIGNATURES
COMMONWEALTH EDISON COMPANY
By:
Name:
Title:
/s/ JOSEPH DOMINGUEZ
Joseph Dominguez
Chief Executive Officer
Pursuant to the requirements of the Securities Exchange Act of 1934, this report has been signed by the following persons on behalf of the Registrant and in
the capacities indicated on the 24th day of February, 2021.
Signature
Title
/s/ JOSEPH DOMINGUEZ
Joseph Dominguez
/s/ JEANNE M. JONES
Jeanne M. Jones
/s/ STEVEN J. CICHOCKI
Steven J. Cichocki
Chief Executive Officer (Principal Executive Officer) and Director
Senior Vice President, Chief Financial Officer and Treasurer (Principal
Financial Officer)
Director, Accounting (Principal Accounting Officer)
This annual report has also been signed below by Joseph Dominguez, Attorney-in-Fact, on behalf of the following Directors on the date indicated:
Calvin G. Butler
James W. Compton
Christopher M. Crane
A. Steven Crown
By:
Name:
/s/ JOSEPH DOMINGUEZ
Joseph Dominguez
Nicholas DeBenedictis
Peter V. Fazio, Jr.
Michael H. Moskow
426
February 24, 2021
Table of Contents
Pursuant to the requirements of Section 13 or 15(d) of the Securities Exchange Act of 1934, the Registrant has duly caused this report to be signed on its
behalf by the undersigned, thereunto duly authorized, in the City of Chicago and State of Illinois on the 24th day of February, 2021.
SIGNATURES
PECO ENERGY COMPANY
By:
Name:
Title:
/s/ MICHAEL A. INNOCENZO
Michael A. Innocenzo
President and Chief Executive Officer
Pursuant to the requirements of the Securities Exchange Act of 1934, this report has been signed by the following persons on behalf of the Registrant and in
the capacities indicated on the 24th day of February, 2021.
Signature
Title
/s/ MICHAEL A. INNOCENZO
Michael A. Innocenzo
/s/ ROBERT J. STEFANI
Robert J. Stefani
/s/ CAROLINE FULGINITI
Caroline Fulginiti
President, Chief Executive Officer (Principal Executive Officer) and Director
Senior Vice President, Chief Financial Officer and Treasurer (Principal
Financial Officer)
Director, Accounting (Principal Accounting Officer)
This annual report has also been signed below by Michael A. Innocenzo, Attorney-in-Fact, on behalf of the following Directors on the date indicated:
Calvin G. Butler
Christopher M. Crane
Nicholas DeBenedictis
Nelson A. Diaz
By:
Name:
/s/ MICHAEL A. INNOCENZO
Michael A. Innocenzo
John S. Grady
Rosemarie B. Greco
Charisse R. Lillie
427
February 24, 2021
Table of Contents
Pursuant to the requirements of Section 13 or 15(d) of the Securities Exchange Act of 1934, the Registrant has duly caused this report to be signed on its
behalf by the undersigned, thereunto duly authorized, in the City of Chicago and State of Illinois on the 24th day of February, 2021.
SIGNATURES
BALTIMORE GAS AND ELECTRIC COMPANY
By:
Name:
Title:
/s/ CARIM V. KHOUZAMI
Carim V. Khouzami
Chief Executive Officer
Pursuant to the requirements of the Securities Exchange Act of 1934, this report has been signed by the following persons on behalf of the Registrant and in
the capacities indicated on the 24th day of February, 2021.
Signature
Title
/s/ CARIM V. KHOUZAMI
Carim V. Khouzami
/s/ DAVID M. VAHOS
David M. Vahos
/s/ JASON T. JONES
Jason T. Jones
Chief Executive Officer (Principal Executive Officer) and Director
Senior Vice President, Chief Financial Officer and Treasurer (Principal
Financial Officer)
Director, Accounting (Principal Accounting Officer)
This annual report has also been signed below by Carim V. Khouzami, Attorney-in-Fact, on behalf of the following Directors on the date indicated:
Ann C. Berzin
Calvin G. Butler
Christopher M. Crane
Michael E. Cryor
By:
Name:
/s/ CARIM V. KHOUZAMI
Carim V. Khouzami
James R. Curtiss
Joseph Haskins, Jr.
Michael D. Sullivan
Maria Harris Tildon
428
February 24, 2021
Table of Contents
Pursuant to the requirements of Section 13 or 15(d) of the Securities Exchange Act of 1934, the Registrant has duly caused this report to be signed on its
behalf by the undersigned, thereunto duly authorized, in the City of Chicago and State of Illinois on the 24th day of February, 2021.
SIGNATURES
PEPCO HOLDINGS LLC
By:
Name:
Title:
/s/ DAVID M. VELAZQUEZ
David M. Velazquez
President and Chief Executive Officer
Pursuant to the requirements of the Securities Exchange Act of 1934, this report has been signed by the following persons on behalf of the Registrant and in
the capacities indicated on the 24th day of February, 2021.
Signature
Title
President, Chief Executive Officer (Principal Executive Officer), and Director
Senior Vice President, Chief Financial Officer and Treasurer (Principal
Financial Officer)
Director, Accounting (Principal Accounting Officer)
/s/ DAVID M. VELAZQUEZ
David M. Velazquez
/s/ PHILLIP S. BARNETT
Phillip S. Barnett
/s/ JULIE E. GIESE
Julie E. Giese
This annual report has also been signed below by David M. Velazquez, Attorney-in-Fact, on behalf of the following Directors on the date indicated:
Calvin. G. Butler
Christopher M. Crane
Linda W. Cropp
Michael E. Cryor
Ernest Dianastasis
Debra P. DiLorenzo
By:
Name:
/s/ DAVID M. VELAZQUEZ
David M. Velazquez
February 24, 2021
429
Table of Contents
Pursuant to the requirements of Section 13 or 15(d) of the Securities Exchange Act of 1934, the Registrant has duly caused this report to be signed on its
behalf by the undersigned, thereunto duly authorized, in the City of Chicago and State of Illinois on the 24th day of February, 2021.
SIGNATURES
POTOMAC ELECTRIC POWER COMPANY
By:
Name:
Title:
/s/ DAVID M. VELAZQUEZ
David M. Velazquez
President and Chief Executive Officer
Pursuant to the requirements of the Securities Exchange Act of 1934, this report has been signed by the following persons on behalf of the Registrant and in
the capacities indicated on the 24th day of February, 2021.
Signature
Title
/s/ DAVID M. VELAZQUEZ
David M. Velazquez
/s/ PHILLIP S. BARNETT
Phillip S. Barnett
/s/ JULIE E. GIESE
Julie E. Giese
President, Chief Executive Officer (Principal Executive Officer), and Director
Senior Vice President, Chief Financial Officer and Treasurer (Principal
Financial Officer)
Director, Accounting (Principal Accounting Officer)
This annual report has also been signed below by David M. Velazquez, Attorney-in-Fact, on behalf of the following Directors on the date indicated:
J. Tyler Anthony
Phillip S. Barnett
Calvin G. Butler
Christopher M. Crane
Melissa A. Lavinson
Kevin M. McGowan
By:
Name:
/s/ DAVID M. VELAZQUEZ
David M. Velazquez
February 24, 2021
430
Table of Contents
Pursuant to the requirements of Section 13 or 15(d) of the Securities Exchange Act of 1934, the Registrant has duly caused this report to be signed on its
behalf by the undersigned, thereunto duly authorized, in the City of Chicago and State of Illinois on the 24th day of February, 2021.
SIGNATURES
DELMARVA POWER & LIGHT COMPANY
By:
Name:
Title:
/s/ DAVID M. VELAZQUEZ
David M. Velazquez
President and Chief Executive Officer
Pursuant to the requirements of the Securities Exchange Act of 1934, this report has been signed by the following persons on behalf of the Registrant and in
the capacities indicated on the 24th day of February, 2021.
Signature
Title
/s/ DAVID M. VELAZQUEZ
David M. Velazquez
/s/ PHILLIP S. BARNETT
Phillip S. Barnett
/s/ JULIE E. GIESE
Julie E. Giese
President, Chief Executive Officer (Principal Executive Officer), and Director
Senior Vice President, Chief Financial Officer and Treasurer (Principal
Financial Officer)
Director, Accounting (Principal Accounting Officer)
This annual report has also been signed below by David M. Velazquez, Attorney-in-Fact, on behalf of the following Directors on the date indicated:
Calvin G. Butler
By:
Name:
/s/ DAVID M. VELAZQUEZ
David M. Velazquez
February 24, 2021
431
Table of Contents
Pursuant to the requirements of Section 13 or 15(d) of the Securities Exchange Act of 1934, the Registrant has duly caused this report to be signed on its
behalf by the undersigned, thereunto duly authorized, in the City of Chicago and State of Illinois on the 24th day of February, 2021.
SIGNATURES
ATLANTIC CITY ELECTRIC COMPANY
By:
Name:
Title:
/s/ DAVID M. VELAZQUEZ
David M. Velazquez
President and Chief Executive Officer
Pursuant to the requirements of the Securities Exchange Act of 1934, this report has been signed by the following persons on behalf of the Registrant and in
the capacities indicated on the 24th day of February, 2021.
Signature
Title
/s/ DAVID M. VELAZQUEZ
David M. Velazquez
/s/ PHILLIP S. BARNETT
Phillip S. Barnett
/s/ JULIE E. GIESE
Julie E. Giese
President, Chief Executive Officer (Principal Executive Officer), and Director
Senior Vice President, Chief Financial Officer and Treasurer (Principal
Financial Officer)
Director, Accounting (Principal Accounting Officer)
432
BYLAWS
OF
COMMONWEALTH EDISON COMPANY
Amended and Restated as of February 22, 2021
Bylaws of
Commonwealth Edison Company
ARTICLE I
MEETINGS OF SHAREHOLDERS
Section 1. - Annual Meeting.
The annual meeting of the shareholders for the election of Directors and for the transaction of general business shall be
held on any date as determined year to year by the Board of Directors. The time and location of the meeting shall be determined
by the Board of Directors.
Section 2. - Special Meeting.
Special meetings of the shareholders may be held upon call by the Chair of the Board, if one is elected, the President, or
a majority of the Board of Directors whenever they deem expedient, or upon the written request of the holders of shares entitled
to not less than twenty percent of all the votes entitled to be cast at such a meeting.
Section 3. - Notice of Meetings
Written or printed notice of every meeting of the shareholders, whether annual or special, stating the place, day, and hour
of such meeting and (in the case of special meetings) the business proposed to be transacted shall be given by the Secretary to
each shareholder entitled to vote at such meeting not less than ten (10) days but no more than sixty (60) days before the date
fixed for such meeting, by electronic mail at his or her e-mail address as it appears on the records of the Company or by
depositing such notice in the United States mail addressed to him or her at his or her post office address as it appears on the
records of the Company, with postage thereon prepaid. A written waiver of notice of a meeting of the shareholders, signed by
the person or persons entitled to such notice, whether before or after the time stated therein, shall be deemed equivalent to the
giving of the notice.
Section 4. - Organization of Meeting.
All meetings of the shareholders shall be called to order by the Chair of the Board, or if one is not elected or is absent, by
the President, or in his or her absence by a Vice President, or in the case of the absence of such officers, then by any
shareholder, whereupon the meeting shall organize by electing a Chair. The Secretary of the Company, if present, shall act as
secretary of the meeting, unless some other person shall be elected by the meeting to so act. An accurate record of the meeting
shall be kept by the secretary thereof, and placed in the record books of the Company.
Section 5. - Quorum.
At any meeting of the shareholders, the presence in person or by proxy of shareholders entitled to cast a majority of the
votes that all shareholders are entitled to cast on a particular matter to be acted upon at the meeting shall constitute a quorum
for the transaction of business. If a quorum be not present at any meeting, holders of a majority of the shares of stock so present
or represented may adjourn the meeting either sine die or to a date certain.
1
Section 6. - Voting.
At all meetings of the shareholders, each shareholder shall be entitled to one vote for each share of common stock
standing in his or her name and, when the preferred or preference stock is entitled to vote, such number of votes as shall be
provided in the charter of the Company for each share of preferred and preference stock standing in his or her name, and the
votes shall be cast by shareholders in person or by lawful proxy.
Section 7. - Action by Consent
Any action required or permitted by law, the Articles of Incorporation, or these Amended and Restated Bylaws to be taken at a
meeting of the shareholders of the Company may be taken without a meeting if a consent or consents in writing, setting forth the
action so taken, shall be signed by shareholders holding at least a majority of the voting power; provided that if a different
proportion of voting power is required for such an action at a meeting, then that proportion of written consents is required. Such
signed consent shall be delivered to the Secretary for inclusion in the minute book of the Corporation.
Section 8. - Record Date for Shareholders and Closing of Transfer Books.
The Board of Directors may fix, in advance, a date as the record for the determination of the shareholders entitled to
notice of, or to vote at, any meeting of shareholders, or entitled to receive payment of any dividend, or entitled to the allotment of
any rights, or for any other proper purpose. Such date in any case shall not be more than sixty (60) days (and in the case of a
meeting of shareholders not less than ten (10) days) prior to the date on which the particular action requiring such determination
of shareholders is to be taken. Only shareholders of record on such date shall be entitled to notice of or to vote at such meeting
or to receive such dividends or rights, as the case may be.
Section 9. – Voting Lists.
The Secretary of the Company shall make, within twenty days after the record date for a meeting of stockholders of the
Company or ten days before such meeting, whichever is earlier, a complete list of the stockholders entitled to vote at such
meeting, arranged in alphabetical order, with the address of and the number of shares held by each, which list, for at least ten
days prior to such meeting, shall be kept on file at the registered office of the Company and shall be subject to inspection by any
stockholder, and to copying at such stockholder's expense, at any time during usual business hours. Such list shall also be
produced and kept open at the time and place of the meeting and shall be subject to the inspection of any stockholder during the
whole time of the meeting.
ARTICLE II
BOARD OF DIRECTORS AND COMMITTEES
Section 1. - Powers of Directors.
The business and affairs of the Company shall be managed by a Board of Directors which shall have and may exercise
all the powers of the Company, except such as are expressly conferred upon or reserved to the shareholders by law, by the
charter, or by these bylaws. Except as otherwise provided herein, the Board of Directors shall appoint the officers for the
conduct of the business of the Company,
2
determine their duties and responsibilities and fix their compensation. The Board of Directors may remove any officer.
Section 2. - Number and Election of Directors.
(a) The Board of Directors shall consist of such number of directors as may be determined from time to time by
resolution of a majority of the Company’s shareholders; provided, however, that the number of Directors may be increased or
decreased by resolution of a majority of the Company’s shareholders without an amendment to these bylaws so long as there
will be no less than four (4) Directors or more than nine (9) Directors.
(b) At least one (1) member of the Board of Directors must be an “Independent Director”, which is defined to mean that
such person is not a director, officer or employee of Exelon Corporation or the the Company (excluding positions as directors of
subsidiaries of the Company).
Section 3. - Removals and Vacancies.
The shareholders, at any meeting duly called and at which a quorum is present or by written consent in lieu thereof, may
remove any Director or Directors from office by the affirmative vote of the holders of a majority of the outstanding shares entitled
to the vote thereon. Vacancies occurring in the Board of Directors for any reason may be filled by the affirmative vote of the
holders of a majority of the outstanding shares entitled to vote thereon.
Section 4. - Director Retirement Age
Each Independent Director must retire from the Board of Directors at or before the next annual meeting of shareholders
following the director’s 75th birthday; provided, however, that a Director’s continued service may be extended by resolution of a
majority of the Company’s shareholders.
Section 5. - Chair of the Board of Directors; Vice Chair.
The Chair of the Board of Directors, if one is elected, shall preside at all meetings of the Board of Directors and of the
shareholders, and shall also have such other powers and duties as from time to time may be assigned to him or her by the
Board of Directors. The Vice Chair, if one is elected, shall, in the absence of the Chair of the Board, perform the duties of the
Chair of the Board, and shall also have such other powers and duties as from time to time may be assigned to him or her by the
Board of Directors.
Section 6. - Meetings of the Board of Directors.
Regular meetings of the Board of Directors shall be held on such dates during the year as may be designated from time
to time by the Board of Directors. All meetings of the Board of Directors shall be held at such location as ordered by the Board of
Directors. Of all such meetings the Secretary shall give notice to each Director personally or by electronic mail, by telephone, or
by written notice at least 24 hours before such meeting. Special meetings may be held at any time or place upon the call of the
Chair or Vice Chair of the Board or the Chief Executive Officer.
The Chair of the Board shall preside at all meetings of the Board of Directors, or, if one is not elected or is absent, the
Vice Chair, the Chief Executive Officer, the President, or one of the Vice Presidents (if a member of the Board of Directors) shall
preside. If at any meeting none of the foregoing persons is present, the Directors present shall designate one of their number to
preside at such meeting.
3
Section 7. - Quorum and Voting.
(a) A majority of the Directors in office shall constitute a quorum of the Board of Directors for the transaction of
business. All actions of the Board of Directors (other than those described in Section 7(b) of this Article II) shall require the
affirmative vote of a majority of the Directors in attendance at a meeting at which a quorum is present. If a quorum be not
present at any meeting, a majority of the Directors present may adjourn to any time and place they may see fit.
(b) Notwithstanding the provisions of subsection 7(a) above, the following actions shall require an affirmative vote of a
majority of the Board of Directors of the corporation that includes the vote of at least one (1) Independent Director: (i) any
decision by the corporation to seek protection from creditors under federal or state bankruptcy, insolvency, moratorium or similar
law affecting the rights of creditors; (ii) any action by the Board of Directors of the corporation to declare and pay dividends; and
(iii) any action by the Board of Directors of the corporation to authorize the purchase of electric energy.
Section 8. - Committees.
The Board of Directors is authorized to appoint from among its members such committees as it may, from time to time,
deem advisable and to delegate to such committee or committees any of the powers of the Board of Directors which it may
lawfully delegate. Each such committee shall consist of at least one (1) Director.
Section 9. - Action by Consent
Any action required or permitted to be taken at any meeting of the Board of Directors may be taken without such a meeting if
a consent or consents in writing, setting forth the action so taken, is signed by all the members of the Board of Directors.
Section 10. - Fees and Expenses.
Each member of the Board of Directors, other than salaried officers and employees, shall be paid an annual retainer fee,
payable in such amount as shall be specified from time to time by the Board of Directors.
Each member of the Board of Directors, other than salaried officers and employees, shall be paid such fee as shall be
specified from time to time by the Board of Directors for attending each regular or special meeting of the Board of Directors and
for attending, as a committee member, each meeting of any committee appointed by the Board of Directors. Each Director shall
be paid reasonable traveling expenses incident to attendance at meetings of the Board of Directors.
ARTICLE III
OFFICERS
Section 1. - Officers.
The Board of Directors shall designate an individual to be the Chief Executive Officer of the Company. The Company
shall also have a President, one or more Vice Presidents, a Treasurer, and a Secretary, who shall be elected by, and hold office
at the will of, the Board of Directors. The Board of Directors shall elect such other officers as they may deem necessary for the
conduct of the business and
4
affairs of the Company. Any two offices, except those of President and Vice President, may be held by the same person, but no
person shall sign checks, drafts and promissory notes, or execute, acknowledge or verify any other instrument in more than one
capacity, if such instrument is required by law, the charter, these bylaws, a resolution of the Board of Directors or order of the
Chief Executive Officer to be signed, executed, acknowledged or verified by two (2) or more officers.
Section 2. - Duties of the Officers.
(a) Chief Executive Officer.
The Chief Executive Officer shall have general and active management of the business of the Corporation and shall see
that all orders and resolutions of the Board of Directors are carried into effect. In the absence of the Chair of the Board and the
Vice Chair, or if one (or both) is (or are) not elected, the Chief Executive Officer shall perform all the duties of the Chair of the
Board.
(b) President.
The President shall have general executive powers, as well as specific powers conferred by these bylaws. The
President, any Vice President, or such other persons as may be designated by the Board of Directors, shall sign all special
contracts of the Company, countersign checks, drafts and promissory notes, and such other papers as may be directed by the
Board of Directors. The President, or any Vice President, together with the Treasurer or an Assistant Treasurer, shall have
authority to sell, assign or transfer and deliver any bonds, stocks or other securities owned by the Company. The President shall
also have such other powers and duties as from time to time may be assigned to him or her by the Board of Directors.
(c) Vice Presidents.
Each Vice President shall have such powers and duties as may be assigned to him or her by the Board of Directors, or
the Chief Executive Officer, as well as the specific powers assigned by these bylaws. A Vice President may be designated by
the Board of Directors or the Chief Executive Officer to perform, in the absence of the President, all the duties of the President.
(d) Treasurer.
The Treasurer shall have the care and the custody of the funds and valuable papers of the Company and shall receive
and disburse all moneys in such a manner as may be prescribed by the Board of Directors or the Chief Executive Officer. The
Treasurer shall have such other powers and duties as may be assigned to him or her by the Board of Directors, or the Chief
Executive Officer, as well as specific powers assigned by these bylaws.
(e) Secretary.
The Secretary shall attend all meetings of the shareholders and the Board of Directors and shall notify the shareholders
and Directors of such meetings in the manner provided in these bylaws. The Secretary shall record the proceedings of all such
meetings in books kept for that purpose. The Secretary
5
shall have such other powers and duties as may be assigned to him or her by the Board of Directors or the Chief Executive
Officer, as well as the specific powers assigned by these bylaws
(f) Assistant Officers.
Assistant Secretaries and Assistant Treasurers, when elected or appointed, shall respectively assist the Secretary or the
Treasurer in the performance of the respective duties assigned to such principal officers, and in assisting such principal officer,
each of such assistant officers shall for such purpose have the powers of such principal officer. In case of the absence, disability,
death, resignation or removal from office of any principal officer, such principal officer's duties shall, except as otherwise ordered
by the Board of Directors, temporarily devolve upon such assistant officer as shall be designated by the Chair, Vice Chair or
Chief Executive Officer.
Section 3. - Removals and Vacancies.
Any officer may be removed by the Board of Directors whenever, in its judgment, the best interest of the Company will be
served thereby. In case of removal, the salary of such officer shall cease. Removal shall be without prejudice to the contractual
rights, if any, of the person so removed, but election of an officer shall not of itself create contractual rights.
Any vacancy occurring in any office of the Company shall be filled by the Board of Directors and the officer so elected
shall hold office for the unexpired term in respect of which the vacancy occurred or until his or her successor shall be duly
elected and qualified.
In any event of absence or temporary disability of any officer of the Company, the Board of Directors may authorize some
other person to perform the duties of that office.
ARTICLE IV
INDEMNIFICATION
Section 1. - Procedure.
The Company shall indemnify any present or former Director or officer of the Company and each Director or elected
officer of any direct or indirect wholly-owned subsidiary of the Company who is made, or threatened to be made, a party to a
proceeding by reason of his or her service in that capacity or by reason of service, while a Director or officer of the Company
and at the request of the Company, as a director or officer of another company, corporation, limited liability company,
partnership, trust, employee benefit plan or other enterprise, and the Company shall pay or reimburse reasonable expenses
incurred in advance of final disposition of the proceeding, in each case to the fullest extent permitted by the laws of the State of
Illinois. The Company may indemnify, and advance reasonable expenses to, other employees and agents of the Company and
employees and agents of any subsidiary of the Company to the extent authorized by the Board of Directors. The Company shall
follow the procedures required by applicable law in determining persons eligible for indemnification and in making
indemnification payments and advances.
Section 2. - Exclusivity, etc.
The indemnification and advancement of expenses provided by these bylaws (a) shall not be deemed exclusive of any
other rights to which a person seeking indemnification or advance of expenses
6
may be entitled under any law (common or statutory), or any agreement, vote of shareholders or disinterested Directors or other
provision that is consistent with law, both as to action in his or her official capacity and as to action in another capacity while
holding office or while employed or acting as agent for the Company, (b) shall continue in respect of all events occurring while a
person was a Director or officer after such person has ceased to be a Director or officer, and (c) shall inure to the benefit of the
estate, heirs, executors and administrators of such person. All rights to indemnification and advance of expenses hereunder
shall be deemed to be a contract between the Company and each Director or officer of the Company who serves or served in
such capacity at any time while this Article IV is in effect. Nothing herein shall prevent the amendment of this Article IV, provided
that no such amendment shall diminish the rights of any person hereunder with respect to events occurring or claims made
before its adoption or as to claims made after its adoption in respect of events occurring before its adoption. Any repeal or
modification of this Article IV shall not in any way diminish any rights to indemnification or advancement of expenses of a
Director or officer or the obligations of the Company arising hereunder with respect to events occurring, or claims made, while
this Article IV or any provision hereof is in effect.
Section 3. - Severability.
The invalidity or unenforceability of any provision of this Article IV shall not affect the validity or enforceability of any other
provision hereof.
ARTICLE V
CAPITAL STOCK
Section 1. - Evidence of Stock Ownership.
Evidence of ownership of stock in the Company shall be pursuant to certificate(s), each of which shall represent the
number of shares of stock owned by a shareholder of the Company. Shareholders may request that their stock ownership be
represented by certificate(s). Each certificate shall be signed on behalf of the Company by the President or a Vice President and
countersigned by the Secretary or the Treasurer and shall be sealed with the corporate seal. The signatures may be either
manual or facsimile. In case any officer who signed any certificate, in facsimile or otherwise, ceases to be such officer of the
Company before the certificate is issued, the certificate may nevertheless be issued by the Company with the same effect as if
the officer had not ceased to be such officer as of the date of its issue.
Section 2. - Transfer of Shares.
Stock shall be transferable only on the books of the Company by assignment in writing by the registered holder thereof,
his or her legally constituted attorney, or his or her legal representative, either upon surrender and cancellation of the
certificate(s) therefor, if such stock is represented by a certificate, or upon receipt of such other documentation for stock not
represented by a certificate as the Board of Directors and the law of the State of Illinois may, from time to time, require.
Section 3. - Lost, Stolen or Destroyed Certificates.
No certificate for shares of stock of the Company shall be issued in place of any other certificate alleged to have been
lost, stolen, or destroyed, except upon production of such evidence of the loss, theft or destruction and upon indemnification of
the Company to such extent and in such manner as the Board of Directors may prescribe.
7
Section 4. - Transfer Agents and Registrars.
The Board of Directors shall appoint a person or persons, or any incorporated trust company or companies or both, as
transfer agents and registrars and, if stock is represented by a certificate, may require that such certificate bear the signatures or
the counter-signatures of such transfer agents and registrars, or either of them.
Section 5. - Stock Ledger.
The Company shall maintain at its principal office a stock record containing the names and addresses of all shareholders
and the numbers of shares of each class held by each shareholder.
ARTICLE VI
SEAL
The Board of Directors shall provide, subject to change, a suitable corporate seal which may be used by causing it, or
facsimile thereof, to be impressed or affixed or reproduced one the Company’s stock certificates, bonds, or any other documents
on which the seal may be appropriate.
These bylaws, or any of them, may be amended or repealed, and new bylaws may be made or adopted by the
shareholders at any annual meeting or a special meeting called for that purpose, or by written consent in lieu of a meeting.
ARTICLE VII
AMENDMENTS
8
Amy E. Best
SVP & Chief HR Officer
10 S. Dearborn Street
Chicago, IL 60603
Tel. (312) 394-7554
June 4, 2020
William A. Von Hoene, Jr.
6901 S Constance Ave
Chicago, IL 60649
Re: Letter of Understanding
Dear Bill:
This letter will confirm our mutual understanding regarding your employment with Exelon Corporation (the “Company”).
1.
2.
3.
4.
You have agreed to remain with the Company in your current position until your retirement on December 31, 2022
(“Retirement Date”).
Your current annualized base salary rate and target annual incentive and long-term performance share opportunities
will remain in effect, you and your eligible dependents will remain eligible to participate in the Company’s applicable
employee benefit plans, your outstanding long-term incentive awards will continue to in accordance with their terms,
and you will remain subject to the Company’s code of business conduct and other employment policies.
In the event your employment ends prior to your Retirement Date for any reason other than your resignation or
termination by the Company for “cause”, you (or your estate) will be eligible to receive non-change in control
separation benefits pursuant to the Exelon Corporation Senior Management Severance Plan. You will not be eligible
for separation benefits if your employment ends on or after your Retirement Date.
This letter supersedes all prior agreements and understandings concerning your employment, including your Change
in Control Employment Agreement dated October 26, 2016 other than the provisions of Article VIII (“Restrictive
Covenants”) thereof.
June 4, 2020
Page 2
Please acknowledge your acceptance of the above terms and conditions by signing this letter in the space provided below and
promptly returning it to me.
We greatly appreciate your ongoing contributions to Exelon.
Very truly yours,
/s/Amy E. Best
Amy E. Best
Senior Vice President &
Chief Human Resources Officer
Agreed and Accepted:
/s/ William A. Von Hoene, Jr.
cc: Chris Crane
Exhibit 21.1
Exelon Corporation (50% and Greater)
12/31/2020
Subsidiary
2014 ESA HoldCo, LLC
2014 ESA Project Company, LLC
2015 ESA Holdco, LLC
2015 ESA Investco, LLC
2015 ESA Project Company, LLC
A/C Fuels Company
Albany Green Energy, LLC
AMP Funding, L.L.C.
Annova LNG Brownsville A, LLC
Annova LNG Common Infrastructure, LLC
Annova LNG, LLC
Annova LNG, LLC Series A
Annova LNG, LLC Series Z
APS Constellation, LLC
Atlantic City Electric Company
Atlantic City Electric Transition Funding LLC
Atlantic Generation, Inc.
Atlantic Southern Properties, Inc.
ATNP Finance Company
AV Solar Ranch 1, LLC
Baltimore Gas and Electric Company
Beebe 1B Renewable Energy, LLC
Beebe Renewable Energy, LLC
Bennett Creek Windfarm, LLC
Bethlehem Renewable Energy, LLC
BGE Home Products & Services, LLC
Big Top, LLC
Blue Breezes II, L.L.C.
Blue Breezes, L.L.C.
Bluestem Wind Energy Holdings, LLC
Bluestem Wind Energy Member Holdings, LLC
Bluestem Wind Energy Member, LLC
Bluestem Wind Energy, LLC
BPHS Solar, LLC
Breakerbox, LLC
Butter Creek Power, LLC
California PV Energy 2, LLC
California PV Energy 3, LLC
California PV Energy, LLC
Calvert Cliffs Nuclear Power Plant, LLC
Cassia Gulch Wind Park LLC
Cassia Wind Farm LLC
CD Panther I, Inc.
CD Panther II, LLC
CD Panther Partners, L.P.
Jurisdiction
Delaware
Delaware
Delaware
Delaware
Delaware
Pennsylvania
Georgia
Delaware
Delaware
Delaware
Delaware
Delaware
Delaware
Delaware
New Jersey
Delaware
New Jersey
New Jersey
Delaware
Delaware
Maryland
Delaware
Delaware
Idaho
Delaware
Delaware
Oregon
Minnesota
Minnesota
Delaware
Delaware
Delaware
Delaware
Delaware
Pennsylvania
Oregon
Delaware
Delaware
Delaware
Maryland
Idaho
Idaho
Maryland
Delaware
Delaware
1
Exhibit 21.1
CD SEGS V, Inc.
CD SEGS VI, Inc.
CE Culm, Inc.
CE FundingCo, LLC
CE Nuclear, LLC
CER Generation, LLC
CEU Arkoma West, LLC
CEU CoLa, LLC
CEU East Fort Peck, LLC
CEU Fayetteville, LLC
CEU Floyd Shale, LLC
CEU Holdings, LLC
CEU Huntsville, LLC
CEU Kingston, LLC
CEU Niobrara, LLC
CEU Ohio Shale, LLC
CEU Paradigm, LLC
CEU Pinedale, LLC
CEU Plymouth, LLC
CEU Simplicity, LLC
CEU W&D, LLC
Chesapeake HVAC, Inc.
CII Solarpower I, Inc.
Clean Jobs for Pennsylvania, LLC
Clinton Battery Utility, LLC
CLT Energy Services Group, L.L.C.
CNE Gas Holdings, LLC
CNEG Holdings, LLC
CNEGH Holdings, LLC
CoLa Resources LLC
Colorado Bend II Power, LLC
Colorado Bend Services, LLC
ComEd Financing III
Commonwealth Edison Company
Commonwealth Edison Company of Indiana, Inc.
Conectiv Communications, Inc.
Conectiv Energy Supply, Inc.
Conectiv Properties and Investments, Inc.
Conectiv Solutions LLC
Conectiv, LLC
Constellation Connect, LLC
Constellation DCO Albany Power Holdings, LLC
Constellation EG, LLC
Constellation Energy Canada, Inc.
Constellation Energy Commodities Group Maine, LLC
Constellation Energy Gas Choice, LLC
Constellation Energy Nuclear Group, LLC
Constellation Energy Power Choice, LLC
Constellation Energy Resources, LLC
Maryland
Maryland
Maryland
Delaware
Delaware
Delaware
Delaware
Delaware
Delaware
Delaware
Delaware
Delaware
Delaware
Delaware
Delaware
Delaware
Delaware
Delaware
Delaware
Delaware
Delaware
Delaware
Maryland
Delaware
Delaware
Pennsylvania
Kentucky
Delaware
Delaware
Delaware
Delaware
Delaware
Delaware
Illinois
Indiana
Delaware
Delaware
Delaware
Delaware
Delaware
Delaware
Delaware
Delaware
Ontario
Delaware
Delaware
Maryland
Delaware
Delaware
2
Exhibit 21.1
Constellation Energy Solutions, LLC
Constellation Energy Upstream Holdings, LLC
Constellation Holdings, LLC
Constellation LNG, LLC
Constellation Mystic Power, LLC
Constellation NewEnergy - Gas Division, LLC
Constellation NewEnergy, Inc.
Constellation Nuclear Power Plants, LLC
Constellation Nuclear, LLC
Constellation Power Source Generation, LLC
Constellation Power, Inc.
Constellation Solar Arizona 2, LLC
Constellation Solar Arizona, LLC
Constellation Solar California, LLC
Constellation Solar Connecticut, LLC
Constellation Solar DC, LLC
Constellation Solar Federal, LLC
Constellation Solar Georgia 2, LLC
Constellation Solar Georgia, LLC
Constellation Solar Holding, LLC
Constellation Solar Horizons, LLC
Constellation Solar Illinois 2, LLC
Constellation Solar Illinois, LLC
Constellation Solar Maryland II, LLC
Constellation Solar Maryland, LLC
Constellation Solar Massachusetts, LLC
Constellation Solar MC, LLC
Constellation Solar Net Metering, LLC
Constellation Solar New Jersey II, LLC
Constellation Solar New Jersey III, LLC
Constellation Solar New Jersey, LLC
Constellation Solar New York, LLC
Constellation Solar Ohio, LLC
Constellation Solar Pennsylvania, LLC
Constellation Solar Rhode Island, LLC
Constellation Solar Texas, LLC
Constellation Solar, LLC
Continental Wind Holding, LLC
Continental Wind, LLC
COSI Central Wayne, Inc.
COSI Sunnyside, Inc.
Cow Branch Wind Power, L.L.C.
CP Sunnyside I, Inc.
CP Windfarm, LLC
CR Clearing, LLC
Criterion Power Partners, LLC
Data Center Enterprise, LLC
DE Asset Operations, LLC
Delaware Operating Services Company, LLC
Delaware
Delaware
Maryland
Delaware
Delaware
Kentucky
Delaware
Delaware
Delaware
Maryland
Maryland
Delaware
Delaware
Delaware
Delaware
Delaware
Delaware
Delaware
Georgia
Delaware
Delaware
Delaware
Delaware
Delaware
Delaware
Delaware
Delaware
Delaware
Delaware
Delaware
Delaware
Delaware
Delaware
Delaware
Delaware
Delaware
Delaware
Delaware
Delaware
Maryland
Maryland
Missouri
Maryland
Minnesota
Missouri
Delaware
Delaware
Delaware
Delaware
3
Exhibit 21.1
Delmarva Power & Light Company
Denver Airport Solar, LLC
Distrigas of Massachusetts LLC
DLC Solar, LLC
E&W Development Corporation
Ecocred, LLC
EdiSun, LLC
Energy Performance Services, Inc.
ETT Canada, Inc.
Everett LNG LLC
Exelon AVSR Holding, LLC
Exelon AVSR, LLC
Exelon Business Services Company, LLC
Exelon Clearsight, LLC
Exelon Energy Delivery Company, LLC
Exelon Enterprises Company, LLC
Exelon FitzPatrick, LLC
Exelon Framingham, LLC
Exelon Fulton, LLC
Exelon Generation Acquisitions, LLC
Exelon Generation Company, LLC
Exelon Generation Consolidation, LLC
Exelon Generation Finance Company, LLC
Exelon Generation Limited
Exelon Generation Services, LLC
Exelon Generation Supply, LLC
Exelon Genesis, LLC
Exelon InQB8R, LLC
Exelon Mechanical, LLC
Exelon Microgrid, LLC
Exelon New Boston, LLC
Exelon New England Holdings, LLC
Exelon Nuclear Partners, LLC
Exelon Nuclear Security, LLC
Exelon PowerLabs, LLC
Exelon Solar Chicago LLC
Exelon Transmission Company, LLC
Exelon VTI, LLC
Exelon West Medway, LLC
Exelon Wind 1, LLC
Exelon Wind 2, LLC
Exelon Wind 3, LLC
Exelon Wind Canada Inc.
Exelon Wind, LLC
Exelon Wyman, LLC
Exelorate Enterprises, LLC
Ex-FM, Inc.
Ex-FME, Inc.
ExGen Energy, S. de R.L. de C.V.
Delaware & Virginia
Delaware
Delaware
Delaware
Florida
Delaware
Delaware
Pennsylvania
New Brunswick
Delaware
Delaware
Delaware
Delaware
Delaware
Delaware
Pennsylvania
Delaware
Delaware
Delaware
Delaware
Pennsylvania
Illinois
Delaware
United Kingdom
Delaware
Delaware
Delaware
Delaware
Delaware
Delaware
Delaware
Delaware
Delaware
Delaware
Pennsylvania
Delaware
Delaware
Delaware
Delaware
Texas
Texas
Texas
Canada
Delaware
Delaware
Delaware
New York
Delaware
Mexico
4
Exhibit 21.1
ExGen Handley Power, LLC
ExGen Renewables Holdings II, LLC
ExGen Renewables Holdings, LLC
ExGen Renewables I Holding, LLC
ExGen Renewables I, LLC
ExGen Renewables II, LLC
ExGen Renewables IV Holding, LLC
ExGen Renewables IV, LLC
ExGen Renewables Partners, LLC
ExGen Texas II Power Holdings, LLC
ExGen Texas II Power, LLC
ExGen Texas Power Services, LLC
ExGen Ventures International Holdings II Limited
ExGen Ventures International Holdings Limited
ExTel Corporation, LLC
F & M Holdings Company, L.L.C.
Fair Wind Power Partners, LLC
Fauquier Landfill Gas, L.L.C.
FHS Solar, LLC
Four Corners Windfarm, LLC
Four Mile Canyon Windfarm, LLC
Fourmile Wind Energy, LLC
Friendly Skies, Inc.
Gateway Solar LLC
Grande Prairie Generation, Inc.
Green Lane Solar Power LLC
Greensburg Wind Farm, LLC
Handsome Lake Energy, LLC
Harvest II Windfarm, LLC
Harvest Windfarm, LLC
High Mesa Energy, LLC
High Plains Wind Power, LLC
Holyoke Solar, LLC
Hot Springs Windfarm, LLC
JBAB Solar I, LLC
JExel Nuclear Company
Lake Houston Power, LLC
LHHS Solar, LLC
Loess Hills Wind Farm, LLC
LSLV Solar, LLC
Melville Solar Power LLC
Michigan Wind 1, LLC
Michigan Wind 2, LLC
Michigan Wind 3, LLC
Millennium Account Services, LLC
Minergy LLC
Mohave Sunrise Solar I, LLC
Mountain Top Wind Power, LLC
NewEnergy Receivables, LLC
Delaware
Delaware
Delaware
Delaware
Delaware
Delaware
Delaware
Delaware
Delaware
Delaware
Delaware
Delaware
United Kingdom
United Kingdom
Delaware
Delaware
Delaware
Delaware
Delaware
Oregon
Oregon
Maryland
U.S. Virgin Islands
Delaware
Alberta
Rhode Island
Delaware
Maryland
Delaware
Michigan
Idaho
Texas
Delaware
Idaho
Delaware
Japan
Delaware
Delaware
Missouri
Delaware
Rhode Island
Delaware
Delaware
Delaware
Delaware
Wisconsin
Arizona
Maryland
Delaware
5
Nine Mile Point Nuclear Station, LLC
North Shore District Energy, LLC
Northwind Thermal Technologies Canada Inc.
Oregon Trail Windfarm, LLC
Outback Solar, LLC
Pacific Canyon Windfarm, LLC
Panther Creek Holdings, Inc.
Panther Creek Partners
PCI - BT Investing, L.L.C.
PCI Air Management Corporation
PCI Air Management Partners, L.L.C.
PEC Financial Services, LLC
PECO Energy Capital Corp.
PECO Energy Capital Trust III
PECO Energy Capital Trust IV
PECO Energy Capital, L.P.
PECO Energy Company
PECO Wireless, LLC
Pegasus Power Company, Inc.
Pepco Building Services Inc.
Pepco Government Services LLC
Pepco Holdings LLC
PFMG Construction, Ltd.
PFMG Solar, LLC
PH Holdco LLC
PHI Service Company
Pinedale Energy, LLC
Potomac Capital Investment Corporation
Potomac Delaware Leasing Corporation
Potomac Electric Power Company
Potomac Leasing Associates, L.P.
R.E. Ginna Nuclear Power Plant, LLC
Ramp Investments, L.L.C.
Renewable Power Generation Holdings, LLC
Renewable Power Generation, LLC
RF HoldCo LLC
RITELine Illinois, LLC
RITELine Transmission Development, LLC
Rolling Hills Landfill Gas, LLC
Sacramento PV Energy, LLC
Sand Ranch Windfarm, LLC
Scherer Holdings 1, LLC
Scherer Holdings 2, LLC
Scherer Holdings 3, LLC
Sendero Wind Energy, LLC
SHHS Solar, LLC
Shooting Star Wind Project, LLC
SHS Solar, LLC
Sky Valley, LLC
Exhibit 21.1
Delaware
Delaware
New Brunswick
Oregon
Oregon
Oregon
Delaware
Delaware
Delaware
Nevada
Delaware
Pennsylvania
Delaware
Delaware
Delaware
Delaware
Pennsylvania
Delaware
California
Delaware
Delaware
Delaware
California
Delaware
Delaware
Delaware
Colorado
Delaware
Delaware
District of Columbia & Virginia
Delaware
Maryland
Delaware
Delaware
Delaware
Delaware
Illinois
Delaware
Delaware
Delaware
Oregon
Delaware
Delaware
Delaware
Delaware
Delaware
Delaware
Delaware
Delaware
6
Exhibit 21.1
SolGen Holding, LLC
SolGen, LLC
Sugar Beet Wind, LLC
Sunbeam LeaseCo, LLC
Threemile Canyon Wind I, LLC
THS Solar, LLC
Titan STC, LLC
Tuana Springs Energy, LLC
UII, LLC
V.G. Investment Holdings, LLC
Volta SPV CMX, LLC
Volta SPV NTR, LLC
Volta SPV RSL, LLC
W&D Gas Partners, LLC
Wagon Trail, LLC
Wansley Holdings 1, LLC
Wansley Holdings 2, LLC
Ward Butte Windfarm, LLC
Water & Energy Savings Company, LLC
West Medway II Holdings, LLC
West Medway II, LLC
Whitetail Wind Energy, LLC
Wildcat Finance, LLC
Wildcat Wind LLC
Wind Capital Holdings, LLC
Wolf Hollow II Power, LLC
Wolf Hollow Services, LLC
Delaware
Delaware
Delaware
Delaware
Oregon
Delaware
Delaware
Idaho
Illinois
Delaware
Delaware
Delaware
Delaware
Delaware
Oregon
Delaware
Delaware
Oregon
Delaware
Delaware
Delaware
Delaware
Delaware
New Mexico
Missouri
Delaware
Delaware
7
Exhibit 21.2
Exelon Generation Company, LLC (50% and Greater)
12/31/2020
Subsidiary
2014 ESA HoldCo, LLC
2014 ESA Project Company, LLC
2015 ESA Holdco, LLC
2015 ESA Investco, LLC
2015 ESA Project Company, LLC
A/C Fuels Company
Albany Green Energy, LLC
Annova LNG Brownsville A, LLC
Annova LNG Common Infrastructure, LLC
Annova LNG, LLC
Annova LNG, LLC Series A
Annova LNG, LLC Series Z
APS Constellation, LLC
Atlantic Generation, Inc.
AV Solar Ranch 1, LLC
Beebe 1B Renewable Energy, LLC
Beebe Renewable Energy, LLC
Bennett Creek Windfarm, LLC
Bethlehem Renewable Energy, LLC
BGE Home Products & Services, LLC
Big Top, LLC
Blue Breezes II, L.L.C.
Blue Breezes, L.L.C.
Bluestem Wind Energy Holdings, LLC
Bluestem Wind Energy Member Holdings, LLC
Bluestem Wind Energy Member, LLC
Bluestem Wind Energy, LLC
BPHS Solar, LLC
Breakerbox, LLC
Butter Creek Power, LLC
California PV Energy 2, LLC
California PV Energy 3, LLC
California PV Energy, LLC
Calvert Cliffs Nuclear Power Plant, LLC
Cassia Gulch Wind Park LLC
Cassia Wind Farm LLC
CD Panther I, Inc.
CD Panther II, LLC
CD Panther Partners, L.P.
CD SEGS V, Inc.
CD SEGS VI, Inc.
CE Culm, Inc.
CE FundingCo, LLC
CE Nuclear, LLC
CER Generation, LLC
Jurisdiction
Delaware
Delaware
Delaware
Delaware
Delaware
Pennsylvania
Georgia
Delaware
Delaware
Delaware
Delaware
Delaware
Delaware
New Jersey
Delaware
Delaware
Delaware
Idaho
Delaware
Delaware
Oregon
Minnesota
Minnesota
Delaware
Delaware
Delaware
Delaware
Delaware
Pennsylvania
Oregon
Delaware
Delaware
Delaware
Maryland
Idaho
Idaho
Maryland
Delaware
Delaware
Maryland
Maryland
Maryland
Delaware
Delaware
Delaware
1
Exhibit 21.2
CEU Arkoma West, LLC
CEU CoLa, LLC
CEU East Fort Peck, LLC
CEU Fayetteville, LLC
CEU Floyd Shale, LLC
CEU Holdings, LLC
CEU Huntsville, LLC
CEU Kingston, LLC
CEU Niobrara, LLC
CEU Ohio Shale, LLC
CEU Paradigm, LLC
CEU Pinedale, LLC
CEU Plymouth, LLC
CEU Simplicity, LLC
CEU W&D, LLC
Chesapeake HVAC, Inc.
CII Solarpower I, Inc.
Clinton Battery Utility, LLC
CLT Energy Services Group, L.L.C.
CNE Gas Holdings, LLC
CNEG Holdings, LLC
CNEGH Holdings, LLC
CoLa Resources LLC
Colorado Bend II Power, LLC
Colorado Bend Services, LLC
Conectiv Energy Supply, Inc.
Conectiv, LLC
Constellation Connect, LLC
Constellation DCO Albany Power Holdings, LLC
Constellation EG, LLC
Constellation Energy Canada, Inc.
Constellation Energy Commodities Group Maine, LLC
Constellation Energy Gas Choice, LLC
Constellation Energy Nuclear Group, LLC
Constellation Energy Power Choice, LLC
Constellation Energy Resources, LLC
Constellation Energy Solutions, LLC
Constellation Energy Upstream Holdings, LLC
Constellation Holdings, LLC
Constellation LNG, LLC
Constellation Mystic Power, LLC
Constellation NewEnergy - Gas Division, LLC
Constellation NewEnergy, Inc.
Constellation Nuclear Power Plants, LLC
Constellation Nuclear, LLC
Constellation Power Source Generation, LLC
Constellation Power, Inc.
Constellation Solar Arizona 2, LLC
Constellation Solar Arizona, LLC
Delaware
Delaware
Delaware
Delaware
Delaware
Delaware
Delaware
Delaware
Delaware
Delaware
Delaware
Delaware
Delaware
Delaware
Delaware
Delaware
Maryland
Delaware
Pennsylvania
Kentucky
Delaware
Delaware
Delaware
Delaware
Delaware
Delaware
Delaware
Delaware
Delaware
Delaware
Ontario
Delaware
Delaware
Maryland
Delaware
Delaware
Delaware
Delaware
Maryland
Delaware
Delaware
Kentucky
Delaware
Delaware
Delaware
Maryland
Maryland
Delaware
Delaware
2
Exhibit 21.2
Constellation Solar California, LLC
Constellation Solar Connecticut, LLC
Constellation Solar DC, LLC
Constellation Solar Federal, LLC
Constellation Solar Georgia 2, LLC
Constellation Solar Georgia, LLC
Constellation Solar Holding, LLC
Constellation Solar Horizons, LLC
Constellation Solar Illinois 2, LLC
Constellation Solar Illinois, LLC
Constellation Solar Maryland II, LLC
Constellation Solar Maryland, LLC
Constellation Solar Massachusetts, LLC
Constellation Solar MC, LLC
Constellation Solar Net Metering, LLC
Constellation Solar New Jersey II, LLC
Constellation Solar New Jersey III, LLC
Constellation Solar New Jersey, LLC
Constellation Solar New York, LLC
Constellation Solar Ohio, LLC
Constellation Solar Pennsylvania, LLC
Constellation Solar Rhode Island, LLC
Constellation Solar Texas, LLC
Constellation Solar, LLC
Continental Wind Holding, LLC
Continental Wind, LLC
COSI Central Wayne, Inc.
COSI Sunnyside, Inc.
Cow Branch Wind Power, L.L.C.
CP Sunnyside I, Inc.
CP Windfarm, LLC
CR Clearing, LLC
Criterion Power Partners, LLC
DE Asset Operations, LLC
Delaware Operating Services Company, LLC
Denver Airport Solar, LLC
Distrigas of Massachusetts LLC
DLC Solar, LLC
Energy Performance Services, Inc.
Everett LNG LLC
Exelon AVSR Holding, LLC
Exelon AVSR, LLC
Exelon FitzPatrick, LLC
Exelon Framingham, LLC
Exelon Fulton, LLC
Exelon Generation Acquisitions, LLC
Exelon Generation Consolidation, LLC
Exelon Generation Finance Company, LLC
Exelon Generation Limited
Delaware
Delaware
Delaware
Delaware
Delaware
Georgia
Delaware
Delaware
Delaware
Delaware
Delaware
Delaware
Delaware
Delaware
Delaware
Delaware
Delaware
Delaware
Delaware
Delaware
Delaware
Delaware
Delaware
Delaware
Delaware
Delaware
Maryland
Maryland
Missouri
Maryland
Minnesota
Missouri
Delaware
Delaware
Delaware
Delaware
Delaware
Delaware
Pennsylvania
Delaware
Delaware
Delaware
Delaware
Delaware
Delaware
Delaware
Illinois
Delaware
United Kingdom
3
Exhibit 21.2
Exelon Generation Services, LLC
Exelon Generation Supply, LLC
Exelon New Boston, LLC
Exelon New England Holdings, LLC
Exelon Nuclear Partners, LLC
Exelon Nuclear Security, LLC
Exelon PowerLabs, LLC
Exelon Solar Chicago LLC
Exelon West Medway, LLC
Exelon Wind 1, LLC
Exelon Wind 2, LLC
Exelon Wind 3, LLC
Exelon Wind Canada Inc.
Exelon Wind, LLC
Exelon Wyman, LLC
ExGen Energy, S. de R.L. de C.V.
ExGen Handley Power, LLC
ExGen Renewables Holdings II, LLC
ExGen Renewables Holdings, LLC
ExGen Renewables I Holding, LLC
ExGen Renewables I, LLC
ExGen Renewables II, LLC
ExGen Renewables IV Holding, LLC
ExGen Renewables IV, LLC
ExGen Renewables Partners, LLC
ExGen Texas II Power Holdings, LLC
ExGen Texas II Power, LLC
ExGen Texas Power Services, LLC
ExGen Ventures International Holdings II Limited
ExGen Ventures International Holdings Limited
Fair Wind Power Partners, LLC
Fauquier Landfill Gas, L.L.C.
FHS Solar, LLC
Four Corners Windfarm, LLC
Four Mile Canyon Windfarm, LLC
Fourmile Wind Energy, LLC
Gateway Solar LLC
Grande Prairie Generation, Inc.
Green Lane Solar Power LLC
Greensburg Wind Farm, LLC
Handsome Lake Energy, LLC
Harvest II Windfarm, LLC
Harvest Windfarm, LLC
High Mesa Energy, LLC
High Plains Wind Power, LLC
Holyoke Solar, LLC
Hot Springs Windfarm, LLC
JBAB Solar I, LLC
JExel Nuclear Company
Delaware
Delaware
Delaware
Delaware
Delaware
Delaware
Pennsylvania
Delaware
Delaware
Texas
Texas
Texas
Canada
Delaware
Delaware
Mexico
Delaware
Delaware
Delaware
Delaware
Delaware
Delaware
Delaware
Delaware
Delaware
Delaware
Delaware
Delaware
United Kingdom
United Kingdom
Delaware
Delaware
Delaware
Oregon
Oregon
Maryland
Delaware
Alberta
Rhode Island
Delaware
Maryland
Delaware
Michigan
Idaho
Texas
Delaware
Idaho
Delaware
Japan
4
Exhibit 21.2
Lake Houston Power, LLC
LHHS Solar, LLC
Loess Hills Wind Farm, LLC
LSLV Solar, LLC
Melville Solar LLC
Michigan Wind 1, LLC
Michigan Wind 2, LLC
Michigan Wind 3, LLC
Minergy LLC
Mohave Sunrise Solar I, LLC
Mountain Top Wind Power, LLC
NewEnergy Receivables LLC
Nine Mile Point Nuclear Station, LLC
North Shore District Energy, LLC
Oregon Trail Windfarm, LLC
Outback Solar, LLC
Pacific Canyon Windfarm, LLC
Panther Creek Holdings, Inc.
Panther Creek Partners
Pegasus Power Company, Inc.
Pepco Building Services Inc.
Pepco Government Services LLC
PFMG Construction, Ltd.
PFMG Solar, LLC
Pinedale Energy, LLC
R.E. Ginna Nuclear Power Plant, LLC
Renewable Power Generation Holdings, LLC
Renewable Power Generation, LLC
Rolling Hills Landfill Gas, LLC
Sacramento PV Energy, LLC
Sand Ranch Windfarm, LLC
Sendero Wind Energy, LLC
SHHS Solar, LLC
Shooting Star Wind Project, LLC
SHS Solar, LLC
Sky Valley, LLC
SolGen Holding, LLC
SolGen, LLC
Sugar Beet Wind, LLC
Sunbeam LeaseCo, LLC
Threemile Canyon Wind I, LLC
THS Solar, LLC
Titan STC, LLC
Tuana Springs Energy, LLC
V.G. Investment Holdings, LLC
W&D Gas Partners, LLC
Wagon Trail, LLC
Ward Butte Windfarm, LLC
Water & Energy Savings Company, LLC
Delaware
Delaware
Missouri
Delaware
Rhode Island
Delaware
Delaware
Delaware
Wisconsin
Arizona
Maryland
Delaware
Delaware
Delaware
Oregon
Oregon
Oregon
Delaware
Delaware
California
Delaware
Delaware
California
Delaware
Colorado
Maryland
Delaware
Delaware
Delaware
Delaware
Oregon
Delaware
Delaware
Delaware
Delaware
Delaware
Delaware
Delaware
Delaware
Delaware
Oregon
Delaware
Delaware
Idaho
Delaware
Delaware
Oregon
Oregon
Delaware
5
Exhibit 21.2
West Medway II Holdings, LLC
West Medway II, LLC
Whitetail Wind Energy, LLC
Wildcat Finance, LLC
Wildcat Wind LLC
Wind Capital Holdings, LLC
Wolf Hollow II Power, LLC
Wolf Hollow Services, LLC
Delaware
Delaware
Delaware
Delaware
New Mexico
Missouri
Delaware
Delaware
6
Exhibit 21.3
Commonwealth Edison Company (50% and Greater)
12/31/2020
Subsidiary
Commonwealth Edison Company of Indiana, Inc.
ComEd Financing III
EdiSun, LLC
RITELine Illinois, LLC
Jurisdiction
Indiana
Delaware
Delaware
Illinois
Exhibit 21.4
PECO Energy Company (50% and Greater)
12/31/2020
Subsidiary
ATNP Finance Company
ExTel Corporation, LLC
PEC Financial Services, LLC
PECO Energy Capital Corp.
PECO Energy Capital, L.P.
PECO Energy Capital Trust III
PECO Energy Capital Trust IV
PECO Wireless, LLC
Jurisdiction
Delaware
Delaware
Pennsylvania
Delaware
Delaware
Delaware
Delaware
Delaware
Exhibit 21.5
Baltimore Gas and Electric Company (50% and Greater)
12/31/2020
Subsidiary
None
Jurisdiction
Pepco Holdings LLC (50% and Greater)
12/31/2020
Subsidiary
Atlantic City Electric Company
Atlantic City Electric Transition Funding LLC
Delmarva Power & Light Company
Millennium Account Services, LLC
PHI Service Company
Potomac Electric Power Company
Exhibit 21.6
Jurisdiction
New Jersey
Delaware
Delaware & Virginia
Delaware
Delaware
District of Columbia & Virginia
Exhibit 21.7
Potomac Electric Power Company (50% and Greater)
12/31/2020
Subsidiary
None
Jurisdiction
Exhibit 21.8
Delmarva Power & Light Company (50% and Greater)
12/31/2020
Subsidiary
None
Jurisdiction
Exhibit 21.9
Atlantic City Electric Company (50% and Greater)
12/31/2020
Subsidiary
Atlantic City Electric Transition Funding LLC
Jurisdiction
Delaware
CONSENT OF INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM
We hereby consent to the incorporation by reference in the Registration Statements on Form S-3 (No. 333-233543 and No. 333-222989), Form S-4 (No.
333-209209) and on Form S-8 (No. 333-238747, No. 333-238720, No. 333-219037, No. 333-215114, No. 333-189849, No. 333-175162, No. 333-127377,
No. 333-37082, No. 333-49780 and No. 333-61390) of Exelon Corporation of our report dated February 24, 2021 relating to the financial statements,
financial statement schedules and the effectiveness of internal control over financial reporting, which appears in this Form 10-K.
Exhibit 23.1
/s/ PricewaterhouseCoopers LLP
Chicago, Illinois
February 24, 2021
CONSENT OF INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM
We hereby consent to the incorporation by reference in the Registration Statements on Form S-3 (No. 333-233543-01) and Form S-4 (No. 333-184712) of
Exelon Generation Company, LLC of our report dated February 24, 2021 relating to the financial statements and financial statement schedule, which
appears in this Form 10-K.
Exhibit 23.2
/s/ PricewaterhouseCoopers LLP
Baltimore, Maryland
February 24, 2021
CONSENT OF INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM
We hereby consent to the incorporation by reference in the Registration Statement on Form S-3 (No. 333-233543-02) of Commonwealth Edison Company of
our report dated February 24, 2021 relating to the financial statements and financial statement schedule, which appears in this Form 10-K.
Exhibit 23.3
/s/ PricewaterhouseCoopers LLP
Chicago, Illinois
February 24, 2021
CONSENT OF INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM
We hereby consent to the incorporation by reference in the Registration Statement on Form S-3 (No. 333-233543-03) of PECO Energy Company of our
report dated February 24, 2021 relating to the financial statements and financial statement schedule, which appears in this Form 10-K.
Exhibit 23.4
/s/ PricewaterhouseCoopers LLP
Philadelphia, Pennsylvania
February 24, 2021
CONSENT OF INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM
We hereby consent to the incorporation by reference in the Registration Statement on Form S-3 (No. 333-233543-04) of Baltimore Gas and Electric
Company of our report dated February 24, 2021 relating to the financial statements and financial statement schedule, which appears in this Form 10-K.
Exhibit 23.5
/s/ PricewaterhouseCoopers LLP
Baltimore, Maryland
February 24, 2021
CONSENT OF INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM
We hereby consent to the incorporation by reference in the Registration Statement on Form S-3 (No. 333-233543-05) of Potomac Electric Power Company
of our report dated February 24, 2021 relating to the financial statements and financial statement schedule, which appears in this Form 10-K.
Exhibit 23.6
/s/ PricewaterhouseCoopers LLP
Philadelphia, Pennsylvania
February 24, 2021
CONSENT OF INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM
We hereby consent to the incorporation by reference in the Registration Statement on Form S-3 (No.333-233543-06) of Delmarva Power & Light Company
of our report dated February 24, 2021 relating to the financial statements and financial statement schedule, which appears in this Form 10-K.
Exhibit 23.7
/s/ PricewaterhouseCoopers LLP
Philadelphia, Pennsylvania
February 24, 2021
CONSENT OF INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM
We hereby consent to the incorporation by reference in the Registration Statement on Form S-3 (No. 333-233543-07) of Atlantic City Electric Company of
our report dated February 24, 2021 relating to the financial statements and financial statement schedule, which appears in this Form 10-K.
Exhibit 23.8
/s/ PricewaterhouseCoopers LLP
Philadelphia, Pennsylvania
February 24, 2021
KNOW ALL MEN BY THESE PRESENTS that I, Anthony K. Anderson, do hereby appoint Christopher M. Crane and Gayle E. Littleton, or either of them,
attorney for me and in my name and on my behalf to sign the annual Securities and Exchange Commission report on Form 10-K for 2020 of Exelon
Corporation, together with any amendments thereto, to be filed with the Securities and Exchange Commission, and generally to do and perform all things
necessary to be done in the premises as fully and effectually in all respects as I could do if personally present.
POWER OF ATTORNEY
Exhibit 24.1
/s/ ANTHONY K. ANDERSON
Anthony K. Anderson
DATE: February 5, 2021
POWER OF ATTORNEY
Exhibit 24.2
KNOW ALL MEN BY THESE PRESENTS that I, Ann C. Berzin, do hereby appoint Christopher M. Crane and Gayle E. Littleton, or either of them, attorney
for me and in my name and on my behalf to sign the annual Securities and Exchange Commission report on Form 10-K for 2020 of Exelon Corporation,
together with any amendments thereto, to be filed with the Securities and Exchange Commission, and generally to do and perform all things necessary to be
done in the premises as fully and effectually in all respects as I could do if personally present.
/s/ ANN C. BERZIN
Ann C. Berzin
DATE: February 10, 2021
POWER OF ATTORNEY
Exhibit 24.3
KNOW ALL MEN BY THESE PRESENTS that I, Laurie Brlas, do hereby appoint Christopher M. Crane and Gayle E. Littleton, or either of them, attorney
for me and in my name and on my behalf to sign the annual Securities and Exchange Commission report on Form 10-K for 2020 of Exelon Corporation,
together with any amendments thereto, to be filed with the Securities and Exchange Commission, and generally to do and perform all things necessary to be
done in the premises as fully and effectually in all respects as I could do if personally present.
/s/ LAURIE BRLAS
Laurie Brlas
DATE: February 7, 2021
POWER OF ATTORNEY
Exhibit 24.4
KNOW ALL MEN BY THESE PRESENTS that I, Christopher M. Crane, do hereby appoint Gayle E. Littleton attorney for me and in my name and on my
behalf to sign the annual Securities and Exchange Commission report on Form 10-K for 2020 of Exelon Corporation, together with any amendments thereto,
to be filed with the Securities and Exchange Commission, and generally to do and perform all things necessary to be done in the premises as fully and
effectually in all respects as I could do if personally present.
/s/ CHRISTOPHER M. CRANE
Christopher M. Crane
DATE: February 23, 2021
POWER OF ATTORNEY
Exhibit 24.5
KNOW ALL MEN BY THESE PRESENTS that I, Yves C. de Balmann, do hereby appoint Christopher M. Crane and Gayle E. Littleton, or either of them,
attorney for me and in my name and on my behalf to sign the annual Securities and Exchange Commission report on Form 10-K for 2020 of Exelon
Corporation, together with any amendments thereto, to be filed with the Securities and Exchange Commission, and generally to do and perform all things
necessary to be done in the premises as fully and effectually in all respects as I could do if personally present.
/s/ YVES C. DE BALMANN
Yves C. de Balmann
DATE: February 5, 2021
POWER OF ATTORNEY
Exhibit 24.6
KNOW ALL MEN BY THESE PRESENTS that I, Nicholas DeBenedictis, do hereby appoint Christopher M. Crane and Gayle E. Littleton, or either of them,
attorney for me and in my name and on my behalf to sign the annual Securities and Exchange Commission report on Form 10-K for 2020 of Exelon
Corporation, together with any amendments thereto, to be filed with the Securities and Exchange Commission, and generally to do and perform all things
necessary to be done in the premises as fully and effectually in all respects as I could do if personally present.
/s/ NICHOLAS DEBENEDICTIS
Nicholas DeBenedictis
DATE: February 22, 2021
POWER OF ATTORNEY
Exhibit 24.7
KNOW ALL MEN BY THESE PRESENTS that I, Linda P. Jojo, do hereby appoint Christopher M. Crane and Gayle E. Littleton, or either of them, attorney
for me and in my name and on my behalf to sign the annual Securities and Exchange Commission report on Form 10-K for 2020 of Exelon Corporation,
together with any amendments thereto, to be filed with the Securities and Exchange Commission, and generally to do and perform all things necessary to be
done in the premises as fully and effectually in all respects as I could do if personally present.
/s/ LINDA P. JOJO
Linda P. Jojo
DATE: February 5, 2021
POWER OF ATTORNEY
Exhibit 24.8
KNOW ALL MEN BY THESE PRESENTS that I, Paul Joskow, do hereby appoint Christopher M. Crane and Gayle E. Littleton, or either of them, attorney
for me and in my name and on my behalf to sign the annual Securities and Exchange Commission report on Form 10-K for 2020 of Exelon Corporation,
together with any amendments thereto, to be filed with the Securities and Exchange Commission, and generally to do and perform all things necessary to be
done in the premises as fully and effectually in all respects as I could do if personally present.
/s/ PAUL L. JOSKOW
Paul L. Joskow
DATE: February 5, 2021
POWER OF ATTORNEY
Exhibit 24.9
KNOW ALL MEN BY THESE PRESENTS that I, Robert J. Lawless, do hereby appoint Christopher M. Crane and Gayle E. Littleton, or either of them,
attorney for me and in my name and on my behalf to sign the annual Securities and Exchange Commission report on Form 10-K for 2020 of Exelon
Corporation, together with any amendments thereto, to be filed with the Securities and Exchange Commission, and generally to do and perform all things
necessary to be done in the premises as fully and effectually in all respects as I could do if personally present.
/s/ ROBERT J. LAWLESS
Robert J. Lawless
DATE: February 22, 2021
POWER OF ATTORNEY
Exhibit 24.10
KNOW ALL MEN BY THESE PRESENTS that I, Marjorie Rodgers Cheshire, do hereby appoint Christopher M. Crane and Gayle E. Littleton, or either of
them, attorney for me and in my name and on my behalf to sign the annual Securities and Exchange Commission report on Form 10-K for 2020 of Exelon
Corporation, together with any amendments thereto, to be filed with the Securities and Exchange Commission, and generally to do and perform all things
necessary to be done in the premises as fully and effectually in all respects as I could do if personally present.
/s/ MARJORIE RODGERS CHESHIRE
Marjorie Rodgers Cheshire
DATE: February 5, 2021
POWER OF ATTORNEY
Exhibit 24.12
KNOW ALL MEN BY THESE PRESENTS that I, Mayo A. Shattuck III, do hereby appoint Christopher M. Crane and Gayle E. Littleton, or either of them,
attorney for me and in my name and on my behalf to sign the annual Securities and Exchange Commission report on Form 10-K for 2020 of Exelon
Corporation, together with any amendments thereto, to be filed with the Securities and Exchange Commission, and generally to do and perform all things
necessary to be done in the premises as fully and effectually in all respects as I could do if personally present.
/s/ MAYO A. SHATTUCK III
Mayo A. Shattuck III
DATE: February 8, 2021
POWER OF ATTORNEY
Exhibit 24.14
KNOW ALL MEN BY THESE PRESENTS that I, John F. Young, do hereby appoint Christopher M. Crane and Gayle E. Littleton, or either of them, attorney
for me and in my name and on my behalf to sign the annual Securities and Exchange Commission report on Form 10-K for 2020 of Exelon Corporation,
together with any amendments thereto, to be filed with the Securities and Exchange Commission, and generally to do and perform all things necessary to be
done in the premises as fully and effectually in all respects as I could do if personally present.
/s/ JOHN F. YOUNG
John F. Young
DATE: February 8, 2021
POWER OF ATTORNEY
Exhibit 24.15
KNOW ALL MEN BY THESE PRESENTS that I, John Richardson, do hereby appoint Christopher M. Crane and Gayle E. Littleton, or either of them,
attorney for me and in my name and on my behalf to sign the annual Securities and Exchange Commission report on Form 10-K for 2020 of Exelon
Corporation, together with any amendments thereto, to be filed with the Securities and Exchange Commission, and generally to do and perform all things
necessary to be done in the premises as fully and effectually in all respects as I could do if personally present.
/s/ JOHN RICHARDSON
John Richardson
DATE: February 5, 2021
POWER OF ATTORNEY
Exhibit 24.16
KNOW ALL MEN BY THESE PRESENTS that I, James W. Compton, do hereby appoint Joseph Dominguez and Verónica Gómez, or either of them,
attorney for me and in my name and on my behalf to sign the annual Securities and Exchange Commission report on Form 10-K for 2020 of Commonwealth
Edison Company, together with any amendments thereto, to be filed with the Securities and Exchange Commission, and generally to do and perform all
things necessary to be done in the premises as fully and effectually in all respects as I could do if personally present.
/s/ JAMES W. COMPTON
James W. Compton
DATE: February 8, 2021
POWER OF ATTORNEY
Exhibit 24.17
KNOW ALL MEN BY THESE PRESENTS that I, Christopher M. Crane, do hereby appoint Joseph Dominguez and Verónica Gómez, or either of them,
attorney for me and in my name and on my behalf to sign the annual Securities and Exchange Commission report on Form 10-K for 2020 of Commonwealth
Edison Company, together with any amendments thereto, to be filed with the Securities and Exchange Commission, and generally to do and perform all
things necessary to be done in the premises as fully and effectually in all respects as I could do if personally present.
/s/ CHRISTOPHER M. CRANE
Christopher M. Crane
DATE: February 23, 2021
POWER OF ATTORNEY
Exhibit 24.18
KNOW ALL MEN BY THESE PRESENTS that I, A. Steven Crown, do hereby appoint Joseph Dominguez and Verónica Gómez, or either of them, attorney
for me and in my name and on my behalf to sign the annual Securities and Exchange Commission report on Form 10-K for 2020 of Commonwealth Edison
Company, together with any amendments thereto, to be filed with the Securities and Exchange Commission, and generally to do and perform all things
necessary to be done in the premises as fully and effectually in all respects as I could do if personally present.
/s/ A. STEVEN CROWN
A. Steven Crown
DATE: February 22, 2021
POWER OF ATTORNEY
Exhibit 24.19
KNOW ALL MEN BY THESE PRESENTS that I, Nicholas DeBenedictis, do hereby appoint Joseph Dominguez and Verónica Gómez, or either of them,
attorney for me and in my name and on my behalf to sign the annual Securities and Exchange Commission report on Form 10-K for 2020 of Commonwealth
Edison Company, together with any amendments thereto, to be filed with the Securities and Exchange Commission, and generally to do and perform all
things necessary to be done in the premises as fully and effectually in all respects as I could do if personally present.
/s/ NICHOLAS DEBENEDICTIS
Nicholas DeBenedictis
DATE: February 22, 2021
POWER OF ATTORNEY
Exhibit 24.20
KNOW ALL MEN BY THESE PRESENTS that I, Joseph Dominguez, do hereby appoint Verónica Gómez attorney for me and in my name and on
my behalf to sign the annual Securities and Exchange Commission report on Form 10-K for 2020 of Commonwealth Edison Company, together with
any amendments thereto, to be filed with the Securities and Exchange Commission, and generally to do and perform all things necessary to be done
in the premises as fully and effectually in all respects as I could do if personally present.
/s/ JOSEPH DOMINGUEZ
Joseph Dominguez
DATE: February 23, 2021
POWER OF ATTORNEY
Exhibit 24.21
KNOW ALL MEN BY THESE PRESENTS that I, Peter V. Fazio, Jr., do hereby appoint Joseph Dominguez and Verónica Gómez, or either of them, attorney
for me and in my name and on my behalf to sign the annual Securities and Exchange Commission report on Form 10-K for 2020 of Commonwealth Edison
Company, together with any amendments thereto, to be filed with the Securities and Exchange Commission, and generally to do and perform all things
necessary to be done in the premises as fully and effectually in all respects as I could do if personally present.
/s/ PETER V. FAZIO, JR.
Peter V. Fazio, Jr.
DATE: February 5, 2021
POWER OF ATTORNEY
Exhibit 24.22
KNOW ALL MEN BY THESE PRESENTS that I, Michael H. Moskow, do hereby appoint Joseph Dominguez and Verónica Gómez, or either of them,
attorney for me and in my name and on my behalf to sign the annual Securities and Exchange Commission report on Form 10-K for 2020 of Commonwealth
Edison Company, together with any amendments thereto, to be filed with the Securities and Exchange Commission, and generally to do and perform all
things necessary to be done in the premises as fully and effectually in all respects as I could do if personally present.
/s/ MICHAEL H. MOSKOW
Michael H. Moskow
DATE: February 5, 2021
POWER OF ATTORNEY
Exhibit 24.23
KNOW ALL MEN BY THESE PRESENTS that I, Calvin G. Butler, do hereby appoint Joseph Dominguez and Verónica Gómez, or either of them, attorney
for me and in my name and on my behalf to sign the annual Securities and Exchange Commission report on Form 10-K for 2020 of Commonwealth Edison
Company, together with any amendments thereto, to be filed with the Securities and Exchange Commission, and generally to do and perform all things
necessary to be done in the premises as fully and effectually in all respects as I could do if personally present.
/s/ CALVIN G. BUTLER
Calvin G. Butler
DATE: February 15, 2021
POWER OF ATTORNEY
Exhibit 24.25
KNOW ALL MEN BY THESE PRESENTS that I, Christopher M. Crane, do hereby appoint Michael A. Innocenzo and Anthony E. Gay, or either of them,
attorney for me and in my name and on my behalf to sign the annual Securities and Exchange Commission report on Form 10-K for 2020 of PECO Energy
Company, together with any amendments thereto, to be filed with the Securities and Exchange Commission, and generally to do and perform all things
necessary to be done in the premises as fully and effectually in all respects as I could do if personally present.
/s/ CHRISTOPHER M. CRANE
Christopher M. Crane
DATE: February 23, 2021
POWER OF ATTORNEY
Exhibit 24.27
KNOW ALL MEN BY THESE PRESENTS that I, Nicholas DeBenedictis, do hereby appoint Michael A. Innocenzo and Anthony E. Gay, or either of them,
attorney for me and in my name and on my behalf to sign the annual Securities and Exchange Commission report on Form 10-K for 2020 of PECO Energy
Company, together with any amendments thereto, to be filed with the Securities and Exchange Commission, and generally to do and perform all things
necessary to be done in the premises as fully and effectually in all respects as I could do if personally present.
/s/ NICHOLAS DEBENEDICTIS
Nicholas DeBenedictis
DATE: February 22, 2021
POWER OF ATTORNEY
Exhibit 24.28
KNOW ALL MEN BY THESE PRESENTS that I, Nelson A. Diaz, do hereby appoint Michael A. Innocenzo and Anthony E. Gay, or either of them, attorney
for me and in my name and on my behalf to sign the annual Securities and Exchange Commission report on Form 10-K for 2020 of PECO Energy Company,
together with any amendments thereto, to be filed with the Securities and Exchange Commission, and generally to do and perform all things necessary to be
done in the premises as fully and effectually in all respects as I could do if personally present.
/s/ NELSON A. DIAZ
Nelson A. Diaz
DATE: February 6, 2021
POWER OF ATTORNEY
Exhibit 24.29
KNOW ALL MEN BY THESE PRESENTS that I, John S. Grady, do hereby appoint Michael A. Innocenzo and Anthony E. Gay, or either of them, attorney
for me and in my name and on my behalf to sign the annual Securities and Exchange Commission report on Form 10-K for 2020 of PECO Energy Company,
together with any amendments thereto, to be filed with the Securities and Exchange Commission, and generally to do and perform all things necessary to be
done in the premises as fully and effectually in all respects as I could do if personally present.
/s/ JOHN S. GRADY
John S. Grady
DATE: February 6, 2021
POWER OF ATTORNEY
Exhibit 24.30
KNOW ALL MEN BY THESE PRESENTS that I, Rosemarie B. Greco, do hereby appoint Michael A. Innocenzo and Anthony E. Gay, or either of them,
attorney for me and in my name and on my behalf to sign the annual Securities and Exchange Commission report on Form 10-K for 2020 of PECO Energy
Company, together with any amendments thereto, to be filed with the Securities and Exchange Commission, and generally to do and perform all things
necessary to be done in the premises as fully and effectually in all respects as I could do if personally present.
/s/ ROSEMARIE B. GRECO
Rosemarie B. Greco
DATE: February 9, 2021
KNOW ALL MEN BY THESE PRESENTS that I, Michael A. Innocenzo, do hereby appoint Anthony E. Gay attorney for me and in my name and on my
behalf to sign the annual Securities and Exchange Commission report on Form 10-K for 2020 of PECO Energy Company, together with any amendments
thereto, to be filed with the Securities and Exchange Commission, and generally to do and perform all things necessary to be done in the premises as fully
and effectually in all respects as I could do if personally present.
POWER OF ATTORNEY
Exhibit 24.31
/s/ MICHAEL A. INNOCENZO
Michael A. Innocenzo
DATE: February 23, 2021
POWER OF ATTORNEY
Exhibit 24.32
KNOW ALL MEN BY THESE PRESENTS that I, Charisse R. Lillie, do hereby appoint Michael A. Innocenzo and Anthony E. Gay, or either of them,
attorney for me and in my name and on my behalf to sign the annual Securities and Exchange Commission report on Form 10-K for 2020 of PECO Energy
Company, together with any amendments thereto, to be filed with the Securities and Exchange Commission, and generally to do and perform all things
necessary to be done in the premises as fully and effectually in all respects as I could do if personally present.
/s/ CHARISSE R. LILLIE
Charisse R. Lillie
DATE: February 5, 2021
POWER OF ATTORNEY
Exhibit 24.33
KNOW ALL MEN BY THESE PRESENTS that I, Calvin G. Butler, do hereby appoint Michael A. Innocenzo and Anthony E. Gay, or either of them, attorney
for me and in my name and on my behalf to sign the annual Securities and Exchange Commission report on Form 10-K for 2020 of PECO Energy Company,
together with any amendments thereto, to be filed with the Securities and Exchange Commission, and generally to do and perform all things necessary to be
done in the premises as fully and effectually in all respects as I could do if personally present.
/s/ CALVIN G. BUTLER
Calvin G. Butler
DATE: February 15, 2021
POWER OF ATTORNEY
Exhibit 24.34
KNOW ALL MEN BY THESE PRESENTS that I, Ann C. Berzin, do hereby appoint Carim V. Khouzami and John D. Corse, or either of them, attorney for
me and in my name and on my behalf to sign the annual Securities and Exchange Commission report on Form 10-K for 2020 of Baltimore Gas & Electric
Company, together with any amendments thereto, to be filed with the Securities and Exchange Commission, and generally to do and perform all things
necessary to be done in the premises as fully and effectually in all respects as I could do if personally present.
/s/ ANN C. BERZIN
Ann C. Berzin
DATE: February 10, 2021
POWER OF ATTORNEY
Exhibit 24.35
KNOW ALL MEN BY THESE PRESENTS that I, Carim V. Khouzami, do hereby appoint John D. Corse attorney for me and in my name and on my behalf
to sign the annual Securities and Exchange Commission report on Form 10-K for 2020 of Baltimore Gas & Electric Company, together with any amendments
thereto, to be filed with the Securities and Exchange Commission, and generally to do and perform all things necessary to be done in the premises as fully
and effectually in all respects as I could do if personally present.
/s/ CARIM V. KHOUZAMI
Carim V. Khouzami
DATE: February 23, 2021
POWER OF ATTORNEY
Exhibit 24.36
KNOW ALL MEN BY THESE PRESENTS that I, Christopher M. Crane, do hereby appoint Carim V. Khouzami and John D. Corse, or either of them,
attorney for me and in my name and on my behalf to sign the annual Securities and Exchange Commission report on Form 10-K for 2020 of Baltimore Gas &
Electric Company, together with any amendments thereto, to be filed with the Securities and Exchange Commission, and generally to do and perform all
things necessary to be done in the premises as fully and effectually in all respects as I could do if personally present.
/s/ CHRISTOPHER M. CRANE
Christopher M. Crane
DATE: February 23, 2021
POWER OF ATTORNEY
Exhibit 24.37
KNOW ALL MEN BY THESE PRESENTS that I, Michael E. Cryor, do hereby appoint Carim V. Khouzami and John D. Corse, or either of them, attorney for
me and in my name and on my behalf to sign the annual Securities and Exchange Commission report on Form 10-K for 2020 of Baltimore Gas & Electric
Company, together with any amendments thereto, to be filed with the Securities and Exchange Commission, and generally to do and perform all things
necessary to be done in the premises as fully and effectually in all respects as I could do if personally present.
/s/ MICHAEL E. CRYOR
Michael E. Cryor
DATE: February 9, 2021
POWER OF ATTORNEY
Exhibit 24.38
KNOW ALL MEN BY THESE PRESENTS that I, James R. Curtiss, do hereby appoint Carim V. Khouzami and John D. Corse, or either of them, for me and
in my name and on my behalf to sign the annual Securities and Exchange Commission report on Form 10-K for 2020 of Baltimore Gas & Electric Company,
together with any amendments thereto, to be filed with the Securities and Exchange Commission, and generally to do and perform all things necessary to be
done in the premises as fully and effectually in all respects as I could do if personally present.
/s/ JAMES R. CURTISS
James R. Curtiss
DATE: February 5, 2021
POWER OF ATTORNEY
Exhibit 24.39
KNOW ALL MEN BY THESE PRESENTS that I, Joseph Haskins, Jr., do hereby appoint Carim V. Khouzami and John D. Corse, or either of them, attorney
for me and in my name and on my behalf to sign the annual Securities and Exchange Commission report on Form 10-K for 2020 of Baltimore Gas & Electric
Company, together with any amendments thereto, to be filed with the Securities and Exchange Commission, and generally to do and perform all things
necessary to be done in the premises as fully and effectually in all respects as I could do if personally present.
/s/ JOSEPH HASKINS, JR.
Joseph Haskins, Jr.
DATE: February 10, 2021
POWER OF ATTORNEY
Exhibit 24.40
KNOW ALL MEN BY THESE PRESENTS that I, Calvin G. Butler, do hereby appoint Carim V. Khouzami and John D. Corse, or either of them, attorney for
me and in my name and on my behalf to sign the annual Securities and Exchange Commission report on Form 10-K for 2020 of Baltimore Gas & Electric
Company, together with any amendments thereto, to be filed with the Securities and Exchange Commission, and generally to do and perform all things
necessary to be done in the premises as fully and effectually in all respects as I could do if personally present.
/s/ CALVIN G. BUTLER
Calvin G. Butler
DATE: February 15, 2021
POWER OF ATTORNEY
Exhibit 24.41
KNOW ALL MEN BY THESE PRESENTS that I, Michael D. Sullivan, do hereby appoint Carim V. Khouzami. and John D. Corse, or either of them, attorney
for me and in my name and on my behalf to sign the annual Securities and Exchange Commission report on Form 10-K for 2020 of Baltimore Gas & Electric
Company, together with any amendments thereto, to be filed with the Securities and Exchange Commission, and generally to do and perform all things
necessary to be done in the premises as fully and effectually in all respects as I could do if personally present.
/s/ MICHAEL D. SULLIVAN
Michael D. Sullivan
DATE: February 19, 2021
POWER OF ATTORNEY
Exhibit 24.42
KNOW ALL MEN BY THESE PRESENTS that I, Maria Harris Tildon, do hereby appoint Carim V. Khouzami. and John D. Corse, or either of them, attorney
for me and in my name and on my behalf to sign the annual Securities and Exchange Commission report on Form 10-K for 2020 of Baltimore Gas & Electric
Company, together with any amendments thereto, to be filed with the Securities and Exchange Commission, and generally to do and perform all things
necessary to be done in the premises as fully and effectually in all respects as I could do if personally present.
/s/ MARIA HARRIS TILDON
Maria Harris Tildon
DATE: February 22, 2021
POWER OF ATTORNEY
Exhibit 24.43
KNOW ALL MEN BY THESE PRESENTS that I, Christopher M. Crane, do hereby appoint David M. Velazquez and Wendy E. Stark, or either of them,
attorney for me and in my name and on my behalf to sign the annual Securities and Exchange Commission report on Form 10-K for 2020 of Pepco Holdings
LLC, together with any amendments thereto, to be filed with the Securities and Exchange Commission, and generally to do and perform all things necessary
to be done in the premises as fully and effectually in all respects as I could do if personally present.
/s/ CHRISTOPHER M. CRANE
Christopher M. Crane
Date: February 23, 2021
POWER OF ATTORNEY
Exhibit 24.44
KNOW ALL MEN BY THESE PRESENTS that I, Linda W. Cropp, do hereby appoint David M. Velazquez and Wendy E. Stark, or either of them, attorney
for me and in my name and on my behalf to sign the annual Securities and Exchange Commission report on Form 10-K for 2020 of Pepco Holdings LLC,
together with any amendments thereto, to be filed with the Securities and Exchange Commission, and generally to do and perform all things necessary to be
done in the premises as fully and effectually in all respects as I could do if personally present.
/s/ LINDA W. CROPP
Linda W. Cropp
Date: February 8, 2021
POWER OF ATTORNEY
Exhibit 24.45
KNOW ALL MEN BY THESE PRESENTS that I, Michael E. Cryor, do hereby appoint David M. Velazquez and Wendy E. Stark, or either of them, attorney
for me and in my name and on my behalf to sign the annual Securities and Exchange Commission report on Form 10-K for 2020 of Pepco Holdings LLC,
together with any amendments thereto, to be filed with the Securities and Exchange Commission, and generally to do and perform all things necessary to be
done in the premises as fully and effectually in all respects as I could do if personally present.
/s/ MICHAEL CRYOR
Michael Cryor
Date: February 9, 2021
POWER OF ATTORNEY
Exhibit 24.46
KNOW ALL MEN BY THESE PRESENTS that I, Ernest Dianastasis, do hereby appoint David M. Velazquez and Wendy E. Stark, or either of them,
attorney for me and in my name and on my behalf to sign the annual Securities and Exchange Commission report on Form 10-K for 2020 of Pepco Holdings
LLC, together with any amendments thereto, to be filed with the Securities and Exchange Commission, and generally to do and perform all things necessary
to be done in the premises as fully and effectually in all respects as I could do if personally present.
/s/ ERNEST DIANASTASIS
Ernest Dianastasis
Date: February 7, 2021
POWER OF ATTORNEY
Exhibit 24.47
KNOW ALL MEN BY THESE PRESENTS that I, Debra P. DiLorenzo, do hereby appoint David M. Velazquez and Wendy E. Stark, or either of them,
attorney for me and in my name and on my behalf to sign the annual Securities and Exchange Commission report on Form 10-K for 2020 of Pepco Holdings
LLC, together with any amendments thereto, to be filed with the Securities and Exchange Commission, and generally to do and perform all things necessary
to be done in the premises as fully and effectually in all respects as I could do if personally present.
/s/ DEBRA P. DILORENZO
Debra P. DiLorenzo
Date: February 7, 2021
POWER OF ATTORNEY
Exhibit 24.48
KNOW ALL MEN BY THESE PRESENTS that I, Calvin G. Butler, do hereby appoint David M. Velazquez and Wendy E. Stark, or either of them, attorney
for me and in my name and on my behalf to sign the annual Securities and Exchange Commission report on Form 10-K for 2020 of Pepco Holdings LLC,
together with any amendments thereto, to be filed with the Securities and Exchange Commission, and generally to do and perform all things necessary to be
done in the premises as fully and effectually in all respects as I could do if personally present.
/s/ CALVIN G. BUTLER
Calvin G. Butler
Date: February 15, 2021
POWER OF ATTORNEY
Exhibit 24.49
KNOW ALL MEN BY THESE PRESENTS that I, David M. Velazquez, do hereby appoint Wendy E. Stark as attorney for me and in my name and on my
behalf to sign the annual Securities and Exchange Commission report on Form 10-K for 2020 of Pepco Holdings LLC, together with any amendments
thereto, to be filed with the Securities and Exchange Commission, and generally to do and perform all things necessary to be done in the premises as fully
and effectually in all respects as I could do if personally present.
/s/ DAVID M. VELAZQUEZ
David M. Velazquez
DATE: February 23, 2021
POWER OF ATTORNEY
Exhibit 24.50
KNOW ALL MEN BY THESE PRESENTS that I, J. Tyler Anthony, do hereby appoint David M. Velazquez and Wendy E. Stark, or either of them, attorney
for me and in my name and on my behalf to sign the annual Securities and Exchange Commission report on Form 10-K for 2020 of Potomac Electric Power
Company, together with any amendments thereto, to be filed with the Securities and Exchange Commission, and generally to do and perform all things
necessary to be done in the premises as fully and effectually in all respects as I could do if personally present.
/s/ J. TYLER ANTHONY
J. Tyler Anthony
DATE: February 19, 2021
POWER OF ATTORNEY
Exhibit 24.51
KNOW ALL MEN BY THESE PRESENTS that I, Phillip S. Barnett, do hereby appoint David M. Velazquez and Wendy E. Stark, or either of them, attorney
for me and in my name and on my behalf to sign the annual Securities and Exchange Commission report on Form 10-K for 2020 of Potomac Electric Power
Company, together with any amendments thereto, to be filed with the Securities and Exchange Commission, and generally to do and perform all things
necessary to be done in the premises as fully and effectually in all respects as I could do if personally present.
/s/ PHILLIP S. BARNETT
Phillip S. Barnett
DATE: February 23, 2021
POWER OF ATTORNEY
Exhibit 24.52
KNOW ALL MEN BY THESE PRESENTS that I, Christopher M. Crane, do hereby appoint David M. Velazquez and Wendy E. Stark, or either of them,
attorney for me and in my name and on my behalf to sign the annual Securities and Exchange Commission report on Form 10-K for 2020 of Potomac
Electric Power Company, together with any amendments thereto, to be filed with the Securities and Exchange Commission, and generally to do and perform
all things necessary to be done in the premises as fully and effectually in all respects as I could do if personally present.
/s/ CHRISTOPHER M. CRANE
Christopher M. Crane
DATE: February 23, 2021
POWER OF ATTORNEY
Exhibit 24.53
KNOW ALL MEN BY THESE PRESENTS that I, Melissa A. Lavinson, do hereby appoint David M. Velazquez and Wendy E. Stark, or either of
them, attorney for me and in my name and on my behalf to sign the annual Securities and Exchange Commission report on Form 10-K for 2020 of
Potomac Electric Power Company, together with any amendments thereto, to be filed with the Securities and Exchange Commission, and generally to
do and perform all things necessary to be done in the premises as fully and effectually in all respects as I could do if personally present.
/s/ MELISSA A. LAVINSON
Melissa A. Lavinson
DATE: February 19, 2021
POWER OF ATTORNEY
Exhibit 24.54
KNOW ALL MEN BY THESE PRESENTS that I, Kevin M. McGowan, do hereby appoint David M. Velazquez and Wendy E. Stark, or either of them,
attorney for me and in my name and on my behalf to sign the annual Securities and Exchange Commission report on Form 10-K for 2020 of Potomac
Electric Power Company, together with any amendments thereto, to be filed with the Securities and Exchange Commission, and generally to do and perform
all things necessary to be done in the premises as fully and effectually in all respects as I could do if personally present.
/s/ KEVIN M. MCGOWAN
Kevin M. McGowan
DATE: February 20, 2021
POWER OF ATTORNEY
Exhibit 24.55
KNOW ALL MEN BY THESE PRESENTS that I, Calvin G. Butler, do hereby appoint David M. Velazquez and Wendy E. Stark, or either of them, attorney
for me and in my name and on my behalf to sign the annual Securities and Exchange Commission report on Form 10-K for 2020 of Potomac Electric Power
Company, together with any amendments thereto, to be filed with the Securities and Exchange Commission, and generally to do and perform all things
necessary to be done in the premises as fully and effectually in all respects as I could do if personally present.
/s/ CALVIN G. BUTLER
Calvin G. Butler
DATE: February 15, 2021
POWER OF ATTORNEY
Exhibit 24.56
KNOW ALL MEN BY THESE PRESENTS that I, David M. Velazquez, do hereby appoint Wendy E. Stark, attorney for me and in my name and on my
behalf to sign the annual Securities and Exchange Commission report on Form 10-K for 2020 of Potomac Electric Power Company, together with any
amendments thereto, to be filed with the Securities and Exchange Commission, and generally to do and perform all things necessary to be done in the
premises as fully and effectually in all respects as I could do if personally present.
/s/ DAVID M. VELAZQUEZ
David M. Velazquez
DATE: February 23, 2021
POWER OF ATTORNEY
Exhibit 24.57
KNOW ALL MEN BY THESE PRESENTS that I, Calvin G. Butler, do hereby appoint David M. Velazquez and Wendy E. Stark, or either of them, attorney
for me and in my name and on my behalf to sign the annual Securities and Exchange Commission report on Form 10-K for 2020 of Delmarva Power & Light
Company, together with any amendments thereto, to be filed with the Securities and Exchange Commission, and generally to do and perform all things
necessary to be done in the premises as fully and effectually in all respects as I could do if personally present.
/s/ CALVIN G. BUTLER
Calvin G. Butler
DATE: February 15, 2021
POWER OF ATTORNEY
Exhibit 24.58
KNOW ALL MEN BY THESE PRESENTS that I, David M. Velazquez, do hereby appoint Wendy E. Stark as attorney for me and in my name and on my
behalf to sign the annual Securities and Exchange Commission report on Form 10-K for 2020 of Delmarva Power & Light Company, together with any
amendments thereto, to be filed with the Securities and Exchange Commission, and generally to do and perform all things necessary to be done in the
premises as fully and effectually in all respects as I could do if personally present.
/s/ DAVID M. VELAZQUEZ
David M. Velazquez
DATE: February 23, 2021
POWER OF ATTORNEY
Exhibit 24.59
KNOW ALL MEN BY THESE PRESENTS that I, David M. Velazquez, do hereby appoint Wendy E. Stark as attorney for me and in my name and on my
behalf to sign the annual Securities and Exchange Commission report on Form 10-K for 2020 of Atlantic City Electric Company, together with any
amendments thereto, to be filed with the Securities and Exchange Commission, and generally to do and perform all things necessary to be done in the
premises as fully and effectually in all respects as I could do if personally present.
/s/ DAVID M. VELAZQUEZ
David M. Velazquez
DATE: February 23, 2021
CERTIFICATION PURSUANT TO RULE 13a-14(a) AND 15d-14(a) OF THE
SECURITIES AND EXCHANGE ACT OF 1934
Exhibit 31.1
I, Christopher M. Crane, certify that:
1.
I have reviewed this annual report on Form 10-K of Exelon Corporation;
2. Based on my knowledge, this report does not contain any untrue statement of a material fact or omit to state a material fact necessary to make the
statements made, in light of the circumstances under which such statements were made, not misleading with respect to the period covered by this
report;
3. Based on my knowledge, the financial statements, and other financial information included in this report, fairly present in all material respects the
financial condition, results of operations and cash flows of the registrant as of, and for, the periods presented in this report;
4. The registrant’s other certifying officer and I are responsible for establishing and maintaining disclosure controls and procedures (as defined in
Exchange Act Rules 13a-15(e) and 15d-15(e)) and internal control over financial reporting (as defined in Exchange Act Rules 13a-15(f) and 15d-15(f))
for the registrant and have:
(a) Designed such disclosure controls and procedures, or caused such disclosure controls and procedures to be designed under our supervision, to
ensure that material information relating to the registrant, including its consolidated subsidiaries, is made known to us by others within those
entities, particularly during the period in which this report is being prepared;
(b) Designed such internal control over financial reporting, or caused such internal control over financial reporting to be designed under our
supervision, to provide reasonable assurance regarding the reliability of financial reporting and the preparation of financial statements for external
purposes in accordance with generally accepted accounting principles;
(c) Evaluated the effectiveness of the registrant’s disclosure controls and procedures and presented in this report our conclusions about the
effectiveness of the disclosure controls and procedures, as of the end of the period covered by this report based on such evaluation; and
(d) Disclosed in this report any change in the registrant’s internal control over financial reporting that occurred during the registrant’s most recent fiscal
quarter (the registrant’s fourth fiscal quarter in the case of an annual report) that has materially affected, or is reasonably likely to materially affect,
the registrant’s internal control over financial reporting; and
5. The registrant’s other certifying officer and I have disclosed, based on our most recent evaluation of internal control over financial reporting, to the
registrant’s auditors and the audit committee of the registrant’s board of directors (or persons performing the equivalent functions):
(a) All significant deficiencies and material weaknesses in the design or operation of internal control over financial reporting which are reasonably likely
to adversely affect the registrant’s ability to record, process, summarize and report financial information; and
(b) Any fraud, whether or not material, that involves management or other employees who have a significant role in the registrant’s internal control over
financial reporting.
Date: February 24, 2021
/s/ CHRISTOPHER M. CRANE
President and Chief Executive Officer
(Principal Executive Officer)
Exhibit 31.2
CERTIFICATION PURSUANT TO RULE 13a-14(a) AND 15d-14(a) OF THE SECURITIES
AND EXCHANGE ACT OF 1934
I have reviewed this annual report on Form 10-K of Exelon Corporation;
I, Joseph Nigro, certify that:
1.
2. Based on my knowledge, this report does not contain any untrue statement of a material fact or omit to state a material fact necessary to make the
statements made, in light of the circumstances under which such statements were made, not misleading with respect to the period covered by this
report;
3. Based on my knowledge, the financial statements, and other financial information included in this report, fairly present in all material respects the
financial condition, results of operations and cash flows of the registrant as of, and for, the periods presented in this report;
4. The registrant’s other certifying officer and I are responsible for establishing and maintaining disclosure controls and procedures (as defined in
Exchange Act Rules 13a-15(e) and 15d-15(e)) and internal control over financial reporting (as defined in Exchange Act Rules 13a-15(f) and 15d-15(f))
for the registrant and have:
(a) Designed such disclosure controls and procedures, or caused such disclosure controls and procedures to be designed under our supervision, to
ensure that material information relating to the registrant, including its consolidated subsidiaries, is made known to us by others within those
entities, particularly during the period in which this report is being prepared;
(b) Designed such internal control over financial reporting, or caused such internal control over financial reporting to be designed under our
supervision, to provide reasonable assurance regarding the reliability of financial reporting and the preparation of financial statements for external
purposes in accordance with generally accepted accounting principles;
(c) Evaluated the effectiveness of the registrant’s disclosure controls and procedures and presented in this report our conclusions about the
effectiveness of the disclosure controls and procedures, as of the end of the period covered by this report based on such evaluation; and
(d) Disclosed in this report any change in the registrant’s internal control over financial reporting that occurred during the registrant’s most recent fiscal
quarter (the registrant’s fourth fiscal quarter in the case of an annual report) that has materially affected, or is reasonably likely to materially affect,
the registrant’s internal control over financial reporting; and
5. The registrant’s other certifying officer and I have disclosed, based on our most recent evaluation of internal control over financial reporting, to the
registrant’s auditors and the audit committee of the registrant’s board of directors (or persons performing the equivalent functions):
(a) All significant deficiencies and material weaknesses in the design or operation of internal control over financial reporting which are reasonably likely
to adversely affect the registrant’s ability to record, process, summarize and report financial information; and
(b) Any fraud, whether or not material, that involves management or other employees who have a significant role in the registrant’s internal control over
financial reporting.
Date: February 24, 2021
/s/ JOSEPH NIGRO
Senior Executive Vice President and Chief Financial Officer
(Principal Financial Officer)
CERTIFICATION PURSUANT TO RULE 13a-14(a) AND 15d-14(a) OF THE
SECURITIES AND EXCHANGE ACT OF 1934
Exhibit 31.3
I, Christopher M. Crane, certify that:
1.
I have reviewed this annual report on Form 10-K of Exelon Generation Company, LLC;
2. Based on my knowledge, this report does not contain any untrue statement of a material fact or omit to state a material fact necessary to make the
statements made, in light of the circumstances under which such statements were made, not misleading with respect to the period covered by this
report;
3. Based on my knowledge, the financial statements, and other financial information included in this report, fairly present in all material respects the
financial condition, results of operations and cash flows of the registrant as of, and for, the periods presented in this report;
4. The registrant’s other certifying officer and I are responsible for establishing and maintaining disclosure controls and procedures (as defined in
Exchange Act Rules 13a-15(e) and 15d-15(e)) and internal control over financial reporting (as defined in Exchange Act Rules 13a-15(f) and 15d-15(f))
for the registrant and have:
(a) Designed such disclosure controls and procedures, or caused such disclosure controls and procedures to be designed under our supervision, to
ensure that material information relating to the registrant, including its consolidated subsidiaries, is made known to us by others within those
entities, particularly during the period in which this report is being prepared;
(b) Designed such internal control over financial reporting, or caused such internal control over financial reporting to be designed under our
supervision, to provide reasonable assurance regarding the reliability of financial reporting and the preparation of financial statements for external
purposes in accordance with generally accepted accounting principles;
(c) Evaluated the effectiveness of the registrant’s disclosure controls and procedures and presented in this report our conclusions about the
effectiveness of the disclosure controls and procedures, as of the end of the period covered by this report based on such evaluation; and
(d) Disclosed in this report any change in the registrant’s internal control over financial reporting that occurred during the registrant’s most recent fiscal
quarter (the registrant’s fourth fiscal quarter in the case of an annual report) that has materially affected, or is reasonably likely to materially affect,
the registrant’s internal control over financial reporting; and
5. The registrant’s other certifying officer and I have disclosed, based on our most recent evaluation of internal control over financial reporting, to the
registrant’s auditors and the audit committee of the registrant’s board of directors (or persons performing the equivalent functions):
(a) All significant deficiencies and material weaknesses in the design or operation of internal control over financial reporting which are reasonably likely
to adversely affect the registrant’s ability to record, process, summarize and report financial information; and
(b) Any fraud, whether or not material, that involves management or other employees who have a significant role in the registrant’s internal control over
financial reporting.
Date: February 24, 2021
/s/ CHRISTOPHER M. CRANE
Principal Executive Officer
CERTIFICATION PURSUANT TO RULE 13a-14(a) AND 15d-14(a) OF THE
SECURITIES AND EXCHANGE ACT OF 1934
Exhibit 31.4
I, Bryan P. Wright, certify that:
I have reviewed this annual report on Form 10-K of Exelon Generation Company, LLC;
1.
2. Based on my knowledge, this report does not contain any untrue statement of a material fact or omit to state a material fact necessary to make the
statements made, in light of the circumstances under which such statements were made, not misleading with respect to the period covered by this
report;
3. Based on my knowledge, the financial statements, and other financial information included in this report, fairly present in all material respects the
financial condition, results of operations and cash flows of the registrant as of, and for, the periods presented in this report;
4. The registrant’s other certifying officer and I are responsible for establishing and maintaining disclosure controls and procedures (as defined in
Exchange Act Rules 13a-15(e) and 15d-15(e)) and internal control over financial reporting (as defined in Exchange Act Rules 13a-15(f) and 15d-15(f))
for the registrant and have:
(a) Designed such disclosure controls and procedures, or caused such disclosure controls and procedures to be designed under our supervision, to
ensure that material information relating to the registrant, including its consolidated subsidiaries, is made known to us by others within those
entities, particularly during the period in which this report is being prepared;
(b) Designed such internal control over financial reporting, or caused such internal control over financial reporting to be designed under our
supervision, to provide reasonable assurance regarding the reliability of financial reporting and the preparation of financial statements for external
purposes in accordance with generally accepted accounting principles;
(c) Evaluated the effectiveness of the registrant’s disclosure controls and procedures and presented in this report our conclusions about the
effectiveness of the disclosure controls and procedures, as of the end of the period covered by this report based on such evaluation; and
(d) Disclosed in this report any change in the registrant’s internal control over financial reporting that occurred during the registrant’s most recent fiscal
quarter (the registrant’s fourth fiscal quarter in the case of an annual report) that has materially affected, or is reasonably likely to materially affect,
the registrant’s internal control over financial reporting; and
5. The registrant’s other certifying officer and I have disclosed, based on our most recent evaluation of internal control over financial reporting, to the
registrant’s auditors and the audit committee of the registrant’s board of directors (or persons performing the equivalent functions):
(a) All significant deficiencies and material weaknesses in the design or operation of internal control over financial reporting which are reasonably likely
to adversely affect the registrant’s ability to record, process, summarize and report financial information; and
(b) Any fraud, whether or not material, that involves management or other employees who have a significant role in the registrant’s internal control over
financial reporting.
Date: February 24, 2021
/s/ BRYAN P. WRIGHT
Senior Vice President and Chief Financial Officer
(Principal Financial Officer)
CERTIFICATION PURSUANT TO RULE 13a-14(a) AND 15d-14(a) OF THE
SECURITIES AND EXCHANGE ACT OF 1934
Exhibit 31.5
I, Joseph Dominguez, certify that:
1.
I have reviewed this annual report on Form 10-K of Commonwealth Edison Company;
2. Based on my knowledge, this report does not contain any untrue statement of a material fact or omit to state a material fact necessary to make the
statements made, in light of the circumstances under which such statements were made, not misleading with respect to the period covered by this
report;
3. Based on my knowledge, the financial statements, and other financial information included in this report, fairly present in all material respects the
financial condition, results of operations and cash flows of the registrant as of, and for, the periods presented in this report;
4. The registrant’s other certifying officer and I are responsible for establishing and maintaining disclosure controls and procedures (as defined in
Exchange Act Rules 13a-15(e) and 15d-15(e)) and internal control over financial reporting (as defined in Exchange Act Rules 13a-15(f) and 15d-15(f))
for the registrant and have:
(a) Designed such disclosure controls and procedures, or caused such disclosure controls and procedures to be designed under our supervision, to
ensure that material information relating to the registrant, including its consolidated subsidiaries, is made known to us by others within those
entities, particularly during the period in which this report is being prepared;
(b) Designed such internal control over financial reporting, or caused such internal control over financial reporting to be designed under our
supervision, to provide reasonable assurance regarding the reliability of financial reporting and the preparation of financial statements for external
purposes in accordance with generally accepted accounting principles;
(c) Evaluated the effectiveness of the registrant’s disclosure controls and procedures and presented in this report our conclusions about the
effectiveness of the disclosure controls and procedures, as of the end of the period covered by this report based on such evaluation; and
(d) Disclosed in this report any change in the registrant’s internal control over financial reporting that occurred during the registrant’s most recent fiscal
quarter (the registrant’s fourth fiscal quarter in the case of an annual report) that has materially affected, or is reasonably likely to materially affect,
the registrant’s internal control over financial reporting; and
5. The registrant’s other certifying officer and I have disclosed, based on our most recent evaluation of internal control over financial reporting, to the
registrant’s auditors and the audit committee of the registrant’s board of directors (or persons performing the equivalent functions):
(a) All significant deficiencies and material weaknesses in the design or operation of internal control over financial reporting which are reasonably likely
to adversely affect the registrant’s ability to record, process, summarize and report financial information; and
(b) Any fraud, whether or not material, that involves management or other employees who have a significant role in the registrant’s internal control over
financial reporting.
Date: February 24, 2021
/s/ JOSEPH DOMINGUEZ
Chief Executive Officer
(Principal Executive Officer)
CERTIFICATION PURSUANT TO RULE 13a-14(a) AND 15d-14(a) OF THE
SECURITIES AND EXCHANGE ACT OF 1934
Exhibit 31.6
I, Jeanne M. Jones, certify that:
1.
I have reviewed this annual report on Form 10-K of Commonwealth Edison Company;
2. Based on my knowledge, this report does not contain any untrue statement of a material fact or omit to state a material fact necessary to make the
statements made, in light of the circumstances under which such statements were made, not misleading with respect to the period covered by this
report;
3. Based on my knowledge, the financial statements, and other financial information included in this report, fairly present in all material respects the
financial condition, results of operations and cash flows of the registrant as of, and for, the periods presented in this report;
4. The registrant’s other certifying officer and I are responsible for establishing and maintaining disclosure controls and procedures (as defined in
Exchange Act Rules 13a-15(e) and 15d-15(e)) and internal control over financial reporting (as defined in Exchange Act Rules 13a-15(f) and 15d-15(f))
for the registrant and have:
(a) Designed such disclosure controls and procedures, or caused such disclosure controls and procedures to be designed under our supervision, to
ensure that material information relating to the registrant, including its consolidated subsidiaries, is made known to us by others within those
entities, particularly during the period in which this report is being prepared;
(b) Designed such internal control over financial reporting, or caused such internal control over financial reporting to be designed under our
supervision, to provide reasonable assurance regarding the reliability of financial reporting and the preparation of financial statements for external
purposes in accordance with generally accepted accounting principles;
(c) Evaluated the effectiveness of the registrant’s disclosure controls and procedures and presented in this report our conclusions about the
effectiveness of the disclosure controls and procedures, as of the end of the period covered by this report based on such evaluation; and
(d) Disclosed in this report any change in the registrant’s internal control over financial reporting that occurred during the registrant’s most recent fiscal
quarter (the registrant’s fourth fiscal quarter in the case of an annual report) that has materially affected, or is reasonably likely to materially affect,
the registrant’s internal control over financial reporting; and
5. The registrant’s other certifying officer and I have disclosed, based on our most recent evaluation of internal control over financial reporting, to the
registrant’s auditors and the audit committee of the registrant’s board of directors (or persons performing the equivalent functions):
(a) All significant deficiencies and material weaknesses in the design or operation of internal control over financial reporting which are reasonably likely
to adversely affect the registrant’s ability to record, process, summarize and report financial information; and
(b) Any fraud, whether or not material, that involves management or other employees who have a significant role in the registrant’s internal control over
financial reporting.
Date: February 24, 2021
/s/ JEANNE M. JONES
Senior Vice President, Chief Financial Officer and Treasurer
(Principal Financial Officer)
CERTIFICATION PURSUANT TO RULE 13a-14(a) AND 15d-14(a) OF THE
SECURITIES AND EXCHANGE ACT OF 1934
Exhibit 31.7
I, Michael A. Innocenzo, certify that:
I have reviewed this annual report on Form 10-K of PECO Energy Company;
1.
2. Based on my knowledge, this report does not contain any untrue statement of a material fact or omit to state a material fact necessary to make the
statements made, in light of the circumstances under which such statements were made, not misleading with respect to the period covered by this
report;
3. Based on my knowledge, the financial statements, and other financial information included in this report, fairly present in all material respects the
financial condition, results of operations and cash flows of the registrant as of, and for, the periods presented in this report;
4. The registrant’s other certifying officer and I are responsible for establishing and maintaining disclosure controls and procedures (as defined in
Exchange Act Rules 13a-15(e) and 15d-15(e)) and internal control over financial reporting (as defined in Exchange Act Rules 13a-15(f) and 15d-15(f))
for the registrant and have:
(a) Designed such disclosure controls and procedures, or caused such disclosure controls and procedures to be designed under our supervision, to
ensure that material information relating to the registrant, including its consolidated subsidiaries, is made known to us by others within those
entities, particularly during the period in which this report is being prepared;
(b) Designed such internal control over financial reporting, or caused such internal control over financial reporting to be designed under our
supervision, to provide reasonable assurance regarding the reliability of financial reporting and the preparation of financial statements for external
purposes in accordance with generally accepted accounting principles;
(c) Evaluated the effectiveness of the registrant’s disclosure controls and procedures and presented in this report our conclusions about the
effectiveness of the disclosure controls and procedures, as of the end of the period covered by this report based on such evaluation; and
(d) Disclosed in this report any change in the registrant’s internal control over financial reporting that occurred during the registrant’s most recent fiscal
quarter (the registrant’s fourth fiscal quarter in the case of an annual report) that has materially affected, or is reasonably likely to materially affect,
the registrant’s internal control over financial reporting; and
5. The registrant’s other certifying officer and I have disclosed, based on our most recent evaluation of internal control over financial reporting, to the
registrant’s auditors and the audit committee of the registrant’s board of directors (or persons performing the equivalent functions):
(a) All significant deficiencies and material weaknesses in the design or operation of internal control over financial reporting which are reasonably likely
to adversely affect the registrant’s ability to record, process, summarize and report financial information; and
(b) Any fraud, whether or not material, that involves management or other employees who have a significant role in the registrant’s internal control over
financial reporting.
Date: February 24, 2021
/s/ MICHAEL A. INNOCENZO
President and Chief Executive Officer
(Principal Executive Officer)
CERTIFICATION PURSUANT TO RULE 13a-14(a) AND 15d-14(a) OF THE
SECURITIES AND EXCHANGE ACT OF 1934
Exhibit 31.8
I, Robert J. Stefani, certify that:
1.
I have reviewed this annual report on Form 10-K of PECO Energy Company;
2. Based on my knowledge, this report does not contain any untrue statement of a material fact or omit to state a material fact necessary to make the
statements made, in light of the circumstances under which such statements were made, not misleading with respect to the period covered by this
report;
3. Based on my knowledge, the financial statements, and other financial information included in this report, fairly present in all material respects the
financial condition, results of operations and cash flows of the registrant as of, and for, the periods presented in this report;
4. The registrant’s other certifying officer and I are responsible for establishing and maintaining disclosure controls and procedures (as defined in
Exchange Act Rules 13a-15(e) and 15d-15(e)) and internal control over financial reporting (as defined in Exchange Act Rules 13a-15(f) and 15d-15(f))
for the registrant and have:
(a) Designed such disclosure controls and procedures, or caused such disclosure controls and procedures to be designed under our supervision, to
ensure that material information relating to the registrant, including its consolidated subsidiaries, is made known to us by others within those
entities, particularly during the period in which this report is being prepared;
(b) Designed such internal control over financial reporting, or caused such internal control over financial reporting to be designed under our
supervision, to provide reasonable assurance regarding the reliability of financial reporting and the preparation of financial statements for external
purposes in accordance with generally accepted accounting principles;
(c) Evaluated the effectiveness of the registrant’s disclosure controls and procedures and presented in this report our conclusions about the
effectiveness of the disclosure controls and procedures, as of the end of the period covered by this report based on such evaluation; and
(d) Disclosed in this report any change in the registrant’s internal control over financial reporting that occurred during the registrant’s most recent fiscal
quarter (the registrant’s fourth fiscal quarter in the case of an annual report) that has materially affected, or is reasonably likely to materially affect,
the registrant’s internal control over financial reporting; and
5. The registrant’s other certifying officer and I have disclosed, based on our most recent evaluation of internal control over financial reporting, to the
registrant’s auditors and the audit committee of the registrant’s board of directors (or persons performing the equivalent functions):
(a) All significant deficiencies and material weaknesses in the design or operation of internal control over financial reporting which are reasonably likely
to adversely affect the registrant’s ability to record, process, summarize and report financial information; and
(b) Any fraud, whether or not material, that involves management or other employees who have a significant role in the registrant’s internal control over
financial reporting.
Date: February 24, 2021
/s/ ROBERT. J STEFANI
Senior Vice President, Chief Financial Officer and Treasurer
(Principal Financial Officer)
CERTIFICATION PURSUANT TO RULE 13a-14(a) AND 15d-14(a) OF THE
SECURITIES AND EXCHANGE ACT OF 1934
Exhibit 31.9
I, Carim V. Khouzami, certify that:
1.
I have reviewed this annual report on Form 10-K of Baltimore Gas and Electric Company;
2. Based on my knowledge, this report does not contain any untrue statement of a material fact or omit to state a material fact necessary to make the
statements made, in light of the circumstances under which such statements were made, not misleading with respect to the period covered by this
report;
3. Based on my knowledge, the financial statements, and other financial information included in this report, fairly present in all material respects the
financial condition, results of operations and cash flows of the registrant as of, and for, the periods presented in this report;
4. The registrant’s other certifying officer and I are responsible for establishing and maintaining disclosure controls and procedures (as defined in
Exchange Act Rules 13a-15(e) and 15d-15(e)) and internal control over financial reporting (as defined in Exchange Act Rules 13a-15(f) and 15d-15(f))
for the registrant and have:
(a) Designed such disclosure controls and procedures, or caused such disclosure controls and procedures to be designed under our supervision, to
ensure that material information relating to the registrant, including its consolidated subsidiaries, is made known to us by others within those
entities, particularly during the period in which this report is being prepared;
(b) Designed such internal control over financial reporting, or caused such internal control over financial reporting to be designed under our
supervision, to provide reasonable assurance regarding the reliability of financial reporting and the preparation of financial statements for external
purposes in accordance with generally accepted accounting principles;
(c) Evaluated the effectiveness of the registrant’s disclosure controls and procedures and presented in this report our conclusions about the
effectiveness of the disclosure controls and procedures, as of the end of the period covered by this report based on such evaluation; and
(d) Disclosed in this report any change in the registrant’s internal control over financial reporting that occurred during the registrant’s most recent fiscal
quarter (the registrant’s fourth fiscal quarter in the case of an annual report) that has materially affected, or is reasonably likely to materially affect,
the registrant’s internal control over financial reporting; and
5. The registrant’s other certifying officer and I have disclosed, based on our most recent evaluation of internal control over financial reporting, to the
registrant’s auditors and the audit committee of the registrant’s board of directors (or persons performing the equivalent functions):
(a) All significant deficiencies and material weaknesses in the design or operation of internal control over financial reporting which are reasonably likely
to adversely affect the registrant’s ability to record, process, summarize and report financial information; and
(b) Any fraud, whether or not material, that involves management or other employees who have a significant role in the registrant’s internal control over
financial reporting.
Date: February 24, 2021
/s/ CARIM V. KHOUZAMI
Chief Executive Officer
(Principal Executive Officer)
CERTIFICATION PURSUANT TO RULE 13a-14(a) AND 15d-14(a) OF THE
SECURITIES AND EXCHANGE ACT OF 1934
Exhibit 31.10
I, David M. Vahos, certify that:
1.
I have reviewed this annual report on Form 10-K of Baltimore Gas and Electric Company;
2. Based on my knowledge, this report does not contain any untrue statement of a material fact or omit to state a material fact necessary to make the
statements made, in light of the circumstances under which such statements were made, not misleading with respect to the period covered by this
report;
3. Based on my knowledge, the financial statements, and other financial information included in this report, fairly present in all material respects the
financial condition, results of operations and cash flows of the registrant as of, and for, the periods presented in this report;
4. The registrant’s other certifying officer and I are responsible for establishing and maintaining disclosure controls and procedures (as defined in
Exchange Act Rules 13a-15(e) and 15d-15(e)) and internal control over financial reporting (as defined in Exchange Act Rules 13a-15(f) and 15d-15(f))
for the registrant and have:
(a) Designed such disclosure controls and procedures, or caused such disclosure controls and procedures to be designed under our supervision, to
ensure that material information relating to the registrant, including its consolidated subsidiaries, is made known to us by others within those
entities, particularly during the period in which this report is being prepared;
(b) Designed such internal control over financial reporting, or caused such internal control over financial reporting to be designed under our
supervision, to provide reasonable assurance regarding the reliability of financial reporting and the preparation of financial statements for external
purposes in accordance with generally accepted accounting principles;
(c) Evaluated the effectiveness of the registrant’s disclosure controls and procedures and presented in this report our conclusions about the
effectiveness of the disclosure controls and procedures, as of the end of the period covered by this report based on such evaluation; and
(d) Disclosed in this report any change in the registrant’s internal control over financial reporting that occurred during the registrant’s most recent fiscal
quarter (the registrant’s fourth fiscal quarter in the case of an annual report) that has materially affected, or is reasonably likely to materially affect,
the registrant’s internal control over financial reporting; and
5. The registrant’s other certifying officer and I have disclosed, based on our most recent evaluation of internal control over financial reporting, to the
registrant’s auditors and the audit committee of the registrant’s board of directors (or persons performing the equivalent functions):
(a) All significant deficiencies and material weaknesses in the design or operation of internal control over financial reporting which are reasonably likely
to adversely affect the registrant’s ability to record, process, summarize and report financial information; and
(b) Any fraud, whether or not material, that involves management or other employees who have a significant role in the registrant’s internal control over
financial reporting.
Date: February 24, 2021
/s/ DAVID M. VAHOS
Senior Vice President, Chief Financial Officer and Treasurer
(Principal Financial Officer)
CERTIFICATION PURSUANT TO RULE 13a-14(a) AND 15d-14(a) OF THE SECURITIES
AND EXCHANGE ACT OF 1934
Exhibit 31.11
I have reviewed this annual report on Form 10-K of Pepco Holdings LLC;
I, David M. Velazquez, certify that:
1.
2. Based on my knowledge, this report does not contain any untrue statement of a material fact or omit to state a material fact necessary to make the
statements made, in light of the circumstances under which such statements were made, not misleading with respect to the period covered by this
report;
3. Based on my knowledge, the financial statements, and other financial information included in this report, fairly present in all material respects the
financial condition, results of operations and cash flows of the registrant as of, and for, the periods presented in this report;
4. The registrant’s other certifying officer and I are responsible for establishing and maintaining disclosure controls and procedures (as defined in
Exchange Act Rules 13a-15(e) and 15d-15(e)) and internal control over financial reporting (as defined in Exchange Act Rules 13a-15(f) and 15d-15(f))
for the registrant and have:
(a) Designed such disclosure controls and procedures, or caused such disclosure controls and procedures to be designed under our supervision, to
ensure that material information relating to the registrant, including its consolidated subsidiaries, is made known to us by others within those
entities, particularly during the period in which this report is being prepared;
(b) Designed such internal control over financial reporting, or caused such internal control over financial reporting to be designed under our
supervision, to provide reasonable assurance regarding the reliability of financial reporting and the preparation of financial statements for external
purposes in accordance with generally accepted accounting principles;
(c) Evaluated the effectiveness of the registrant’s disclosure controls and procedures and presented in this report our conclusions about the
effectiveness of the disclosure controls and procedures, as of the end of the period covered by this report based on such evaluation; and
(d) Disclosed in this report any change in the registrant’s internal control over financial reporting that occurred during the registrant’s most recent fiscal
quarter (the registrant’s fourth fiscal quarter in the case of an annual report) that has materially affected, or is reasonably likely to materially affect,
the registrant’s internal control over financial reporting; and
5. The registrant’s other certifying officer and I have disclosed, based on our most recent evaluation of internal control over financial reporting, to the
registrant’s auditors and the audit committee of the registrant’s board of directors (or persons performing the equivalent functions):
(a) All significant deficiencies and material weaknesses in the design or operation of internal control over financial reporting which are reasonably likely
to adversely affect the registrant’s ability to record, process, summarize and report financial information; and
(b) Any fraud, whether or not material, that involves management or other employees who have a significant role in the registrant’s internal control over
financial reporting.
Date: February 24, 2021
/s/ DAVID M. VELAZQUEZ
President and Chief Executive Officer
(Principal Executive Officer)
CERTIFICATION PURSUANT TO RULE 13a-14(a) AND 15d-14(a) OF THE SECURITIES
AND EXCHANGE ACT OF 1934
Exhibit 31.12
I have reviewed this annual report on Form 10-K of Pepco Holdings LLC;
I, Phillip S. Barnett, certify that:
1.
2. Based on my knowledge, this report does not contain any untrue statement of a material fact or omit to state a material fact necessary to make the
statements made, in light of the circumstances under which such statements were made, not misleading with respect to the period covered by this
report;
3. Based on my knowledge, the financial statements, and other financial information included in this report, fairly present in all material respects the
financial condition, results of operations and cash flows of the registrant as of, and for, the periods presented in this report;
4. The registrant’s other certifying officer and I are responsible for establishing and maintaining disclosure controls and procedures (as defined in
Exchange Act Rules 13a-15(e) and 15d-15(e)) and internal control over financial reporting (as defined in Exchange Act Rules 13a-15(f) and 15d-15(f))
for the registrant and have:
(a) Designed such disclosure controls and procedures, or caused such disclosure controls and procedures to be designed under our supervision, to
ensure that material information relating to the registrant, including its consolidated subsidiaries, is made known to us by others within those
entities, particularly during the period in which this report is being prepared;
(b) Designed such internal control over financial reporting, or caused such internal control over financial reporting to be designed under our
supervision, to provide reasonable assurance regarding the reliability of financial reporting and the preparation of financial statements for external
purposes in accordance with generally accepted accounting principles;
(c) Evaluated the effectiveness of the registrant’s disclosure controls and procedures and presented in this report our conclusions about the
effectiveness of the disclosure controls and procedures, as of the end of the period covered by this report based on such evaluation; and
(d) Disclosed in this report any change in the registrant’s internal control over financial reporting that occurred during the registrant’s most recent fiscal
quarter (the registrant’s fourth fiscal quarter in the case of an annual report) that has materially affected, or is reasonably likely to materially affect,
the registrant’s internal control over financial reporting; and
5. The registrant’s other certifying officer and I have disclosed, based on our most recent evaluation of internal control over financial reporting, to the
registrant’s auditors and the audit committee of the registrant’s board of directors (or persons performing the equivalent functions):
(a) All significant deficiencies and material weaknesses in the design or operation of internal control over financial reporting which are reasonably likely
to adversely affect the registrant’s ability to record, process, summarize and report financial information; and
(b) Any fraud, whether or not material, that involves management or other employees who have a significant role in the registrant’s internal control over
financial reporting.
Date: February 24, 2021
/s/ PHILLIP S. BARNETT
Senior Vice President, Chief Financial Officer and Treasurer
(Principal Financial Officer)
CERTIFICATION PURSUANT TO RULE 13a-14(a) AND 15d-14(a) OF THE SECURITIES
AND EXCHANGE ACT OF 1934
Exhibit 31.13
I have reviewed this annual report on Form 10-K of Potomac Electric Power Company;
I, David M. Velazquez, certify that:
1.
2. Based on my knowledge, this report does not contain any untrue statement of a material fact or omit to state a material fact necessary to make the
statements made, in light of the circumstances under which such statements were made, not misleading with respect to the period covered by this
report;
3. Based on my knowledge, the financial statements, and other financial information included in this report, fairly present in all material respects the
financial condition, results of operations and cash flows of the registrant as of, and for, the periods presented in this report;
4. The registrant’s other certifying officer and I are responsible for establishing and maintaining disclosure controls and procedures (as defined in
Exchange Act Rules 13a-15(e) and 15d-15(e)) and internal control over financial reporting (as defined in Exchange Act Rules 13a-15(f) and 15d-15(f))
for the registrant and have:
(a) Designed such disclosure controls and procedures, or caused such disclosure controls and procedures to be designed under our supervision, to
ensure that material information relating to the registrant, including its consolidated subsidiaries, is made known to us by others within those
entities, particularly during the period in which this report is being prepared;
(b) Designed such internal control over financial reporting, or caused such internal control over financial reporting to be designed under our
supervision, to provide reasonable assurance regarding the reliability of financial reporting and the preparation of financial statements for external
purposes in accordance with generally accepted accounting principles;
(c) Evaluated the effectiveness of the registrant’s disclosure controls and procedures and presented in this report our conclusions about the
effectiveness of the disclosure controls and procedures, as of the end of the period covered by this report based on such evaluation; and
(d) Disclosed in this report any change in the registrant’s internal control over financial reporting that occurred during the registrant’s most recent fiscal
quarter (the registrant’s fourth fiscal quarter in the case of an annual report) that has materially affected, or is reasonably likely to materially affect,
the registrant’s internal control over financial reporting; and
5. The registrant’s other certifying officer and I have disclosed, based on our most recent evaluation of internal control over financial reporting, to the
registrant’s auditors and the audit committee of the registrant’s board of directors (or persons performing the equivalent functions):
(a) All significant deficiencies and material weaknesses in the design or operation of internal control over financial reporting which are reasonably likely
to adversely affect the registrant’s ability to record, process, summarize and report financial information; and
(b) Any fraud, whether or not material, that involves management or other employees who have a significant role in the registrant’s internal control over
financial reporting.
Date: February 24, 2021
/s/ DAVID M. VELAZQUEZ
President and Chief Executive Officer
(Principal Executive Officer)
CERTIFICATION PURSUANT TO RULE 13a-14(a) AND 15d-14(a) OF THE SECURITIES
AND EXCHANGE ACT OF 1934
Exhibit 31.14
I have reviewed this annual report on Form 10-K of Potomac Electric Power Company;
I, Phillip S. Barnett, certify that:
1.
2. Based on my knowledge, this report does not contain any untrue statement of a material fact or omit to state a material fact necessary to make the
statements made, in light of the circumstances under which such statements were made, not misleading with respect to the period covered by this
report;
3. Based on my knowledge, the financial statements, and other financial information included in this report, fairly present in all material respects the
financial condition, results of operations and cash flows of the registrant as of, and for, the periods presented in this report;
4. The registrant’s other certifying officer and I are responsible for establishing and maintaining disclosure controls and procedures (as defined in
Exchange Act Rules 13a-15(e) and 15d-15(e)) and internal control over financial reporting (as defined in Exchange Act Rules 13a-15(f) and 15d-15(f))
for the registrant and have:
(a) Designed such disclosure controls and procedures, or caused such disclosure controls and procedures to be designed under our supervision, to
ensure that material information relating to the registrant, including its consolidated subsidiaries, is made known to us by others within those
entities, particularly during the period in which this report is being prepared;
(b) Designed such internal control over financial reporting, or caused such internal control over financial reporting to be designed under our
supervision, to provide reasonable assurance regarding the reliability of financial reporting and the preparation of financial statements for external
purposes in accordance with generally accepted accounting principles;
(c) Evaluated the effectiveness of the registrant’s disclosure controls and procedures and presented in this report our conclusions about the
effectiveness of the disclosure controls and procedures, as of the end of the period covered by this report based on such evaluation; and
(d) Disclosed in this report any change in the registrant’s internal control over financial reporting that occurred during the registrant’s most recent fiscal
quarter (the registrant’s fourth fiscal quarter in the case of an annual report) that has materially affected, or is reasonably likely to materially affect,
the registrant’s internal control over financial reporting; and
5. The registrant’s other certifying officer and I have disclosed, based on our most recent evaluation of internal control over financial reporting, to the
registrant’s auditors and the audit committee of the registrant’s board of directors (or persons performing the equivalent functions):
(a) All significant deficiencies and material weaknesses in the design or operation of internal control over financial reporting which are reasonably likely
to adversely affect the registrant’s ability to record, process, summarize and report financial information; and
(b) Any fraud, whether or not material, that involves management or other employees who have a significant role in the registrant’s internal control over
financial reporting.
Date: February 24, 2021
/s/ PHILLIP S. BARNETT
Senior Vice President, Chief Financial Officer and Treasurer
(Principal Financial Officer)
CERTIFICATION PURSUANT TO RULE 13a-14(a) AND 15d-14(a) OF THE SECURITIES
AND EXCHANGE ACT OF 1934
Exhibit 31.15
I have reviewed this annual report on Form 10-K of Delmarva Power & Light Company;
I, David M. Velazquez, certify that:
1.
2. Based on my knowledge, this report does not contain any untrue statement of a material fact or omit to state a material fact necessary to make the
statements made, in light of the circumstances under which such statements were made, not misleading with respect to the period covered by this
report;
3. Based on my knowledge, the financial statements, and other financial information included in this report, fairly present in all material respects the
financial condition, results of operations and cash flows of the registrant as of, and for, the periods presented in this report;
4. The registrant’s other certifying officer and I are responsible for establishing and maintaining disclosure controls and procedures (as defined in
Exchange Act Rules 13a-15(e) and 15d-15(e)) and internal control over financial reporting (as defined in Exchange Act Rules 13a-15(f) and 15d-15(f))
for the registrant and have:
(a) Designed such disclosure controls and procedures, or caused such disclosure controls and procedures to be designed under our supervision, to
ensure that material information relating to the registrant, including its consolidated subsidiaries, is made known to us by others within those
entities, particularly during the period in which this report is being prepared;
(b) Designed such internal control over financial reporting, or caused such internal control over financial reporting to be designed under our
supervision, to provide reasonable assurance regarding the reliability of financial reporting and the preparation of financial statements for external
purposes in accordance with generally accepted accounting principles;
(c) Evaluated the effectiveness of the registrant’s disclosure controls and procedures and presented in this report our conclusions about the
effectiveness of the disclosure controls and procedures, as of the end of the period covered by this report based on such evaluation; and
(d) Disclosed in this report any change in the registrant’s internal control over financial reporting that occurred during the registrant’s most recent fiscal
quarter (the registrant’s fourth fiscal quarter in the case of an annual report) that has materially affected, or is reasonably likely to materially affect,
the registrant’s internal control over financial reporting; and
5. The registrant’s other certifying officer and I have disclosed, based on our most recent evaluation of internal control over financial reporting, to the
registrant’s auditors and the audit committee of the registrant’s board of directors (or persons performing the equivalent functions):
(a) All significant deficiencies and material weaknesses in the design or operation of internal control over financial reporting which are reasonably likely
to adversely affect the registrant’s ability to record, process, summarize and report financial information; and
(b) Any fraud, whether or not material, that involves management or other employees who have a significant role in the registrant’s internal control over
financial reporting.
Date: February 24, 2021
/s/ DAVID M. VELAZQUEZ
President and Chief Executive Officer
(Principal Executive Officer)
CERTIFICATION PURSUANT TO RULE 13a-14(a) AND 15d-14(a) OF THE SECURITIES
AND EXCHANGE ACT OF 1934
Exhibit 31.16
I have reviewed this annual report on Form 10-K of Delmarva Power & Light Company;
I, Phillip S. Barnett, certify that:
1.
2. Based on my knowledge, this report does not contain any untrue statement of a material fact or omit to state a material fact necessary to make the
statements made, in light of the circumstances under which such statements were made, not misleading with respect to the period covered by this
report;
3. Based on my knowledge, the financial statements, and other financial information included in this report, fairly present in all material respects the
financial condition, results of operations and cash flows of the registrant as of, and for, the periods presented in this report;
4. The registrant’s other certifying officer and I are responsible for establishing and maintaining disclosure controls and procedures (as defined in
Exchange Act Rules 13a-15(e) and 15d-15(e)) and internal control over financial reporting (as defined in Exchange Act Rules 13a-15(f) and 15d-15(f))
for the registrant and have:
(a) Designed such disclosure controls and procedures, or caused such disclosure controls and procedures to be designed under our supervision, to
ensure that material information relating to the registrant, including its consolidated subsidiaries, is made known to us by others within those
entities, particularly during the period in which this report is being prepared;
(b) Designed such internal control over financial reporting, or caused such internal control over financial reporting to be designed under our
supervision, to provide reasonable assurance regarding the reliability of financial reporting and the preparation of financial statements for external
purposes in accordance with generally accepted accounting principles;
(c) Evaluated the effectiveness of the registrant’s disclosure controls and procedures and presented in this report our conclusions about the
effectiveness of the disclosure controls and procedures, as of the end of the period covered by this report based on such evaluation; and
(d) Disclosed in this report any change in the registrant’s internal control over financial reporting that occurred during the registrant’s most recent fiscal
quarter (the registrant’s fourth fiscal quarter in the case of an annual report) that has materially affected, or is reasonably likely to materially affect,
the registrant’s internal control over financial reporting; and
5. The registrant’s other certifying officer and I have disclosed, based on our most recent evaluation of internal control over financial reporting, to the
registrant’s auditors and the audit committee of the registrant’s board of directors (or persons performing the equivalent functions):
(a) All significant deficiencies and material weaknesses in the design or operation of internal control over financial reporting which are reasonably likely
to adversely affect the registrant’s ability to record, process, summarize and report financial information; and
(b) Any fraud, whether or not material, that involves management or other employees who have a significant role in the registrant’s internal control over
financial reporting.
Date: February 24, 2021
/s/ PHILLIP S. BARNETT
Senior Vice President, Chief Financial Officer and Treasurer
(Principal Financial Officer)
CERTIFICATION PURSUANT TO RULE 13a-14(a) AND 15d-14(a) OF THE SECURITIES
AND EXCHANGE ACT OF 1934
Exhibit 31.17
I have reviewed this annual report on Form 10-K of Atlantic City Electric Company;
I, David M. Velazquez, certify that:
1.
2. Based on my knowledge, this report does not contain any untrue statement of a material fact or omit to state a material fact necessary to make the
statements made, in light of the circumstances under which such statements were made, not misleading with respect to the period covered by this
report;
3. Based on my knowledge, the financial statements, and other financial information included in this report, fairly present in all material respects the
financial condition, results of operations and cash flows of the registrant as of, and for, the periods presented in this report;
4. The registrant’s other certifying officer and I are responsible for establishing and maintaining disclosure controls and procedures (as defined in
Exchange Act Rules 13a-15(e) and 15d-15(e)) and internal control over financial reporting (as defined in Exchange Act Rules 13a-15(f) and 15d-15(f))
for the registrant and have:
(a) Designed such disclosure controls and procedures, or caused such disclosure controls and procedures to be designed under our supervision, to
ensure that material information relating to the registrant, including its consolidated subsidiaries, is made known to us by others within those
entities, particularly during the period in which this report is being prepared;
(b) Designed such internal control over financial reporting, or caused such internal control over financial reporting to be designed under our
supervision, to provide reasonable assurance regarding the reliability of financial reporting and the preparation of financial statements for external
purposes in accordance with generally accepted accounting principles;
(c) Evaluated the effectiveness of the registrant’s disclosure controls and procedures and presented in this report our conclusions about the
effectiveness of the disclosure controls and procedures, as of the end of the period covered by this report based on such evaluation; and
(d) Disclosed in this report any change in the registrant’s internal control over financial reporting that occurred during the registrant’s most recent fiscal
quarter (the registrant’s fourth fiscal quarter in the case of an annual report) that has materially affected, or is reasonably likely to materially affect,
the registrant’s internal control over financial reporting; and
5. The registrant’s other certifying officer and I have disclosed, based on our most recent evaluation of internal control over financial reporting, to the
registrant’s auditors and the audit committee of the registrant’s board of directors (or persons performing the equivalent functions):
(a) All significant deficiencies and material weaknesses in the design or operation of internal control over financial reporting which are reasonably likely
to adversely affect the registrant’s ability to record, process, summarize and report financial information; and
(b) Any fraud, whether or not material, that involves management or other employees who have a significant role in the registrant’s internal control over
financial reporting.
Date: February 24, 2021
/s/ DAVID M. VELAZQUEZ
President and Chief Executive Officer
(Principal Executive Officer)
CERTIFICATION PURSUANT TO RULE 13a-14(a) AND 15d-14(a) OF THE SECURITIES
AND EXCHANGE ACT OF 1934
Exhibit 31.18
I have reviewed this annual report on Form 10-K of Atlantic City Electric Company;
I, Phillip S. Barnett, certify that:
1.
2. Based on my knowledge, this report does not contain any untrue statement of a material fact or omit to state a material fact necessary to make the
statements made, in light of the circumstances under which such statements were made, not misleading with respect to the period covered by this
report;
3. Based on my knowledge, the financial statements, and other financial information included in this report, fairly present in all material respects the
financial condition, results of operations and cash flows of the registrant as of, and for, the periods presented in this report;
4. The registrant’s other certifying officer and I are responsible for establishing and maintaining disclosure controls and procedures (as defined in
Exchange Act Rules 13a-15(e) and 15d-15(e)) and internal control over financial reporting (as defined in Exchange Act Rules 13a-15(f) and 15d-15(f))
for the registrant and have:
(a) Designed such disclosure controls and procedures, or caused such disclosure controls and procedures to be designed under our supervision, to
ensure that material information relating to the registrant, including its consolidated subsidiaries, is made known to us by others within those
entities, particularly during the period in which this report is being prepared;
(b) Designed such internal control over financial reporting, or caused such internal control over financial reporting to be designed under our
supervision, to provide reasonable assurance regarding the reliability of financial reporting and the preparation of financial statements for external
purposes in accordance with generally accepted accounting principles;
(c) Evaluated the effectiveness of the registrant’s disclosure controls and procedures and presented in this report our conclusions about the
effectiveness of the disclosure controls and procedures, as of the end of the period covered by this report based on such evaluation; and
(d) Disclosed in this report any change in the registrant’s internal control over financial reporting that occurred during the registrant’s most recent fiscal
quarter (the registrant’s fourth fiscal quarter in the case of an annual report) that has materially affected, or is reasonably likely to materially affect,
the registrant’s internal control over financial reporting; and
5. The registrant’s other certifying officer and I have disclosed, based on our most recent evaluation of internal control over financial reporting, to the
registrant’s auditors and the audit committee of the registrant’s board of directors (or persons performing the equivalent functions):
(a) All significant deficiencies and material weaknesses in the design or operation of internal control over financial reporting which are reasonably likely
to adversely affect the registrant’s ability to record, process, summarize and report financial information; and
(b) Any fraud, whether or not material, that involves management or other employees who have a significant role in the registrant’s internal control over
financial reporting.
Date: February 24, 2021
/s/ PHILLIP S. BARNETT
Senior Vice President, Chief Financial Officer and Treasurer
(Principal Financial Officer)
Certificate Pursuant to Section 1350 of Chapter 63 of Title 18 United States Code
The undersigned officer hereby certifies, as to the Report on Form 10-K of Exelon Corporation for the year ended December 31, 2020, that (i) the
report fully complies with the requirements of section 13(a) or 15(d) of the Securities Exchange Act of 1934, and (ii) the information contained in the report
fairly presents, in all material respects, the financial condition and results of operations of Exelon Corporation.
Exhibit 32.1
Date: February 24, 2021
/s/ CHRISTOPHER M. CRANE
Christopher M. Crane
President and Chief Executive Officer
Certificate Pursuant to Section 1350 of Chapter 63 of Title 18 United States Code
The undersigned officer hereby certifies, as to the Report on Form 10-K of Exelon Corporation for the year ended December 31, 2020, that (i) the
report fully complies with the requirements of section 13(a) or 15(d) of the Securities Exchange Act of 1934, and (ii) the information contained in the report
fairly presents, in all material respects, the financial condition and results of operations of Exelon Corporation.
Exhibit 32.2
Date: February 24, 2021
/s/ JOSEPH NIGRO
Joseph Nigro
Senior Executive Vice President and Chief Financial Officer
Certificate Pursuant to Section 1350 of Chapter 63 of Title 18 United States Code
The undersigned officer hereby certifies, as to the Report on Form 10-K of Exelon Generation Company, LLC for the year ended December 31, 2020,
that (i) the report fully complies with the requirements of section 13(a) or 15(d) of the Securities Exchange Act of 1934, and (ii) the information contained in
the report fairly presents, in all material respects, the financial condition and results of operations of Exelon Generation Company, LLC.
Exhibit 32.3
Date: February 24, 2021
/s/ CHRISTOPHER M. CRANE
Christopher M. Crane
Principal Executive Officer
Certificate Pursuant to Section 1350 of Chapter 63 of Title 18 United States Code
The undersigned officer hereby certifies, as to the Report on Form 10-K of Exelon Generation Company, LLC for the year ended December 31, 2020,
that (i) the report fully complies with the requirements of section 13(a) or 15(d) of the Securities Exchange Act of 1934, and (ii) the information contained in
the report fairly presents, in all material respects, the financial condition and results of operations of Exelon Generation Company, LLC.
Exhibit 32.4
Date: February 24, 2021
/s/ BRYAN P. WRIGHT
Bryan P. Wright
Senior Vice President and Chief Financial Officer
Certificate Pursuant to Section 1350 of Chapter 63 of Title 18 United States Code
The undersigned officer hereby certifies, as to the Report on Form 10-K of Commonwealth Edison Company for the year ended December 31, 2020,
that (i) the report fully complies with the requirements of section 13(a) or 15(d) of the Securities Exchange Act of 1934, and (ii) the information contained in
the report fairly presents, in all material respects, the financial condition and results of operations of Commonwealth Edison Company.
Exhibit 32.5
Date: February 24, 2021
/s/ JOSEPH DOMINGUEZ
Joseph Dominguez
Chief Executive Officer
Certificate Pursuant to Section 1350 of Chapter 63 of Title 18 United States Code
The undersigned officer hereby certifies, as to the Report on Form 10-K of Commonwealth Edison Company for the year ended December 31, 2020,
that (i) the report fully complies with the requirements of section 13(a) or 15(d) of the Securities Exchange Act of 1934, and (ii) the information contained in
the report fairly presents, in all material respects, the financial condition and results of operations of Commonwealth Edison Company.
Exhibit 32.6
Date: February 24, 2021
/s/ JEANNE M. JONES
Jeanne M. Jones
Senior Vice President, Chief Financial Officer and Treasurer
Certificate Pursuant to Section 1350 of Chapter 63 of Title 18 United States Code
The undersigned officer hereby certifies, as to the Report on Form 10-K of PECO Energy Company for the year ended December 31, 2020, that (i) the
report fully complies with the requirements of section 13(a) or 15(d) of the Securities Exchange Act of 1934, and (ii) the information contained in the report
fairly presents, in all material respects, the financial condition and results of operations of PECO Energy Company.
Exhibit 32.7
Date: February 24, 2021
/s/ MICHAEL A. INNOCENZO
Michael A. Innocenzo
President and Chief Executive Officer
Certificate Pursuant to Section 1350 of Chapter 63 of Title 18 United States Code
The undersigned officer hereby certifies, as to the Report on Form 10-K of PECO Energy Company for the year ended December 31, 2020, that (i) the
report fully complies with the requirements of section 13(a) or 15(d) of the Securities Exchange Act of 1934, and (ii) the information contained in the report
fairly presents, in all material respects, the financial condition and results of operations of PECO Energy Company.
Exhibit 32.8
Date: February 24, 2021
/s/ ROBERT J. STEFANI
Robert J. Stefani
Senior Vice President, Chief Financial Officer and Treasurer
Certificate Pursuant to Section 1350 of Chapter 63 of Title 18 United States Code
The undersigned officer hereby certifies, as to the Report on Form 10-K of Baltimore Gas and Electric Company for the year ended December 31,
2020, that (i) the report fully complies with the requirements of section 13(a) or 15(d) of the Securities Exchange Act of 1934, and (ii) the information
contained in the report fairly presents, in all material respects, the financial condition and results of operations of Baltimore Gas and Electric Company.
Exhibit 32.9
/s/ CARIM V. KHOUZAMI
Carim V. Khouzami
Chief Executive Officer
Date: February 24, 2021
Certificate Pursuant to Section 1350 of Chapter 63 of Title 18 United States Code
The undersigned officer hereby certifies, as to the Report on Form 10-K of Baltimore Gas and Electric Company for the year ended December 31,
2020, that (i) the report fully complies with the requirements of section 13(a) or 15(d) of the Securities Exchange Act of 1934, and (ii) the information
contained in the report fairly presents, in all material respects, the financial condition and results of operations of Baltimore Gas and Electric Company.
Exhibit 32-10
Date: February 24, 2021
/s/ DAVID M. VAHOS
David M. Vahos
Senior Vice President, Chief Financial Officer and Treasurer
Certificate Pursuant to Section 1350 of Chapter 63 of Title 18 United States Code
The undersigned officer hereby certifies, as to the Report on Form 10-K of Pepco Holdings LLC for the year ended December 31, 2020, that (i) the
report fully complies with the requirements of section 13(a) or 15(d) of the Securities Exchange Act of 1934, and (ii) the information contained in the report
fairly presents, in all material respects, the financial condition and results of operations of Pepco Holdings LLC.
Exhibit 32.11
Date: February 24, 2021
/s/ DAVID M. VELAZQUEZ
David M. Velazquez
President and Chief Executive Officer
Certificate Pursuant to Section 1350 of Chapter 63 of Title 18 United States Code
The undersigned officer hereby certifies, as to the Report on Form 10-K of Pepco Holdings LLC for the year ended December 31, 2020, that (i) the
report fully complies with the requirements of section 13(a) or 15(d) of the Securities Exchange Act of 1934, and (ii) the information contained in the report
fairly presents, in all material respects, the financial condition and results of operations of Pepco Holdings LLC.
Exhibit 32-12
Date: February 24, 2021
/s/ PHILLIP S. BARNETT
Phillip S. Barnett
Senior Vice President, Chief Financial Officer and Treasurer
Certificate Pursuant to Section 1350 of Chapter 63 of Title 18 United States Code
The undersigned officer hereby certifies, as to the Report on Form 10-K of Potomac Electric Power Company for the year ended December 31, 2020,
that (i) the report fully complies with the requirements of section 13(a) or 15(d) of the Securities Exchange Act of 1934, and (ii) the information contained in
the report fairly presents, in all material respects, the financial condition and results of operations of Potomac Electric Power Company.
Exhibit 32.13
Date: February 24, 2021
/s/ DAVID M. VELAZQUEZ
David M. Velazquez
President and Chief Executive Officer
Certificate Pursuant to Section 1350 of Chapter 63 of Title 18 United States Code
The undersigned officer hereby certifies, as to the Report on Form 10-K of Potomac Electric Power Company for the year ended December 31, 2020,
that (i) the report fully complies with the requirements of section 13(a) or 15(d) of the Securities Exchange Act of 1934, and (ii) the information contained in
the report fairly presents, in all material respects, the financial condition and results of operations of Potomac Electric Power Company.
Exhibit 32.14
Date: February 24, 2021
/s/ PHILLIP S. BARNETT
Phillip S. Barnett
Senior Vice President, Chief Financial Officer and Treasurer
Certificate Pursuant to Section 1350 of Chapter 63 of Title 18 United States Code
The undersigned officer hereby certifies, as to the Report on Form 10-K of Delmarva Power & Light Company for the year ended December 31, 2020,
that (i) the report fully complies with the requirements of section 13(a) or 15(d) of the Securities Exchange Act of 1934, and (ii) the information contained in
the report fairly presents, in all material respects, the financial condition and results of operations of Delmarva Power & Light Company.
Exhibit 32.15
Date: February 24, 2021
/s/ DAVID M. VELAZQUEZ
David M. Velazquez
President and Chief Executive Officer
Certificate Pursuant to Section 1350 of Chapter 63 of Title 18 United States Code
The undersigned officer hereby certifies, as to the Report on Form 10-K of Delmarva Power & Light Company for the year ended December 31, 2020,
that (i) the report fully complies with the requirements of section 13(a) or 15(d) of the Securities Exchange Act of 1934, and (ii) the information contained in
the report fairly presents, in all material respects, the financial condition and results of operations of Delmarva Power & Light Company.
Exhibit 32.16
Date: February 24, 2021
/s/ PHILLIP S. BARNETT
Phillip S. Barnett
Senior Vice President, Chief Financial Officer and Treasurer
Certificate Pursuant to Section 1350 of Chapter 63 of Title 18 United States Code
The undersigned officer hereby certifies, as to the Report on Form 10-K of Atlantic City Electric Company for the year ended December 31, 2020, that
(i) the report fully complies with the requirements of section 13(a) or 15(d) of the Securities Exchange Act of 1934, and (ii) the information contained in the
report fairly presents, in all material respects, the financial condition and results of operations of Atlantic City Electric Company.
Exhibit 32.17
Date: February 24, 2021
/s/ DAVID M. VELAZQUEZ
David M. Velazquez
President and Chief Executive Officer
Certificate Pursuant to Section 1350 of Chapter 63 of Title 18 United States Code
The undersigned officer hereby certifies, as to the Report on Form 10-K of Atlantic City Electric Company for the year ended December 31, 2020, that
(i) the report fully complies with the requirements of section 13(a) or 15(d) of the Securities Exchange Act of 1934, and (ii) the information contained in the
report fairly presents, in all material respects, the financial condition and results of operations of Atlantic City Electric Company.
Exhibit 32.18
Date: February 24, 2021
/s/ PHILLIP S. BARNETT
Phillip S. Barnett
Senior Vice President, Chief Financial Officer and Treasurer