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, 2019
or
☐ TRANSITION REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934
Commission
File Number
Name of Registrant; State or Other Jurisdiction of Incorporation; Address of Principal Executive Offices; and Telephone
Number
IRS Employer
Identification Number
001-16169
EXELON CORPORATION
(a Pennsylvania corporation)
10 South Dearborn Street
P.O. Box 805379
Chicago, Illinois 60680-5379
(800) 483-3220
333-85496
EXELON GENERATION COMPANY, LLC
(a Pennsylvania limited liability company)
300 Exelon Way
Kennett Square, Pennsylvania 19348-2473
(610) 765-5959
001-01839
COMMONWEALTH EDISON COMPANY
000-16844
(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
23-2990190
23-3064219
36-0938600
23-0970240
001-01910
BALTIMORE GAS AND ELECTRIC COMPANY
52-0280210
(a Maryland corporation)
2 Center Plaza
110 West Fayette Street
Baltimore, Maryland 21201-3708
(410) 234-5000
001-31403
PEPCO HOLDINGS LLC
(a Delaware limited liability company)
701 Ninth Street, N.W.
Washington, District of Columbia 20068
(202) 872-2000
001-01072
POTOMAC ELECTRIC POWER COMPANY
(a District of Columbia and Virginia corporation)
701 Ninth Street, N.W.
Washington, District of Columbia 20068
(202) 872-2000
001-01405
DELMARVA POWER & LIGHT COMPANY
(a Delaware and Virginia corporation)
500 North Wakefield Drive
Newark, Delaware 19702
(202) 872-2000
001-03559
ATLANTIC CITY ELECTRIC COMPANY
(a New Jersey corporation)
500 North Wakefield Drive
Newark, Delaware 19702
(202) 872-2000
52-2297449
53-0127880
51-0084283
21-0398280
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
Title of Each Class
COMMONWEALTH EDISON COMPANY:
Common Stock Purchase Warrants (1971 Warrants and Series B Warrants)
Securities registered pursuant to Section 12(g) of the Act:
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 ý No ¨
Indicate by check mark whether the registrant has submitted electronically every Interactive Data File required to be submitted pursuant to Rule 405 of Regulation S-T
(§232.405 of this chapter) during the preceding 12 months (or for such shorter period that the registrant was required to submit and post such files). Yes ý No ¨
Indicate by check mark whether the registrant is a large accelerated filer, an accelerated filer, a non-accelerated filer, a smaller reporting company, or an emerging growth
company. See the definitions of “large accelerated filer,” “accelerated filer,” “smaller reporting company,” and "emerging growth company" in Rule 12b-2 of the Exchange Act.
Exelon 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 ☐ Emerging Growth Company ☐
Smaller Reporting
Company ☐ Emerging Growth Company ☐
Smaller Reporting
Company ☐ Emerging Growth Company ☐
Smaller Reporting
Company ☐ Emerging Growth Company ☐
Smaller Reporting
Company ☐ Emerging Growth Company ☐
Smaller Reporting
Company ☐ Emerging Growth Company ☐
Smaller Reporting
Company ☐ Emerging Growth Company ☐
Smaller Reporting
Company ☐ Emerging Growth Company ☐
Smaller Reporting
Company ☐ Emerging Growth Company ☐
If an emerging growth company, indicate by check mark if the registrant has elected not to use the extended transition period for complying with any new or revised
financial accounting standards provided pursuant to Section 13(a) of the Exchange Act. o
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, 2019 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, 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 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
$46,542,193,363
Not applicable
No established market
None
None
Not applicable
None
None
None
974,319,565
Not applicable
127,021,349
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 2019 Annual Meeting of Shareholders and the Commonwealth Edison Company 2019 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.
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
ITEM 1A.
ITEM 1B.
ITEM 2.
ITEM 3.
ITEM 4.
PART II
ITEM 5.
ITEM 6.
SELECTED FINANCIAL 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
1
6
6
6
7
7
8
16
19
19
24
29
43
44
44
48
49
50
51
54
54
55
55
56
56
57
58
58
59
ITEM 7.
MANAGEMENT’S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS
Exelon Corporation
Executive Overview
Financial Results of Operations
Significant 2019 Transactions and Recent Developments
Exelon's Strategy and Outlook for 2020 and Beyond
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
ITEM 7A.
QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK
Contractual Obligations and Off-Balance Sheet Arrangements
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.
60
60
60
61
64
68
69
74
84
85
91
94
98
101
102
105
110
112
129
134
134
141
143
145
147
149
151
153
155
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. Early Plant Retirements
7. Property, Plant and Equipment
8. Jointly Owned Electric Utility Plant
9. Asset Retirement Obligations
10. Leases
11. Asset Impairments
12. Intangible Assets
13. Income Taxes
14. Retirement Benefits
15. Derivative Financial Instruments
16. Debt and Credit Agreements
17. Fair Value of Financial Assets and Liabilities
18. Commitments and Contingencies
19. Shareholders' Equity
20. Stock-Based Compensation Plans
21. Changes in Accumulated Other Comprehensive Income
22. Variable Interest Entities
23. Supplemental Financial Information
24. Related Party Transactions
25. Quarterly Data
ITEM 9.
ITEM 9A.
ITEM 9B.
CHANGES IN AND DISAGREEMENTS WITH ACCOUNTANTS ON ACCOUNTING AND FINANCIAL DISCLOSURE
CONTROLS AND PROCEDURES
OTHER INFORMATION
Page No.
157
178
183
188
193
198
203
208
213
218
223
223
232
235
252
255
265
269
271
272
277
280
280
283
292
305
312
322
338
348
349
352
353
356
363
367
370
370
370
PART III
ITEM 10.
ITEM 11.
ITEM 12.
ITEM 13.
ITEM 14.
PART IV
ITEM 15.
ITEM 16.
SIGNATURES
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.
371
372
373
374
375
376
421
422
422
423
424
425
426
427
428
429
430
Table of Contents
Exelon Corporation and Related Entities
GLOSSARY OF TERMS AND ABBREVIATIONS
Exelon
Generation
ComEd
PECO
BGE
Exelon Corporation
Exelon Generation Company, LLC
Commonwealth Edison Company
PECO Energy Company
Baltimore Gas and Electric Company
Pepco Holdings or PHI
Pepco Holdings LLC (formerly Pepco Holdings, Inc.)
Pepco
DPL
ACE
Registrants
Utility Registrants
Legacy PHI
ACE Funding or ATF
Antelope Valley
BondCo
BSC
CENG
Constellation
EEDC
EGR IV
EGRP
EGTP
Entergy
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
ExGen Texas Power, LLC
Entergy Nuclear FitzPatrick, LLC
Exelon Corporate
Exelon in its corporate capacity as a holding company
Exelon Transmission Company
Exelon Transmission Company, LLC
Exelon Wind
FitzPatrick
Ginna
PCI
PEC L.P.
PECO Trust III
PECO Trust IV
Exelon Wind, LLC and Exelon Generation Acquisition Company, LLC
James A. FitzPatrick nuclear generating station
R. E. Ginna nuclear generating station
Potomac Capital Investment Corporation and its subsidiaries
PECO Energy Capital, L.P.
PECO Capital Trust III
PECO Energy Capital Trust IV
Pepco Energy Services or PES
Pepco Energy Services, Inc. and its subsidiaries
PHI Corporate
PHI in its corporate capacity as a holding company
PHISCO
RPG
SolGen
TMI
UII
PHI Service Company
Renewable Power Generation
SolGen, LLC
Three Mile Island nuclear facility
Unicom Investments, Inc.
1
Table of Contents
Other Terms and Abbreviations
GLOSSARY OF TERMS AND ABBREVIATIONS
AEC
AESO
AFUDC
AGE
AMI
AMP
AOCI
ARC
ARO
ARP
ASA
BGS
CAISO
CAP
CCGTs
CERCLA
CES
Clean Air Act
Clean Water Act
CODM
Conectiv
Conectiv Energy
ConEdison Solutions
CSAPR
CTA
D.C. Circuit Court
DC PLUG
DCPSC
DDOT
DOE
DOEE
DOJ
DPSC
DSP
DSP Program
EDF
EIMA
EmPower
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
Albany Green Energy Project
Advanced Metering Infrastructure
Advanced Metering Program
Accumulated Other Comprehensive Income (Loss)
Asset Retirement Cost
Asset Retirement Obligation
Alternative Revenue Program
Asset Sale Agreement
Basic Generation Service
California ISO
Customer Assistance Program
Combined-Cycle gas turbines
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
Conectiv Energy Holdings, Inc. and substantially all of its subsidiaries, which were sold to Calpine
in July 2010
The competitive retail electricity and natural gas business of Consolidated Edison Solutions, Inc., a
subsidiary of Consolidated Edison, Inc
Cross-State Air Pollution Rule
Consolidated tax adjustment
United States Court of Appeals for the District of Columbia Circuit
District of Columbia Power Line Undergrounding Initiative
District of Columbia Public Service Commission
District Department of Transportation
United States Department of Energy
Department of Energy & Environment
United States Department of Justice
Delaware Public Service Commission
Default Service Provider
Default Service Provider Program
Electricite de France SA and its subsidiaries
Energy Infrastructure Modernization Act (Illinois Senate Bill 1652 and Illinois House Bill 3036)
A Maryland demand-side management program for Pepco and DPL
2
Table of Contents
Other Terms and Abbreviations
GLOSSARY OF TERMS AND ABBREVIATIONS
EPA
EPSA
ERCOT
ERISA
EROA
FASB
FEJA
FERC
FRCC
FRR
GAAP
GCR
GHG
GSA
GWh
IBEW
ICC
ICE
IIP
United States Environmental Protection Agency
Electric Power Supply Association
Electric Reliability Council of Texas
Employee Retirement Income Security Act of 1974, as amended
Expected Rate of Return on Assets
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
Gigawatt hour
International Brotherhood of Electrical Workers
Illinois Commerce Commission
Intercontinental Exchange
Infrastructure Investment Program
Illinois EPA
Illinois Environmental Protection Agency
Illinois Settlement Legislation
Legislation enacted in 2007 affecting electric utilities in Illinois
Integrys
IPA
IRC
IRS
ISO
ISO-NE
NYISO
kV
kW
kWh
LIBOR
LLRW
LNG
LTIP
MAPP
MATS
MBR
MDE
MDPSC
MGP
MISO
Integrys Energy Services, Inc.
Illinois Power Agency
Internal Revenue Code
Internal Revenue Service
Independent System Operator
ISO New England Inc.
New York ISO
Kilovolt
Kilowatt
Kilowatt-hour
London Interbank Offered Rate
Low-Level Radioactive Waste
Liquefied Natural Gas
Long-Term Incentive Plan
Mid-Atlantic Power Pathway
U.S. EPA Mercury and Air Toxics Rule
Market Based Rates Incentive
Maryland Department of the Environment
Maryland Public Service Commission
Manufactured Gas Plant
Midcontinent Independent System Operator, Inc.
3
Table of Contents
Other Terms and Abbreviations
GLOSSARY OF TERMS AND ABBREVIATIONS
mmcf
Moody’s
MOPR
MRV
MW
MWh
n.m.
NAAQS
NAV
NDT
NEIL
NERC
NGS
NJBPU
NJDEP
NLRB
Million Cubic Feet
Moody’s Investor Service
Minimum Offer Price Rule
Market-Related Value
Megawatt
Megawatt hour
not meaningful
National Ambient Air Quality Standards
Net Asset Value
Nuclear Decommissioning Trust
Nuclear Electric Insurance Limited
North American Electric Reliability Corporation
Natural Gas Supplier
New Jersey Board of Public Utilities
New Jersey Department of Environmental Protection
National Labor Relations Board
Non-Regulatory Agreements Units
Nuclear generating units or portions thereof whose decommissioning-related activities are not
subject to contractual elimination under regulatory accounting
NOSA
NPDES
NPNS
NRC
NSPS
NWPA
NYMEX
NYPSC
OCI
OIESO
OPC
OPEB
PA DEP
PAPUC
PCB
PGC
PG&E
PJM
POLR
POR
PPA
Nuclear Operating Services Agreement
National Pollutant Discharge Elimination System
Normal Purchase Normal Sale scope exception
Nuclear Regulatory Commission
New Source Performance Standards
Nuclear Waste Policy Act of 1982
New York Mercantile Exchange
New York Public Service Commission
Other Comprehensive Income
Ontario Independent Electricity System Operator
Office of People’s Counsel
Other Postretirement Employee Benefits
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
Purchase of Receivables
Power Purchase Agreement
Price-Anderson Act
Preferred Stock
Price-Anderson Nuclear Industries Indemnity Act of 1957
Originally issued shares of non-voting, non-convertible and non-transferable Series A preferred
stock, par value $0.01 per share
4
Table of Contents
Other Terms and Abbreviations
PRP
PSEG
PV
RCRA
REC
Regulatory Agreement Units
RES
RFP
Rider
RGGI
RMC
RNF
ROE
ROU
RPM
RPS
RSSA
RTEP
RTO
S&P
SEC
SERC
SGIG
SILO
SNF
SOS
SPFPA
SPP
TCJA
GLOSSARY OF TERMS AND ABBREVIATIONS
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
PJM Reliability Pricing Model
Renewable Energy Portfolio Standards
Reliability Support Services Agreement
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
Sale-In, Lease-Out
Spent Nuclear Fuel
Standard Offer Service
Security, Police and Fire Professionals of America
Southwest Power Pool
Tax Cuts and Jobs Act
Transition Bond Charge
Revenue ACE receives, and pays to ACE Funding, to fund the principal and interest payments on
Transition Bonds
Upstream
VIE
WECC
ZEC
ZES
Transition Bonds and related taxes, expenses and fees
Transition Bonds issued by ACE Funding
Natural gas and oil exploration and production activities
Variable Interest Entity
Western Electric Coordinating Council
Zero Emission Credit
Zero Emission Standard
5
Table of Contents
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.
FILING FORMAT
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. 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 and (c) Part II, ITEM 8. Financial Statements and Supplementary Data:
Note 18, 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
State/Jurisdiction and
Year of Incorporation
Pennsylvania (2000)
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
Commonwealth Edison
Company
Illinois (1913)
Purchase and regulated retail sale of electricity
Northern Illinois, including the City of Chicago
PECO Energy Company
Pennsylvania (1929)
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
Baltimore Gas and Electric
Company
Maryland (1906)
Purchase and regulated retail sale of electricity and natural gas
Transmission and distribution of electricity and distribution of natural gas to retail
customers
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
Delaware (2016)
Utility services holding company engaged, through its reportable segments Pepco,
DPL and ACE
Service Territories of Pepco, DPL and ACE
Potomac Electric
Power Company
District of Columbia (1896)
Purchase and regulated retail sale of electricity
Virginia (1949)
District of Columbia and Major portions of
Montgomery and Prince George’s Counties,
Maryland
Delmarva Power & Light
Company
Delaware (1909)
Virginia (1979)
Atlantic City Electric Company New Jersey (1924)
Business Services
Transmission and distribution of electricity to retail customers
Purchase and regulated retail sale of electricity and natural gas
Portions of Delaware and Maryland (electricity)
Transmission and distribution of electricity and distribution of natural gas to retail
customers
Portions of New Castle County, Delaware (natural
gas)
Purchase and regulated retail sale of electricity
Transmission and distribution of electricity to retail customers
Portions of Southern New Jersey
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
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“Other” within the consolidated financial statements and include intercompany eliminations unless otherwise disclosed.
Merger with Pepco Holdings, Inc. (Exelon)
On March 23, 2016, Exelon completed the merger contemplated by the Merger Agreement 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.
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.
Acquisitions and Dispositions
Disposition of Oyster Creek. On July 1, 2019, Generation completed the sale with Holtec International (Holtec) and its indirect wholly owned subsidiary, Oyster
Creek Environmental Protection, LLC (OCEP), of Oyster Creek located in Forked River, New Jersey, which permanently ceased generation operations on
September 17, 2018.
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Disposition of EGTP and Acquisition of Handley Generating Station. On November 7, 2017, EGTP and all of its wholly owned subsidiaries filed voluntary
petitions for relief under Chapter 11 of Title 11 of the United States Code in the United States Bankruptcy Court for the District of Delaware. As a result of the
bankruptcy filing, EGTP’s assets and liabilities were deconsolidated from Exelon and Generation's consolidated financial statements. The Chapter 11 bankruptcy
proceedings were finalized on April 17, 2018, resulting in the ownership of EGTP assets (other than the Handley Generating Station) being transferred to
EGTP's lenders.
On April 4, 2018, Generation acquired the Handley Generating Station in conjunction with the EGTP Chapter 11 proceedings for a total purchase price of $62
million.
Acquisition of FitzPatrick. On March 31, 2017, Generation acquired the single-unit FitzPatrick plant located in Scriba, New York from Entergy for a total
purchase price consideration of $289 million, resulting in an after-tax bargain purchase gain of $233 million in 2017.
Acquisition of ConEdison Solutions. On September 1, 2016, Generation acquired ConEdison Solutions for a purchase price of $257 million, including net
working capital of $204 million. The renewable energy, sustainable services and energy efficiency businesses of ConEdison were excluded from the transaction.
See Note 2 — Mergers, Acquisitions and Dispositions and Note 11 — Asset Impairments of the Combined Notes to Consolidated Financial Statements for
additional information on acquisitions and dispositions.
Generating Resources
At December 31, 2019, 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
18,872
9,665
3,057
31,594
4,765
36,359
__________
(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 generating
resources are located and Generation's customer-facing activities are conducted.
Segment
Mid-Atlantic
Midwest
New York
ERCOT
Other Power Regions
% of Capacity
Geographical Area
Eastern half of PJM, which includes Pennsylvania, New Jersey, Maryland, Virginia, West Virginia,
Delaware, the District of Columbia and parts of North Carolina
32%
38% Western half of PJM and the United States footprint of MISO, excluding MISO’s Southern Region
6% NYISO
11% Electric Reliability Council of Texas
13% New England, South, West and Canada
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Nuclear Facilities
Generation has ownership interests in thirteen nuclear generating stations currently in service, consisting of 23 units with an aggregate of 18,872 MW of
capacity. 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.
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. 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 transaction will require
approval of the NYPSC, the FERC and the NRC. The process and regulatory approvals could take one to two years or more to complete.
See ITEM 2. PROPERTIES for additional information on Generation's nuclear facilities and Note 22 — 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 2019, 2018 and 2017 electric supply (in GWh) generated from the nuclear generating
facilities was 64%, 68% and 69%, 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.
During 2019, 2018 and 2017, the nuclear generating facilities operated by Generation achieved capacity factors of 95.7%, 94.6% and 94.1%, respectively. The
capacity factors reflect ownership percentage of stations operated by Generation. 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.
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, the regulations
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under such 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. Additionally, PSEG has received 20-year operating license renewals for Salem Units 1 and 2.
The following table summarizes the current license expiration dates for Generation’s operating nuclear facilities in service:
Station
Braidwood
Byron
Calvert Cliffs
Clinton(b)
Dresden
FitzPatrick
LaSalle
Limerick
Nine Mile Point
Peach Bottom(c)
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
2033
2034
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.
(c) On July 10, 2018, Generation submitted a second 20-year license renewal application to NRC for Peach Bottom Units 2 and 3. See Note 3 - Regulatory Matters of the
Combined Notes to Consolidated Financial Statements for additional information.
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. To date, each granted license renewal has
been for 20 years beyond the original operating license expiration. 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 and Peach Bottom. 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
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useful life of 2053 and 2054 for Unit 2 and Unit 3, respectively, which reflects the anticipated second renewal of its operating licenses. See Note 3 — Regulatory
Matters of the Combined Notes to Consolidated Financial Statements for additional information on FEJA and Note 6 — Early Plant Retirements of the Combined
Notes to Consolidated Financial Statements for additional information on early retirements.
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, 2019, Generation had approximately 84,700 SNF assemblies (21,000 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 18 — 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 until after 2020.
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 18 — 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.
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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 NDTs. At December 31,
2019 the fair value of NDTs exceeds the balance of the Nuclear AROs. See ITEM 7. MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL
CONDITION AND RESULTS OF OPERATIONS — Exelon Corporation, Executive Overview; ITEM 7. MANAGEMENT'S DISCUSSION AND ANALYSIS OF
FINANCIAL CONDITION AND RESULTS OF OPERATIONS, Critical 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
17 — Fair Value of Financial Assets and Liabilities and Note 9 — Asset Retirement Obligations of the Combined Notes to Consolidated Financial Statements for
additional information regarding Generation’s NDT funds and its decommissioning obligations.
Zion Station Decommissioning. On September 1, 2010, Generation completed an Asset Sale Agreement (ASA) with EnergySolutions, Inc. and its wholly owned
subsidiaries, EnergySolutions, LLC and ZionSolutions under which ZionSolutions has assumed responsibility for decommissioning Zion Station. See Note 9 —
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 22 — 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 2019, 2018 and 2017, electric supply (in GWh) generated from
owned fossil and renewable generating facilities was 11%, 11% and 12%, respectively, of Generation’s total electric supply. The majority of this output was
dispatched to support Generation’s wholesale and retail power marketing activities. For additional information regarding Generation’s electric generating
facilities, see ITEM 2. PROPERTIES.
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.
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 16 — 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 — Exelon Generation Company, LLC.
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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, 2019:
Region
Mid-Atlantic
Midwest
ERCOT
Other Power Regions
Total
Capacity Expiring (MW)
Fuel
Number of
Agreements
Expiration
Dates
2020 - 2032
2020 - 2031
2020 - 2035
2020 - 2030
13
3
6
16
38
Capacity (MW)
235
332
1,706
2,492
4,765
2020
1,054
2021
2022
2023
2024
Thereafter
Total
814
304
168
50
2,375
4,765
The following table shows sources of electric supply in GWh for 2019 and 2018:
Nuclear(a)
Purchases — non-trading portfolio
Fossil (primarily natural gas and oil)
Renewable(b)
Total supply
Source of Electric Supply
2019
2018
181,326
70,939
21,554
7,777
281,596
185,020
59,154
21,015
8,469
273,658
__________
(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 2019 and 2018 includes physical volumes of 35,745 GWh and 35,100 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 15 — Derivative Financial Instruments of the Combined Notes to Consolidated Financial
Statements for additional information regarding derivative financial instruments.
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
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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 2020 and beyond for portions of its electricity portfolio that are unhedged.
As of December 31, 2019, the percentage of expected generation hedged for the Mid-Atlantic, Midwest, New York and ERCOT reportable segments is
91%-94% and 61%-64% for 2020 and 2021, respectively. 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 2020 includes 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 2020 capital expenditures.
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Utility Registrants
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, 2019:
ComEd
PECO
BGE
Pepco
DPL
ACE
Service Territories (in square miles)
Electric
Natural Gas
Total
Service Territory Population (in millions)
Electric
Natural Gas
Total
Main City
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
Chicago
Philadelphia
Baltimore
Main City Population
2.7
1.6
0.6
640
n/a
640
2.4
n/a
2.4
District of
Columbia
0.7
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
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
Atlantic City
0.1
0.5
0.1
0.5
0.1
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
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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.
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 electric distribution revenues and natural gas distribution revenues, ACE’s electric distribution revenues and DPL’s Delaware electric distribution and
natural gas 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 are recovered through traditional rate case proceedings. 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’ Revenues net of
purchased power and fuel expense, which is a non-GAAP measure used to evaluate operational performance, or 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-Related Proceedings
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
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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.
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, 129,000 mmcf and 58,000 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
Liquefied Natural
Gas Facility
Propane-Air Plant
Underground Storage Service
Agreements (a)
Peak Natural Gas Sources (in mmcf)
1,200
1,056
150
550
18,000
22,000
DPL
___________
(a) Natural gas from underground storage represents approximately 28%, 42% and 30% of PECO's, BGE’s and DPL's 2019-2020 heating season planned supplies,
3,900
250
n/a
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 2020 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
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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-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 approved by FERC as shown below:
ComEd
PECO
BGE
Pepco
DPL
ACE
Employees
Approval Date
January 2008
December 2019
April 2006
April 2006
April 2006
April 2006
The following table presents employee information, including information about collective bargaining agreements (CBAs), as of December 31, 2019:
Total Employees
Total Employees Covered by
CBAs
Number of CBAs
CBAs New and Renewed in
2019(a)
Total Employees Under
CBAs
New and Renewed
in 2019
Exelon
Generation
ComEd
PECO
BGE
PHI
Pepco
DPL
32,713
13,082
6,182
2,752
3,151
4,188
1,389
936
12,310
3,648
3,462
1,398
1,436
2,268
953
652
ACE
__________
(a) Does not include CBAs that were extended in 2019 while negotiations are ongoing for renewal.
398
639
32
20
2
2
1
7
1
2
2
6
2
—
—
1
3
1
—
—
2,593
189
—
—
1,436
968
953
—
—
Environmental Regulation
General
The Registrants are subject to comprehensive and complex legislation regarding environmental matters by the federal government and various state and local
jurisdictions in which they operate their facilities. The Registrants are also subject to environmental regulations administered by the EPA and various state and
local environmental protection agencies. Federal, state and local regulation includes the authority to regulate air, water, and solid and hazardous waste disposal.
The Exelon Board of Directors is responsible for overseeing the management of environmental matters. Exelon has a management team 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 Director, Safety & Sustainability, 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 Governance Committee the authority to
oversee
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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.
Air Quality
Air quality regulations promulgated by the EPA and the various state and local environmental agencies impose restrictions on emission of particulates, sulfur
dioxide (SO2), nitrogen oxides (NOx), mercury and other air pollutants and require permits for operation of emitting sources. Such permits have been obtained
as needed by Exelon’s subsidiaries. However, due to its low emitting generation fleet comprised of nuclear, natural gas, hydroelectric, wind and solar,
compliance with the Federal Clean Air Act does not have a material impact on Generation’s operations.
See ITEM 7. MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS for additional information
regarding clean air regulation in the forms of the CSAPR, regulation of hazardous air pollutants from coal- and oil-fired electric generating facilities under MATS,
and regulation of GHG emissions.
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 must be renewed periodically. Certain of Exelon's facilities discharge stormwater and industrial
wastewater into waterways and are therefore subject to these regulations and operate under NPDES permits or pending applications for renewals of such
permits after being granted an administrative extension. 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.
Section 316(b) of the Clean Water Act
Section 316(b) requires that the cooling water intake structures at electric power plants reflect the best technology available to minimize adverse environmental
impacts and is implemented through state-level NPDES permit programs. All of Generation’s power generation facilities with cooling water systems are subject
to the regulations. Facilities without closed-cycle recirculating systems (e.g., cooling towers) are potentially most affected by recent changes to the regulations.
For Generation, those facilities are Calvert Cliffs, Clinton, Dresden, Eddystone, Fairless Hills, FitzPatrick, Ginna, Gould Street, Handley, Mystic 7, Nine Mile Point
Unit 1, Peach Bottom, Quad Cities and Salem.
On October 14, 2014, the EPA's Section 316(b) rule became effective. The rule requires that a series of studies and analyses be performed to determine the
best technology available to minimize adverse impacts on aquatic life, followed by an implementation period for the selected technology. The timing of the
various requirements for each facility is related to the status of its current NPDES permit and the subsequent renewal period. There is no fixed compliance
schedule, as this is left to the discretion of the state permitting director.
Until the compliance requirements are determined by the applicable state permitting director on a site-specific basis for each plant, Generation cannot estimate
the effect that compliance with the rule will have on the operation of its generating facilities and its future results of operations, cash flows, and financial position.
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 potential impact of the rule has been significantly reduced since the final rule does not mandate cooling towers as a national standard
and sets forth technologies that are presumptively compliant, and the state permitting director is required to apply a cost-benefit test and can take into
consideration site-specific factors, such as those that would make cooling towers infeasible.
New York Facilities
In July 2011, the New York Department of Environmental Conservation (DEC) issued a policy regarding the best available technology for cooling water intake
structures. Through its policy, the DEC established closed-cycle cooling or its equivalent as the performance goal for all existing facilities, but also provided that
the DEC will select a feasible technology whose costs are not wholly disproportionate to the environmental benefits to be gained and allows for a site-specific
determination where the entrainment performance goal cannot be achieved (i.e., the requirement
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most likely to support cooling towers). The Ginna, Nine Mile Point Unit 1, and Fitzpatrick power generation facilities have received renewals of their state water
discharge permits and cooling towers were not required. These facilities are now engaged in the required analyses to enable the environmental agency to
determine the best technology available in the next permit renewal cycles.
Salem
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.
Solid and Hazardous Waste
CERCLA provides for immediate 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 waste at sites, most 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 prior to listing on
the NPL. Various states, including Delaware, Illinois, Maryland, New Jersey and Pennsylvania and the District of Columbia have also enacted statutes that
contain provisions substantially similar to CERCLA. In addition, RCRA governs treatment, storage and disposal of solid and hazardous wastes and cleanup of
sites where such activities were conducted.
Generation, the Utility 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 with respect to a number of sites, including MGP sites, or may undertake to investigate and remediate sites
for which they may be subject to enforcement actions by an agency or third-party.
See Note 18 — Commitments and Contingencies of the Combined Notes to Consolidated Financial Statements for additional information related to
environmental matters.
Environmental Remediation
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 2020 for compliance with environmental remediation related to contamination at former MGP sites and other gas purification sites is expected to
total $49 million which consists primarily of $45 million at ComEd. The Utility Registrants also have contingent liabilities for environmental remediation of non-
MGP contaminants (e.g., PCBs). As of December 31, 2019, the Utility Registrants have established appropriate contingent liabilities for environmental
remediation requirements.
The Registrants’ operations have in the past, and may in the future, require substantial expenditures in order 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, Generation and the Utility Registrants may be required to make significant additional expenditures not presently determinable for other environmental
remediation costs.
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See Note 3 — Regulatory Matters and Note 18 — Commitments and Contingencies of the Combined Notes to Consolidated Financial Statements for additional
information regarding the Registrants’ environmental remediation efforts and related impacts to the Registrants’ Consolidated Financial Statements.
Global Climate Change
Exelon has utility and generation assets, and customers, that are and will be further subject to the impacts of climate change. Accordingly, Exelon is engaged in
a variety of initiatives to understand and mitigate these impacts, including investments in resiliency, partnering with federal, state and local governments to
minimize impacts, and, importantly, advocating for public policy that reduces emissions that cause climate change. Exelon, as a producer of electricity from
predominantly low- and zero-carbon generating facilities (such as nuclear, hydroelectric, natural gas, wind and solar photovoltaic), has a relatively small GHG
emission profile, or carbon footprint, compared to other domestic generators of electricity (Exelon neither owns nor operates any coal-fueled generating assets).
Exelon's natural gas and biomass fired generating plants produce GHG emissions, most notably, CO2. However, Generation’s owned-asset emission intensity,
or rate of carbon dioxide equivalent (CO2e) emitted per unit of electricity generated, is among the lowest in the industry. Other GHG emission sources at Exelon
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. Exelon facilities and operations are subject to the global
impacts of climate change and Exelon believes its operations could be significantly affected by the physical risks of climate change. See ITEM 1A. RISK
FACTORS for additional information.
Climate Change Regulation
Exelon is or may become subject to additional climate change regulation or legislation at the federal, regional and state levels.
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, and it became effective on November 4, 2016. Under the Paris Agreement, the Parties agreed to try to limit the global average temperature
increase to 2°C (3.6°F) above pre-industrial levels. In doing so, Parties developed their own national reduction commitments. The United States submitted a
non-binding target of 17% below 2005 emission levels by 2020 and 26% to 28% below 2005 levels by 2025. President Trump has stated his intention to
withdraw the U.S. from the Paris Agreement, but no formal action has been initiated. A withdrawal would not be effective until November 2020 at the earliest.
Federal Climate Change Legislation and Regulation. It is highly unlikely that federal legislation to reduce GHG emissions will be enacted in the near-term. If such
legislation is 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.
Under the Obama Administration, the EPA finalized its Clean Power Plan regulations to reduce GHG emissions from fossil fuel-fired power plants. Subsequently,
the Trump Administration EPA proposed regulations on October 16, 2017 to repeal the CPP on the basis that the new Administration believed that the CPP rule
went beyond the EPA's authority to establish a best system of emissions reduction (BSER) for existing power plants. On August 31, 2018, EPA proposed its
Affordable Clean Energy rule to replace the CPP with revised emission guidelines based on heat rate improvement measures that could be achieved within the
fence line of existing power plants. In June 2019, EPA issued a final rule that repealed the CPP, and finalized the Affordable Clean Energy rule. The Affordable
Clean Energy rule is currently being litigated.
Given litigation uncertainty around the final Affordable Clean Energy rule, Exelon and Generation cannot predict the impacts of regulation of existing power
plants, or individual state responses to developments related to final resolution of the Affordable Clean Energy rule, or how developments will impact their future
financial statements.
Regional and State Climate Change Legislation and Regulation. A number of states in which Exelon operates have state and regional programs to reduce GHG
emissions, including from the power sector. As the nation’s largest generator of carbon-free electricity, our fleet supports these efforts to produce safe, reliable
electricity with minimal GHGs. Notably, nine northeast and mid-Atlantic states (Connecticut, Delaware, Maine, Maryland, Massachusetts, New Hampshire, New
York, Rhode Island and Vermont) currently participate in the Regional Greenhouse Gas
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Initiative (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 June 2019, New Jersey was accepted as a RGGI member effective January 2020. In October 2019, Governor Wolf of Pennsylvania issued an Executive
Order that directed the Pennsylvania Department of Environmental Protection to begin a rulemaking process that will allow Pennsylvania to join the RGGI, with
the goal of reducing carbon emissions from the electricity sector.
Many states in which Exelon subsidiaries operate also have state-specific programs to address GHGs, including from power plants. Most notable of these,
besides RGGI, are through renewable and other portfolio standards. Additionally, in response to a court decision clarifying the obligations under the Global
Warming Solutions Act, the Massachusetts Department of Environmental Protection in 2017 finalized regulations establishing a statewide cap on CO2 emissions
from fossil fuel power plants (Massachusetts remains in RGGI as well). The effect of this new obligation and potential for market illiquidity in the early years
represent a risk to Generation’s Massachusetts fossil facilities, including Medway and Mystic. At the same time, the District of Columbia is considering a plan to
incorporate the cost of carbon into electricity, via consumption, as well as directly into the cost of transportation and home heating fuels. Details remain to be
developed, but the specifics could have implications for Pepco’s operations.
Regardless of whether GHG regulation occurs at the local, state, or federal level, Exelon remains one of the largest, lowest-carbon electric generators in the
United States, relying mainly on nuclear, natural gas, hydropower, wind, and solar. The extent that the low-carbon generating fleet will continue to be a
competitive advantage for Exelon depends on resolution of the CPP and Affordable Clean Energy regulations and associated current or future litigation at the
federal level, new or expanded state action on greenhouse gas emissions or direct support of clean energy technologies, including nuclear, as well as potential
market reforms that value our fleet’s emission-free attributes.
Renewable and Alternative Energy Portfolio Standards
Thirty-nine states and the District of Columbia, incorporating the vast majority of Exelon operations as well as all utility operations, have adopted some form of
RPS 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. Exelon's utilities 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. New York, Illinois 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 Generation and our utilities operate are considering similar programs.
See Note 3 — Regulatory Matters of the Combined Notes to Consolidated Financial Statements for additional information on renewable portfolio standards.
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Information about our Executive Officers as of February 11, 2020
Exelon
Name
Crane, Christopher M.
Age Position
61 Chief Executive Officer, Exelon;
President, Exelon
Cornew, Kenneth W.
54 Senior Executive Vice President and Chief Commercial Officer, Exelon;
President and CEO, Generation
Butler, Calvin G.
50
Senior Executive Vice President, Exelon; Chief Executive Officer, Exelon
Utilities
Dominguez, Joseph
57 Chief Executive Officer, ComEd
Chief Executive Officer, BGE
Executive Vice President, Governmental & Regulatory Affairs and Public
Policy, Exelon
Period
2012 - Present
2008 - Present
2013 - Present
2013 - Present
2019 - Present
2014 - 2019
2018 - Present
2015 - 2018
Senior Vice President, Governmental & Regulatory Affairs and Public Policy,
Exelon
2012 - 2015
Innocenzo, Michael A.
54 President and Chief Executive Officer, PECO
Senior Vice President and Chief Operations Officer, PECO
Khouzami, Carim V.
44 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.
60 President and Chief Executive Officer, PHI
President and Chief Executive Officer, Pepco, DPL and ACE
Executive Vice President, Pepco Holdings, Inc.
2018 - Present
2012 - 2018
2019 - Present
2018 - 2019
2016 - 2018
2014 - 2016
2016 - Present
2009 - Present
2009 - 2016
Von Hoene Jr., William A.
66 Senior Executive Vice President and Chief Strategy Officer, Exelon
2012 - Present
Nigro, Joseph
55 Senior Executive Vice President and Chief Financial Officer, Exelon
2018 - Present
Aliabadi, Paymon
Souza, Fabian E.
Executive Vice President, Exelon; Chief Executive Officer, Constellation
2013 - 2018
57 Executive Vice President and Chief Risk Officer, Exelon
49 Senior Vice President and Corporate Controller, Exelon
Senior Vice President and Deputy Controller, Exelon
2013 - Present
2018 - Present
2017 - 2018
Vice President, Controller and Chief Accounting Officer, The AES Corporation
2015 - 2017
Vice President, Internal Audit and Advisory Services, The AES Corporation
2014 - 2015
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Generation
Name
Cornew, Kenneth W.
Age Position
54 Senior Executive Vice President and Chief Commercial Officer, Exelon;
President and Chief Executive Officer, Generation
Period
2013 - Present
2013 - Present
Pacilio, Michael J.
59 Executive Vice President and Chief Operating Officer, Generation
2015 - Present
President, Exelon Nuclear; Senior Vice President and Chief Nuclear Officer,
Generation
2010 - 2015
Hanson, Bryan C
54
President and Chief Nuclear Officer, Exelon Nuclear; Senior Vice President,
Generation
2015 - Present
McHugh, James
48 Executive Vice President, Exelon; Chief Executive Officer, Constellation
2018 - Present
Senior Vice President, Portfolio Management & Strategy, Constellation
Vice President, Portfolio Management, Constellation
Barnes, John
56 Senior Vice President, Generation; President, Exelon Power
Senior Vice President, Generation, Senior Vice President and Chief Operating
Officer, Exelon Power
2016 - 2018
2012 - 2016
2018 - Present
2012 - 2018
Wright, Bryan P.
Bauer, Matthew N.
53 Senior Vice President and Chief Financial Officer, Generation
2013 - Present
43 Vice President and Controller, Generation
Vice President and Controller, BGE
2016 - Present
2014 - 2016
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ComEd
Name
Dominguez, Joseph
Age Position
57 Chief Executive Officer, ComEd
Executive Vice President, Governmental & Regulatory Affairs and Public
Policy, Exelon
Period
2018 - Present
2015 - 2018
Senior Vice President, Governmental & Regulatory Affairs and Public Policy,
Exelon
2012 - 2015
Donnelly, Terence R.
59 President and Chief Operating Officer, ComEd
Executive Vice President and Chief Operating Officer, ComEd
Jones, Jeanne M.
40 Senior Vice President, Chief Financial Officer and Treasurer, ComEd
Vice President, Finance, Exelon Nuclear
Park, Jane
47 Senior Vice President, Customer Operations, ComEd
Vice President, Regulatory Policy & Strategy, ComEd
Director, Business Strategy & Technology, ComEd
Gomez, Veronica
50
Senior Vice President, Regulatory and Energy Policy and General Counsel,
ComEd
2018 - Present
2012 - 2018
2018 - Present
2014 - 2018
2018 - Present
2016 - 2018
2014 - 2016
2017 - Present
Vice President and Deputy General Counsel, Litigation, Exelon
2012 - 2017
Washington, Melissa
50 Senior Vice President, Governmental and External Affairs, ComEd
2019 - Present
Vice President, Governmental and External Affairs, ComEd
Vice President, External Affairs and Large Customer Services, ComEd
Vice President, Corporate Affairs, Exelon Business Services Company
Perez, David
50 Senior Vice President, Distribution Operations, ComEd
Vice President, Transmission and Substation, ComEd
Vice President, Regional Operations, ComEd
Kozel, Gerald J.
47 Vice President, Controller, ComEd
26
2019 -2019
2016 - 2019
2014 - 2016
2019 - Present
2016 - 2019
2010 - 2016
2013 - Present
Table of Contents
PECO
Name
Innocenzo, Michael A.
Age Position
54 President and Chief Executive Officer, PECO
Senior Vice President and Chief Operations Officer, PECO
McDonald, John
62 Senior Vice President and Chief Operations Officer, PECO
Vice President, Integration, PHI
Vice President, Technical Services
Period
2018 - Present
2012 - 2018
2018 - Present
2016 - 2018
2006 - 2016
Stefani, Robert J.
45 Senior Vice President, Chief Financial Officer and Treasurer, PECO
2018 - Present
Vice President, Corporate Development, Exelon
Director, Corporate Development, Exelon
Murphy, Elizabeth A.
60 Senior Vice President, Governmental and External Affairs, PECO
Vice President, Governmental and External Affairs, PECO
Webster Jr., Richard G.
58 Vice President, Regulatory Policy and Strategy, PECO
Williamson, Olufunmilayo
41 Senior Vice President, Customer Operations, PECO
Senior Vice President, Chief Commercial Risk Officer, Exelon
Vice President, Commercial Risk Management, Exelon
Gay, Anthony
54 Vice President and General Counsel, PECO
Vice President, Governmental and External Affairs, PECO
Associate General Counsel, Exelon
Bailey, Scott A.
43 Vice President and Controller, PECO
2015 - 2018
2012 - 2015
2016 - Present
2012 - 2016
2012 - Present
2020 - Present
2017 - 2020
2015 - 2017
2019 - Present
2016 - 2019
2010 - 2016
2012 - Present
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BGE
Name
Khouzami, Carim V.
Age Position
44 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.
52 President, BGE
Chief Operating Officer, BGE
Vahos, David M.
47 Senior Vice President, Chief Financial Officer and Treasurer, BGE
Vice President, Chief Financial Officer and Treasurer, BGE
Núñez, Alexander G.
48 Senior Vice President, Regulatory Affairs and Strategy, BGE
Senior Vice President, Regulatory and External Affairs, BGE
Vice President, Governmental and External Affairs, BGE
58 Vice President, Strategy and Regulatory Affairs, BGE
Case, Mark D.
Oddoye, Rodney
43 Senior Vice President, Governmental and External Affairs, BGE
2020 - Present
Vice President, Customer Operations, BGE
Director, Northeast Regional Electric Operations, BGE
Director, Financial Operations, BGE
Manager, Distribution Operations, BGE
Olivier, Tamla
47 Senior Vice President, Customer Operations, BGE
Senior Vice President, Constellation NewEnergy, Inc.
VP, Human Resources, Exelon Business Services Company
Corse, John
59 Vice President and General Counsel, BGE
Associate General Counsel, Exelon
Holmes, Andrew W.
51 Vice President and Controller, BGE
Director, Generation Accounting, Exelon
28
2018 - 2020
2016 - 2018
2015 - 2016
2013 - 2015
2020 - Present
2016 - 2020
2012 - 2016
2018 - Present
2012 - 2018
2016 - Present
2013 - 2016
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
Table of Contents
PHI, Pepco, DPL and ACE
Name
Velazquez, David M.
Age Position
60 President and Chief Executive Officer, PHI
Executive Vice President, Pepco Holdings, Inc.
President and Chief Executive Officer, Pepco, DPL and ACE
Period
2016 - Present
2009 - 2016
2009 - Present
Anthony, J. Tyler
55 Senior Vice President and Chief Operating Officer, PHI, Pepco, DPL and ACE 2016 - Present
Barnett, Phillip S.
Senior Vice President, Distribution Operations, ComEd
2010 - 2016
56
Senior Vice President, Chief Financial Officer and Treasurer, PHI, Pepco, DPL
and ACE
2018 - Present
Senior Vice President and Chief Financial Officer, PECO
Treasurer, PECO
2007 - 2018
2012 - 2018
Lavinson, Melissa
50
Senior Vice President, Governmental & External Affairs, PHI, Pepco, DPL and
ACE
2018 - Present
Vice President, Federal Affairs and Policy and Chief Sustainability Officer,
PG&E Corporation
Vice President, Federal Affairs, PG&E Corporation
Stark, Wendy E.
47
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.
2015 - 2018
2012 - 2015
2019 - Present
2016 - 2018
2012 - 2016
McGowan, Kevin M.
58 Vice President, Regulatory Policy and Strategy, PHI, Pepco, DPL and ACE
2016 - Present
Dickens, Derrick
55 Senior Vice President, Customer Operations, PHI
Vice President, Regulatory Affairs, Pepco Holdings, Inc.
Vice President, Technical Services, BGE
Director, Advanced Meter Infrastructure, PECO
Aiken, Robert
53 Vice President and Controller, PHI, Pepco, DPL and ACE
Vice President and Controller, Generation
2012 - 2016
2020 - Present
2016 - 2020
2012 - 2016
2016 - Present
2012 - 2016
ITEM 1A.
RISK FACTORS
Each of the Registrants operates in a complex market and regulatory environment that involves significant risks, many of which are beyond that Registrant’s
direct control. Such risks, which could negatively affect one or more of the Registrants’ consolidated financial statements, fall primarily under the categories
below:
Market and Financial Factors primarily include:
•
•
the price of fuels, in particular the price of natural gas, which affects power prices,
the generation resources in the markets in which the Registrants operate,
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•
•
•
the demand for electricity, reliability of service and affordability in the markets where the Registrants conduct their business,
the impacts of on-going competition, and
emerging technologies and business models.
Regulatory and Legislative Factors primarily include changes to the laws and regulations that govern:
•
•
•
•
•
•
the design of power markets,
zero emission credit programs,
utility regulatory business model,
regulations and other standards,
environmental 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 the effects of climate
change regulation could impact the GHG emissions from the Registrant’s operations,
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
the Registrants face physical and cyber security risks as the owner-operators of generation, transmission and distribution facilities and as participants in
commodities trading.
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.
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.
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
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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 6 — 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 decommission its nuclear plants. A decline in the market value of the pension and OPEB plan assets will increase the funding
requirements associated with Exelon’s pension and OPEB plan obligations. Additionally, Exelon’s pension and OPEB plan liabilities are sensitive to changes in
interest rates. As interest rates decrease, the 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 9 — Asset Retirement Obligations and
Note 14 — 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
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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, 2019, approximately 23%, 19%, and 18%
of the Registrants’ available credit facilities were with European, Canadian and Asian banks, respectively. See Note 16 — 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 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.
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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.
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.
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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.
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, PHI’s, and ComEd’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 7 — Property, Plant and Equipment, Note 11 — Asset Impairments and Note 12 —
Intangible Assets of the Combined Notes to the Consolidated Financial Statements for additional information on long-lived asset 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
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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 a
Registrant could incur substantial costs to fulfill its obligations under these indemnities.
The Registrants have issued guarantees of the performance of third parties, which obligate the Registrant to perform in the event that the third parties do not
perform. In the event of non-performance by those third parties, a Registrant could incur substantial cost to fulfill its 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 of
amounts, if any, were already paid to the counterparties. In the spot markets, Generation is 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 and Legislative 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
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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 6 — 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 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, bad debt, 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 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 decommission fully its nuclear
units. Generation cannot predict what, if any, fee may be established in the future for SNF disposal. See Note 18 — 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.
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PECO, BGE and DPL as operators of natural gas distribution systems, PECO, BGE and DPL 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 which 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 and solid waste disposal. Violations of these emission and disposal 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 contaminated by
hazardous substances they generate. 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.
If application of Section 316(b) of the Clean Water Act, which establishes a national requirement for reducing the adverse impacts to aquatic organisms at
existing generating stations, requires the retrofitting of cooling water intake structures at Salem or other Exelon power plants, this development could result in
material costs of compliance. 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 13 — 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 Alternative Energy Portfolio Standards for additional information.
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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 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 18 —
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.
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 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.
Exelon and ComEd have received requests for information related to government investigations. The outcome of the investigations could
have a material adverse effect on their reputation and consolidated financial statements (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 requiring
production of information concerning their lobbying activities in the state
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of Illinois. On October 4, 2019, Exelon and ComEd received a second grand jury subpoena from the U.S. Attorney’s Office for the Northern District of Illinois
requiring production of records of any communications with certain individuals and entities. On October 22, 2019, the SEC notified Exelon and ComEd that it has
also opened an investigation into their lobbying activities. Exelon and ComEd have cooperated fully, including by providing additional information requested by
the U.S. Attorney’s Office and the SEC, and intend to continue to cooperate fully and expeditiously with the U.S. Attorney’s Office and the SEC. The outcome of
the U.S. Attorney’s Office and SEC investigations cannot be predicted and could subject Exelon and ComEd to criminal or civil penalties, sanctions or other
remedial measures. Any of the foregoing, as well as the appearance of non-compliance with anti-corruption and anti-bribery laws, could have an adverse impact
on Exelon’s and ComEd’s reputation or relationship with regulatory and legislative authorities, customers and other stakeholders, as well as their consolidated
financial statements.
Operational Factors
The Registrants are subject to risks associated with climate change (All Registrants).
Physical plants could be placed at greater risk of damage should changes in the global climate produce unusual variations in temperature and weather patterns,
resulting in more intense, frequent and extreme weather events, unprecedented levels of precipitation and a change in sea level. The Registrants’ 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. Still disruption or failure of electric generation, transmission or distribution
systems or natural gas production, transmission, storage or distribution systems in the event of a hurricane, tornado or other severe weather event, or otherwise,
could prevent the Registrants from operating their business in the normal course.
The Registrants are considering ways to address the effect of GHG emissions on climate change. If carbon reduction regulation or legislation becomes effective,
the Registrants could incur costs either to limit further the GHG emissions from their operations or to procure emission allowance credits for Generation’s fossil
fuel-fired generation. See ITEM 1. BUSINESS — Global Climate Change.
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 performance at
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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 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 $13.9 billion limit for a single incident.
See Note 18 — 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 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 NDTs 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 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.
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See Note 9 — 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 advanced metering
infrastructure, 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, 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.
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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 1. BUSINESS
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 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.
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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.
ITEM 1B.
UNRESOLVED STAFF COMMENTS
All Registrants
None.
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ITEM 2.
PROPERTIES
Generation
The following table presents Generation’s interests in net electric generating capacity by station at December 31, 2019:
Station(a)
Location
No. of
Units
Percent
Owned(b)
Primary
Fuel Type
Primary
Dispatch
Type(c)
Net Generation
Capacity (MW)(d)
Midwest
Braidwood
Byron
LaSalle
Dresden
Quad Cities
Clinton
Michigan Wind 2
Beebe
Michigan Wind 1
Harvest 2
Harvest
Beebe 1B
Ewington
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
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
Jackson Co., MN
Chicago, IL
Toledo, OH
Faribault Co., MN
Faribault Co., MN
Chicago, IL
Blanchester, OH
2
2
2
2
2
1
50
34
46
33
32
21
10
1
2
2
2
8
1
75
51 (g)
51 (g)
51 (g)
51 (g)
51 (g)
51 (g)
99
51 (g)
Sanatoga, PA
2
Delta, PA
Lower Alloways
Creek Township, NJ
Lusby, MD
Darlington, MD
Oakland, MD
Garrett County, MD
Various, MD
Garrett County, MD
2
2
2
11
28
12
41
16
50
42.59
50.01 (f)
51 (g)
51 (g)
44
Uranium
Uranium
Uranium
Uranium
Uranium
Uranium
Wind
Wind
Wind
Wind
Wind
Wind
Wind
Solar
Solar
Wind
Wind
Gas
Energy Storage
Uranium
Uranium
Uranium
Uranium
Hydroelectric
Wind
Wind
Solar
Wind
Base-load
Base-load
Base-load
Base-load
Base-load
Base-load
Base-load
Base-load
Base-load
Base-load
Base-load
Base-load
Base-load
Base-load
Base-load
Base-load
Base-load
Peaking
Peaking
Base-load
Base-load
Base-load
Base-load
Base-load
Base-load
Base-load
Base-load
Base-load
2,386
2,347
2,320
1,845
1,403 (e)
1,069
46 (e)
42 (e)
35 (e)
30 (e)
27 (e)
26 (e)
20 (e)
9
4
3
2 (e)
296 (k)
10
11,920
2,317
1,324 (e)
998 (e)
895 (e)
572
36 (e)
30
39
20 (e)
Table of Contents
Station(a)
Location
No. of
Units
Percent
Owned(b)
Primary
Fuel Type
Primary
Dispatch
Type(c)
Net Generation
Capacity (MW)(d)
Solar New Jersey 1
Solar New Jersey 2
Solar Horizons
Solar Maryland
Solar Maryland 2
JBAB Solar
Gateway Solar
Constellation New Energy
Solar Federal
Solar New Jersey 3
Solar DC
Muddy Run
Eddystone 3, 4
Perryman
Croydon
Handsome Lake
Notch Cliff
Westport
Richmond
Philadelphia Road
Eddystone
Fairless Hills
Delaware
Southwark
Falls
Moser
Chester
Schuylkill
Salem
Pennsbury
Total Mid-Atlantic
ERCOT
Whitetail
Sendero
Various, NJ
Various, NJ
Emmitsburg, MD
5
2
1
Various, MD
11
Various, MD
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
Baltimore, MD
Baltimore, MD
Philadelphia, PA
Baltimore, MD
Eddystone, PA
Fairless Hills, PA
Philadelphia, PA
Philadelphia, PA
Morrisville, PA
Lower PottsgroveTwp.,
PA
Chester, PA
Philadelphia, PA
Lower Alloways
Creek Township, NJ
Morrisville, PA
3
4
1
3
1
5
1
8
2
5
8
5
8
1
2
4
4
2
4
4
3
3
3
2
1
2
51 (g)
51 (g)
Solar
Solar
Solar
Solar
Solar
Solar
Solar
Solar
Solar
Solar
Solar
Base-load
Base-load
Base-load
Base-load
Base-load
Base-load
Base-load
Base-load
Base-load
Base-load
Base-load
18
11
8 (e)
8
8
7
7
6
5
1 (e)
1
Hydroelectric
Intermediate
1,070
Oil/Gas
Oil/Gas
Oil
Gas
Gas
Gas
Oil
Oil
Oil
Landfill Gas
Oil
Oil
Oil
Oil
Oil
Oil
Oil
Landfill Gas
Peaking
Peaking
Peaking
Peaking
Peaking
Peaking
Peaking
Peaking
Peaking
Peaking
Peaking
Peaking
Peaking
Peaking
Peaking
Peaking
Peaking
Peaking
760
404
391
268
117 (j)
116 (j)
98
61
60
60 (j)
56
52
51
51
39
30
16 (e)
4 (e)
10,015
42.59
Webb County, TX
Jim Hogg and Zapata
County, TX
57
39
51 (g)
51 (g)
Wind
Wind
Base-load
Base-load
46 (e)
40 (e)
45
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Station(a)
Location
No. of
Units
Percent
Owned(b)
Primary
Fuel Type
Primary
Dispatch
Type(c)
Net Generation
Capacity (MW)(d)
Constellation Solar Texas
Colorado Bend II
Wolf Hollow II
Handley 3
Handley 4, 5
Total ERCOT
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
High Plains
Solar Georgia 2
Tuana Springs
Solar Georgia
Greensburg
Solar
Massachusetts
Outback Solar
Echo 3
Various, TX
11
Wharton, TX
Granbury, TX
Fort Worth, TX
Fort Worth, TX
Scriba, NY
Scriba, NY
Ontario, NY
Bethlehem, NY
3
3
1
2
2
1
1
1
Lancaster, CA
1
Beaver County, OK
Kiowa County, KS
Albany, GA
60
65
1
Various, AZ
127
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
Panhandle, TX
Various, GA
Hagerman, ID
Various, GA
Greensburg, KS
Various, MA
Christmas Valley, OR
Echo, OR
27
90
24
24
56
53
20
19
21
4
14
13
10
8
8
8
10
10
10
1
6
50.01 (f)
50.01 (f)
51 (g)(h)
51 (g)
99 (i)
51 (g)
51 (g)
51 (g)
51 (g)
51 (g)
50.49 (g)
51 (g)
51 (g)
51 (g)
51 (g)
99.5
51 (g)
51 (g)
50.49 (g)
46
Solar
Gas
Gas
Gas
Gas
Base-load
Intermediate
Intermediate
Intermediate
Peaking
Uranium
Uranium
Uranium
Solar
Solar
Wind
Wind
Biomass
Solar
Wind
Solar
Wind
Wind
Solar
Solar
Wind
Wind
Wind
Solar
Wind
Wind
Wind
Wind
Solar
Wind
Solar
Wind
Solar
Solar
Wind
Base-load
Base-load
Base-load
Base-load
Base-load
Base-load
Base-load
Base-load
Base-load
Base-load
Base-load
Base-load
Base-load
Base-load
Base-load
Base-load
Base-load
Base-load
Base-load
Base-load
Base-load
Base-load
Base-load
Base-load
Base-load
Base-load
Base-load
Base-load
Base-load
Base-load
13
1,140
1,115
395
870
3,619
838 (e)
842
288 (e)
3
1,971
242
101 (e)
53 (e)
53
46
29 (e)
28
26 (e)
26 (e)
34
21
21 (e)
20 (e)
17 (e)
15 (e)
15 (e)
14 (e)
10 (e)
10 (e)
10
9 (e)
8
7 (e)
7
6
5 (e)
Table of Contents
Station(a)
Location
No. of
Units
Percent
Owned(b)
Primary
Fuel Type
Primary
Dispatch
Type(c)
Net Generation
Capacity (MW)(d)
Holyoke Solar
Three Mile Canyon
Loess Hills
California PV Energy 3
Mohave Sunrise Solar
Denver Airport
Solar
Solar Net Metering
Solar Connecticut
Mystic 8, 9
Hillabee
Mystic 7
Wyman 4
Grand Prairie
West Medway
West Medway II
Framingham
Mystic Jet
Total Other
Total
51 (g)
51 (g)
5.9
Various, MA
Boardman, OR
Rock Port, MO
Various, CA
Fort Mohave, AZ
Denver, CO
Uxbridge, MA
Various, CT
Charlestown, MA
Alexander City, AL
Charlestown, MA
Yarmouth, ME
Alberta, Canada
West Medway, MA
West Medway, MA
Framingham, MA
Charlestown, MA
2
6
4
19
1
1
1
1
6
3
1
1
1
3
2
3
1
Solar
Wind
Wind
Solar
Solar
Solar
Solar
Solar
Gas
Gas
Base-load
Base-load
Base-load
Base-load
Base-load
Base-load
Base-load
Base-load
Intermediate
Intermediate
Oil/Gas
Intermediate
Oil
Gas
Oil
Oil/Gas
Oil
Oil
Intermediate
Peaking
Peaking
Peaking
Peaking
Peaking
5
5 (e)
5
6
5
2 (e)
2
1
1,417
753
542 (j)
35 (e)
105
123
190
31
9 (j)
4,069
31,594
__________
(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. 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 reflect a summer rating. Wind and solar facilities reflect name plate capacity.
(e) Net generation capacity is stated at proportionate ownership share.
(f) Reflects Generation’s interest in CENG, a joint venture with EDF. See ITEM 1. — BUSINESS — Exelon Generation Company, LLC — Nuclear Facilities for additional
information.
(g) Reflects the prior sale of 49% of EGRP to a third party. See Note 22 — Variable Interest Entities of the Combined Notes to Consolidated Financial Statements for
additional information.
(h) 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.
(i) Generation directly owns a 50% interest in the Albany Green Energy station and an additional 49% through the consolidation of a Variable Interest Entity.
(j) Generation has plans to retire and cease generation operations at certain plants in 2020 and 2021.
(k) Generation has deactivated the site and is evaluating for potential return of service or retirement in 2020.
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
47
Table of Contents
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.
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, 2019 were as follows:
Voltage
(Volts)
765,000
500,000(a)
345,000
230,000
138,000
115,000
69,000
ComEd
PECO
90
—
2,716
—
2,224
—
—
(a)
—
188
—
549
135
—
177
BGE
—
216
—
358
55
705
—
Circuit Miles
Pepco
—
109
—
769
50
25
—
(a)
DPL
—
16
—
472
586
—
569
(a)
ACE
—
—
—
274
209
—
661
___________
(a)
In addition, PECO, DPL, and ACE have an ownership interest located in Delaware and New Jersey. See Note 8 - Jointly Owned Electric Utility Plant - for additional
information.
The Utility Registrant’s electric distribution system includes the following number of circuit miles of overhead and underground lines:
Circuit Miles
Overhead
Underground
ComEd
35,385
31,799
PECO
12,964
9,417
BGE
9,176
17,489
Pepco
4,104
6,993
DPL
6,010
6,316
ACE
7,350
2,942
Gas
The following table presents PECO’s, BGE’s and DPL’s natural gas pipeline miles at December 31, 2019:
Transmission
Distribution
Service piping
Total
PECO
9
6,932
6,414
13,355
BGE
161
7,386
6,345
13,892
48
(a)
DPL
8
2,114
1,447
3,569
Table of Contents
___________
(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.
The following table presents PECO’s, BGE’s and DPL’s natural gas facilities:
Registrant
PECO
PECO
BGE
BGE
DPL
Facility
LNG Facility
Location
West Conshohocken, PA
Propane Air Plant
LNG Facility
Propane Air Plant
LNG Facility
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, 32, 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 16 — 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 18 — Commitments and Contingencies of the Combined Notes to Consolidated
Financial Statements. Such descriptions are incorporated herein by these references.
49
Table of Contents
ITEM 4.
MINE SAFETY DISCLOSURES
All Registrants
Not Applicable to the Registrants.
50
Table of Contents
PART II
(Dollars in millions except per share data, unless otherwise noted)
ITEM 5.
MARKET FOR REGISTRANT’S COMMON EQUITY, RELATED STOCKHOLDER MATTERS AND ISSUER PURCHASES OF
EQUITY SECURITIES
Exelon
Exelon’s common stock is listed on the Nasdaq (trading symbol: EXC). As of January 31, 2020, there were 974,319,565 shares of common stock outstanding
and approximately 95,064 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 2015 through 2019.
This performance chart assumes:
•
•
$100 invested on December 31, 2014 in Exelon common stock, the S&P 500 Stock Index and the S&P Utility Index; and
All dividends are reinvested.
Exelon Corporation
S&P 500
S&P Utilities
2014
$100
$100
$100
2015
$77.83
$101.38
$95.15
2016
$103.37
$113.51
$110.65
2017
$118.92
$138.29
$124.05
2018
$140.72
$132.23
$129.14
2019
$146.74
$173.86
$163.17
Value of Investment at December 31,
Generation
As of January 31, 2020, Exelon indirectly held the entire membership interest in Generation.
ComEd
As of January 31, 2020, there were 127,021,349 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, 2020, in addition to Exelon, there were 296 record holders of ComEd common stock. There is no established market for shares of
the common stock of ComEd.
PECO
As of January 31, 2020, there were 170,478,507 outstanding shares of common stock, without par value, of PECO, all of which were indirectly held by Exelon.
51
Table of Contents
BGE
As of January 31, 2020, 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, 2020, Exelon indirectly held the entire membership interest in PHI.
Pepco
As of January 31, 2020, 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, 2020, 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, 2020, 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 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
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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.
Exelon’s Board of Directors approved an updated dividend policy providing an increase of 5% each year for the period covering 2018 through 2020, beginning
with the March 2018 dividend.
At December 31, 2019, Exelon had retained earnings of $16,267 million, including Generation’s undistributed earnings of $3,950 million, ComEd’s retained
earnings of $1,517 million consisting of retained earnings appropriated for future dividends of $3,156 million, partially offset by $1,639 million of unappropriated
accumulated deficits, PECO’s retained earnings of $1,412 million, BGE’s retained earnings of $1,776 million, and PHI's undistributed losses of $10 million.
The following table sets forth Exelon’s quarterly cash dividends per share paid during 2019 and 2018:
(per share)
Exelon
Fourth
Quarter
Third
Quarter
Second
Quarter
First
Quarter
Fourth
Quarter
Third
Quarter
Second
Quarter
First
Quarter
$
0.363 $
0.363 $
0.363 $
0.363 $
0.345 $
0.345 $
0.345 $
0.345
2019
2018
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
2019
2018
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
313 $
114
6
52
94
41
38
13
311 $
116
7
52
123
78
18
27
189 $
115
6
53
38
25
4
10
188
114
287
52
71
25
36
9
First Quarter 2020 Dividend
On January 28, 2020, the Exelon Board of Directors declared a first quarter 2020 regular quarterly dividend of $0.3825 per share on Exelon’s common stock
payable on March 10, 2020, to shareholders of record of Exelon at the end of the day on February 20, 2020.
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Table of Contents
ITEM 6.
SELECTED FINANCIAL DATA
Exelon
The selected financial data presented below has been derived from the audited consolidated financial statements of Exelon. This data is qualified in its entirety
by reference to and should be read in conjunction with Exelon’s Consolidated Financial Statements and ITEM 7. MANAGEMENT'S DISCUSSION AND
ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS.
(In millions, except per share data)
Statement of Operations data:
Operating revenues
Operating income
Net income
Net income attributable to common shareholders
Earnings per average common share (diluted):
Net income
Dividends per common share
(In millions)
Balance Sheet data:
Current assets
Property, plant and equipment, net
Total assets
Current liabilities
Long-term debt, including long-term debt to
financing trusts
$
$
$
$
2019
2018(a)
2017(a)
2016(b)
2015
For the Years Ended December 31,
34,438 $
35,978 $
33,558 $
31,366 $
4,374
3,028
2,936
3.01 $
1.45 $
3,891
2,079
2,005
2.07 $
1.38 $
4,388
3,869
3,779
3.98 $
1.31 $
3,212
1,196
1,121
1.21 $
1.26 $
2019
2018(a)
2017(a)
2016
2015
December 31,
12,037 $
80,233
124,977
14,185
13,328 $
76,707
119,634
11,404
11,872 $
74,202
116,746
10,798
12,451 $
71,555
114,952
13,463
31,719
34,465
32,565
32,216
29,447
4,554
2,250
2,269
2.54
1.24
15,334
57,439
95,384
9,118
24,286
Shareholders’ equity
__________
(a) Amounts have been revised to reflect the correction of an error related to Pepco's decoupling mechanism. See Note 1 — Significant Accounting Policies of the Combined
32,224
30,741
29,878
25,860
25,793
Notes to Consolidated Financial Statements for additional information.
(b) The 2016 financial results include the activity of PHI from the merger effective date of March 24, 2016 through December 31, 2016.
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Table of Contents
Generation
The selected financial data presented below has been derived from the audited consolidated financial statements of Generation. This data is qualified in its
entirety by reference to and should be read in conjunction with Generation’s Consolidated Financial Statements and ITEM 7. MANAGEMENT'S DISCUSSION
AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS.
(In millions)
Statement of Operations data:
Operating revenues
Operating income
Net income
(In millions)
Balance Sheet data:
Current assets
Property, plant and equipment, net
Total assets
Current liabilities
Long-term debt, including long-term debt to
affiliates
Member’s equity
ComEd
2019
2018
2017
2016
2015
For the Years Ended December 31,
$
18,924 $
20,437 $
18,500 $
17,757 $
1,323
1,217
975
443
947
2,798
820
550
2019
2018
2017
2016
2015
December 31,
$
7,076 $
8,433 $
6,882 $
6,567 $
24,193
48,995
7,289
4,792
13,484
23,981
47,556
5,769
7,887
13,204
24,906
48,457
4,191
8,644
13,669
25,585
47,022
5,689
8,124
11,505
19,135
2,275
1,340
6,342
25,843
46,529
4,933
8,869
11,635
The selected financial data presented below has been derived from the audited consolidated financial statements of ComEd. This data is qualified in its entirety
by reference to and should be read in conjunction with ComEd’s Consolidated Financial Statements and ITEM 7. MANAGEMENT'S DISCUSSION AND
ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS.
(In millions)
2019
2018
2017
2016
2015
For the Years Ended December 31,
Statement of Operations data:
Operating revenues
Operating income
Net income
$
5,747 $
1,171
688
5,882 $
1,146
664
5,536 $
1,323
567
5,254 $
1,205
378
4,905
1,017
426
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Table of Contents
(In millions)
Balance Sheet data:
Current assets
Property, plant and equipment, net
Total assets
Current liabilities
Long-term debt, including long-term debt to
financing trusts
Shareholders’ equity
PECO
2019
2018
2017
2016
2015
December 31,
$
1,583 $
1,570 $
1,364 $
1,554 $
23,107
32,765
2,117
8,196
10,677
22,058
31,213
1,925
8,006
10,247
20,723
29,726
2,294
6,966
9,542
19,335
28,335
2,938
6,813
8,725
1,518
17,502
26,532
2,766
6,049
8,243
The selected financial data presented below has been derived from the audited consolidated financial statements of PECO. This data is qualified in its entirety
by reference to and should be read in conjunction with PECO’s Consolidated Financial Statements and ITEM 7. MANAGEMENT'S DISCUSSION AND
ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS.
(In millions)
2019
2018
2017
2016
2015
For the Years Ended December 31,
$
$
Statement of Operations data:
Operating revenues
Operating income
Net income
(In millions)
Balance Sheet data:
Current assets
Property, plant and equipment, net
Total assets
Current liabilities
Long-term debt, including long-term debt to
financing trusts
Shareholder's equity
BGE
3,100 $
3,038 $
2,870 $
2,994 $
713
528
587
460
655
434
702
438
2019
2018
2017
2016
2015
December 31,
722 $
782 $
822 $
757 $
9,292
11,469
722
3,589
4,178
8,610
10,642
809
3,268
3,820
8,053
10,170
1,267
2,587
3,577
7,565
10,831
727
2,764
3,415
3,032
630
378
842
7,141
10,367
944
2,464
3,236
The selected financial data presented below has been derived from the audited consolidated financial statements of BGE. This data is qualified in its entirety by
reference to and should be read in conjunction with BGE’s Consolidated Financial Statements and ITEM 7. MANAGEMENT'S DISCUSSION AND ANALYSIS
OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS.
(In millions)
2019
2018
2017
2016
2015
For the Years Ended December 31,
Statement of Operations data:
Operating revenues
Operating income
Net income
$
3,106 $
3,169 $
3,176 $
3,233 $
532
360
474
313
614
307
550
294
3,135
558
288
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(In millions)
Balance Sheet data:
Current assets
Property, plant and equipment, net
Total assets
Current liabilities
Long-term debt, including long-term debt to
financing trusts
Shareholder's equity
PHI
2019
2018
2017
2016
2015
December 31,
$
833 $
786 $
811 $
842 $
8,990
10,634
753
3,270
3,683
8,243
9,716
774
2,876
3,354
7,602
9,104
760
2,577
3,141
7,040
8,704
707
2,533
2,848
845
6,597
8,295
1,134
1,732
2,687
The selected financial data presented below has been derived from the audited consolidated financial statements of PHI. This data is qualified in its entirety by
reference to and should be read in conjunction with PHI’s Consolidated Financial Statements and ITEM 7. MANAGEMENT'S DISCUSSION AND ANALYSIS OF
FINANCIAL CONDITION AND RESULTS OF OPERATIONS.
Successor
For the Years Ended
December 31,
March 24 to
December 31,
January 1 to March
23,
For the Year Ended
December 31,
Predecessor
(In millions)
2019
2018(a)
2017(a)
2016
2016
2015
Statement of Operations data:
Operating revenues
Operating income
Net income (loss) from continuing operations
Net income (loss)
(In millions)
Balance Sheet data:
Current assets
Property, plant and equipment, net
Total assets
Current liabilities
Long-term debt
Preferred Stock
$
4,806 $
4,798 $
4,672 $
3,643
$1,153 $
4,935
722
477
477
643
393
393
762
355
355
93
(61)
(61)
105
19
19
673
318
327
Successor
December 31,
Predecessor
2019
2018(a)
2017(a)
2016
2015
$
1,480 $
1,501 $
1,527 $
1,838 $
14,296
22,719
1,612
6,460
—
13,446
21,952
1,592
6,134
—
12,498
21,223
1,931
5,478
—
11,598
21,025
2,284
5,645
—
1,474
10,864
16,188
2,327
4,823
183
Member’s equity/Shareholders' equity
__________
(a) Amounts have been revised to reflect the correction of an error related to Pepco's decoupling mechanism. See Note 1 — Significant Accounting Policies of the Combined
8,016
9,608
9,259
4,413
8,807
Notes to Consolidated Financial Statements for additional information.
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Pepco
The selected financial data presented below has been derived from the audited consolidated financial statements of Pepco. This data is qualified in its entirety
by reference to and should be read in conjunction with Pepco’s Financial Statements and ITEM 7. MANAGEMENT'S DISCUSSION AND ANALYSIS OF
FINANCIAL CONDITION AND RESULTS OF OPERATIONS.
(In millions)
Statement of Operations data:
Operating revenues
Operating income
Net income
(In millions)
Balance Sheet data:
Current assets
Property, plant and equipment, net
Total assets
Current liabilities
Long-term debt
$
$
2019
2018(a)
2017(a)
2016
2015
For the Years Ended December 31,
2,260 $
2,232 $
2,151 $
2,186 $
361
243
313
205
392
198
174
42
2019
2018(a)
2017(a)
2016
2015
December 31,
696 $
728 $
686 $
684 $
6,909
8,661
657
2,862
6,460
8,267
628
2,704
6,001
7,808
550
2,521
5,571
7,335
596
2,333
2,129
385
187
726
5,162
6,908
455
2,340
Shareholder's equity
__________
(a) Amounts have been revised to reflect the correction of an error related to Pepco's decoupling mechanism. See Note 1 — Significant Accounting Policies of the Combined
2,240
2,717
2,907
2,515
2,300
Notes to Consolidated Financial Statements for additional information.
DPL
The selected financial data presented below has been derived from the audited consolidated financial statements of DPL. This data is qualified in its entirety by
reference to and should be read in conjunction with DPL’s Financial Statements and ITEM 7. MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL
CONDITION AND RESULTS OF OPERATIONS.
(In millions)
Statement of Operations data:
Operating revenues
Operating income
Net income (loss)
2019
2018
2017
2016
2015
For the Years Ended December 31,
$
1,306 $
1,332 $
1,300 $
1,277 $
217
147
190
120
229
121
50
(9)
1,302
165
76
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(In millions)
Balance Sheet data:
Current assets
Property, plant and equipment, net
Total assets
Current liabilities
Long-term debt
Shareholder's equity
ACE
2019
2018
2017
2016
2015
December 31,
$
325 $
336 $
325 $
370 $
4,035
4,830
414
1,487
1,580
3,821
4,588
375
1,403
1,509
3,579
4,357
547
1,217
1,335
3,273
4,153
381
1,221
1,326
388
3,070
3,969
564
1,061
1,237
The selected financial data presented below has been derived from the audited consolidated financial statements of ACE. This data is qualified in its entirety by
reference to and should be read in conjunction with ACE’s Financial Statements and ITEM 7. MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL
CONDITION AND RESULTS OF OPERATIONS.
(In millions)
Statement of Operations data:
Operating revenues
Operating income
Net income (loss)
(In millions)
Balance Sheet data:
Current assets
Property, plant and equipment, net
Total assets
Current liabilities
Long-term debt
Shareholder's equity
2019
2018
2017
2016
2015
For the Years Ended December 31,
$
$
1,240 $
1,236 $
1,186 $
1,257 $
151
99
149
75
157
77
7
(42)
2019
2018
2017
2016
2015
December 31,
270 $
240 $
258 $
399 $
3,190
3,933
360
1,307
1,276
2,966
3,699
422
1,170
1,126
59
2,706
3,445
619
840
1,043
2,521
3,457
320
1,120
1,034
1,295
134
40
546
2,322
3,387
297
1,153
1,000
Table of Contents
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. During the first quarter of 2019, due to a change in economics in our New England region, Generation
changed the way that information is reviewed by the CODM. The New England region is no longer regularly reviewed as a separate region by the CODM nor
presented separately in any external information presented to third parties. Information for the New England region is reviewed by the CODM as part of Other
Power Regions. 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, 2019 compared to the year ended December 31, 2018,
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, 2018 compared to the year ended December 31,
2017, refer to ITEM 7. MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS in the 2018-Form 10-
K, which was filed with the SEC on February 8, 2019.
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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, 2019 compared to the same period in 2018 and 2017. For additional information regarding the financial results for the years ended
December 31, 2019 and 2018 see the discussions of Results of Operations by Registrant.
Exelon
Generation
ComEd
PECO
BGE
PHI
Pepco
DPL
ACE
2019
2018(a)
Favorable (unfavorable)
2019 vs. 2018 variance
2017(a)
Favorable (unfavorable)
2018 vs. 2017 variance
$
2,936 $
1,125
688
528
360
477
243
147
99
2,005 $
370
664
460
313
393
205
120
75
931 $
755
3,779 $
2,710
(1,774)
(2,340)
24
68
47
84
38
27
24
567
434
307
355
198
121
77
97
26
6
38
7
(1)
(2)
Other(b)
__________
(a) Exelon’s, PHI’s and Pepco’s amounts have been revised to reflect the correction of an error related to Pepco’s decoupling mechanism. See Note 1 - Significant
(242)
(594)
(195)
(47)
399
Accounting Policies of the Combined Notes to Consolidated Financial Statements for additional information.
(b) Primarily includes eliminating and consolidating adjustments, Exelon’s corporate operations, shared service entities and other financing and investing activities.
Year Ended December 31, 2019 Compared to Year Ended December 31, 2018. Net income attributable to common shareholders increased by $931
million and diluted earnings per average common share increased to $3.01 in 2019 from $2.07 in 2018 primarily due to:
•
•
•
•
•
•
•
•
•
•
Higher net unrealized and realized gains on NDT funds;
Decreased accelerated depreciation and amortization due to the early retirement of the Oyster Creek nuclear facility in September 2018 and TMI in
September 2019 and the absence of a charge associated with the remeasurement of the Oyster Creek ARO in 2018;
Decreased Operating and maintenance expense at Generation which includes the impacts of previous cost management programs, lower pension
and OPEB costs and increased NEIL insurance distributions;
A benefit associated with the remeasurement of the TMI ARO in the first quarter of 2019 and the annual nuclear ARO update in the third quarter of
2019;
Decreased nuclear outage days;
Lower mark-to-market losses;
Regulatory rate increases at PECO, BGE, Pepco, DPL, and ACE;
Increased electric distribution, energy efficiency and transmission earnings at ComEd;
Decreased storms costs at PECO and BGE; and
Research and development income tax benefits.
The increases were partially offset by;
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•
•
•
•
Lower realized energy prices;
Lower capacity prices;
Unfavorable weather conditions at PECO, DPL and ACE; and
Unfavorable volume at PECO.
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, 2019 as compared to 2018 and 2017:
(All amounts in millions after tax)
Net Income Attributable to Common Shareholders
Mark-to-Market Impact of Economic Hedging Activities (net of
taxes of $66, $89 and $68, respectively)
Unrealized (Gains) Losses Related to NDT Fund Investments (net
of taxes of $269, $289 and $286, respectively)(b)
Amortization of Commodity Contract Intangibles (net of taxes of
$22)
PHI Merger and Integration Costs (net of taxes of $2 and $25,
respectively)
Merger Commitments (net of taxes of $137)
Asset Impairments (net of taxes of $56, $13 and $204,
respectively)(c)
Plant Retirements and Divestitures (net of taxes of $9, $181, and
$134, respectively)(d)
Cost Management Program (net of taxes of $17, $16, and $21,
respectively)(e)
Asset Retirement Obligation (net of taxes of $9, $7, and $1,
respectively)(f)
Vacation Policy Change (net of taxes of $21)
Change in Environmental Liabilities (net of taxes of $8, $0, and
$17, respectively)
Bargain Purchase Gain (net of taxes of $0)
Gain on Deconsolidation of Business (net of taxes of $83)
Gain on Contract Settlement (net of taxes of $20)(g)
Litigation Settlement Gain (net of taxes of $7)
Income Tax-Related Adjustments (entire amount represents tax
expense)(h)
Noncontrolling Interests (net of taxes of $26, $24, and $24,
respectively)(i)
Adjusted (non-GAAP) Operating Earnings
For the Years Ended December 31,
2019
2018(a)
2017(a)
Earnings per
Diluted Share
Earnings per
Diluted Share
Earnings per
Diluted Share
$
2,936 $
3.01 $
2,005 $
2.07 $
3,779 $
3.98
197
0.20
252
(299)
(0.31)
337
—
—
—
—
—
—
123
0.13
—
3
—
35
118
0.12
512
51
0.05
48
20
—
(1)
—
—
(55)
—
(0.09)
—
0.02
—
—
—
(0.02)
(84)
—
20
—
—
—
(19)
5
90
0.26
0.35
—
—
—
0.04
0.53
0.05
0.02
—
—
—
—
(0.06)
—
107
0.11
(318)
(0.34)
34
0.04
40
(137)
321
207
34
(2)
(33)
27
(233)
(130)
—
—
0.04
(0.14)
0.34
0.22
0.04
—
(0.03)
0.03
(0.25)
(0.14)
—
—
0.01
(22)
(0.02)
(1,330)
(1.41)
$
3,139 $
3.22 $
3,021 $
3.12 $
2,480 $
0.09
(113)
(0.12)
114
0.12
2.61
__________
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 2019 and 2018 ranged from 26.0 percent to 29.0
percent. 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 47.3 percent and 46.2 percent for the years ended December 31, 2019 and 2018, respectively.
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(a) Net Income Attributable to Common Shareholders and Adjusted (non-GAAP) Operating Earnings have been revised to reflect the correction of an error related to Pepco’s
decoupling mechanism. See Note 1 - Significant Accounting Policies of the Combined Notes to Consolidated Financial Statements for additional information.
(b) 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
(c)
(d)
Regulatory Agreement Units, including the associated income taxes, are contractually eliminated, resulting in no earnings impact.
In 2018, primarily reflects the impairment of certain wind projects at Generation. 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 2018, primarily reflects accelerated depreciation and amortization expenses and one-time charges associated with Generation's decision to early retire the Oyster
Creek and TMI nuclear facilities, a charge associated with a remeasurement of the Oyster Creek ARO, partially offset by a gain associated with Generation's sale of its
electrical contracting business. 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.
(e) Primarily represents severance and reorganization costs related to cost management programs.
(f)
In 2018, reflects an increase at Pepco related primarily to asbestos identified at its Buzzard Point property. In 2019, reflects a benefit related to Generation's annual
nuclear ARO update for non-regulatory units.
(g) Represents the gain on the settlement of a long-term gas supply agreement at Generation.
(h)
In 2018, reflects an adjustment to the remeasurement of deferred income taxes as a result of the TCJA. In 2019, primarily reflects the adjustment to deferred income taxes
due to changes in forecasted apportionment.
(i) Represents elimination from Generation’s results of the noncontrolling interests related to certain exclusion items. In 2018, primarily related to the impact of unrealized
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 2019 Transactions and Developments
Utility Rates and Base Rate Proceedings
The Utility Registrants file base rate cases with their regulatory commissions seeking increases or decreases to their electric transmission and distribution, and
gas distribution rates to recover their costs and earn a fair return on their investments. The outcomes of these regulatory proceedings impact the Utility
Registrants’ current and future results of operations, cash flows and financial position.
The following tables show the Utility Registrants’ completed and pending distribution base rate case proceedings in 2019. See Note 3 — Regulatory Matters of
the Combined Notes to Consolidated Financial Statements for additional information on other regulatory proceedings.
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Completed Utility Distribution Base Rate Case Proceedings
Registrant/Jurisdiction
Filing Date
Requested Revenue
Requirement Increase
(Decrease)
Approved Revenue
Requirement Increase
(Decrease)
ComEd - Illinois (Electric)
ComEd - Illinois (Electric)
PECO - Pennsylvania (Electric)
BGE - Maryland
(Natural Gas)
BGE - Maryland (Electric)
BGE - Maryland (Natural Gas)
ACE - New Jersey (Electric)
Pepco - Maryland (Electric)
April 16, 2018 $
April 8, 2019
$
March 29, 2018 $
June 8, 2018
(amended
October 12,
2018)
May 24, 2019
(amended
December 17,
2019)
May 24, 2019
(amended
December 17,
2019)
August 21, 2018
(amended
November 19,
2018)
$
$
$
$
January 15,
2019 (amended
May 16, 2019) $
Approved ROE
Approval Date
Rate Effective Date
8.69%
8.91%
December 4, 2018
January 1, 2019
December 4, 2019
January 1, 2020
N/A
December 20, 2018
January 1, 2019
9.8%
January 4, 2019
January 4, 2019
(23) $
(6) $
82 $
61
74 $
(24)
(17)
25
43
18
9.7%
December 17, 2019
December 17,
2019
December 17,
2019
59 $
45
9.75%
December 17, 2019
122 $
70
9.6%
March 13, 2019
April 1, 2019
27 $
10.3
9.6%
August 12, 2019
August 13, 2019
Pending Distribution Base Rate Case Proceedings
Registrant/Jurisdiction
Filing Date
Pepco - District of Columbia
(Electric)
May 30, 2019 (amended
September 16, 2019)
DPL - Maryland (Electric)
December 5, 2019
$
$
Requested Revenue Requirement
Increase
Requested ROE
Expected Approval Timing
160
19
10.3%
10.3%
Fourth quarter of 2020
Third quarter of 2020
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Transmission Formula Rate
The following total (decreases)/increases were included in ComEd's, BGE's, Pepco's, DPL's and ACE's 2019 annual electric transmission formula rate updates.
ComEd
BGE
Pepco
DPL
ACE
Registrant
$
Initial Revenue
Requirement
Increase/(Decrease)
Annual Reconciliation
(Decrease)/Increase
Total Revenue Requirement
Increase/(Decrease)
Allowed Return on
Rate Base
Allowed ROE
$
21
(10)
15
17
11
$
(16)
(23)
11
(1)
(2)
5
(19)
26
16
9
8.21%
7.35%
7.75%
7.14%
7.79%
11.50%
10.50%
10.50%
10.50%
10.50%
PECO Transmission Formula Rate
On May 1, 2017, PECO filed a request with FERC seeking approval to update its transmission rates and change the manner in which PECO’s transmission rate
is determined from a fixed rate to a formula rate. The formula rate will be updated annually to ensure that under this rate customers pay the actual costs of
providing transmission services. PECO’s initial formula rate filing included a requested increase of $22 million to PECO’s annual transmission revenue
requirement, which reflected a ROE of 11%, inclusive of a 50 basis point adder for being a member of a RTO. On June 27, 2017, FERC issued an Order
accepting the filing and suspending the proposed rates until December 1, 2017, subject to refund, and set the matter for hearing and settlement judge
procedures.
On December 5, 2019, FERC issued an Order accepting without modification the settlement agreement filed by PECO and other parties in July 2019. The
settlement results in an increase of approximately $14 million with a return on rate base of 7.62% compared to PECO's initial formula rate filing and allows for an
ROE of 10.35%, inclusive of a 50 basis point adder for being a member of the RTO. The settlement did not have a material impact on PECO's 2017, 2018, or
2019 annual transmission revenue requirements. PECO will update its rates in 2020 and refund estimated overcollections totaling approximately $28 million
related to the amounts billed under the proposed rates in effect since 2017.
Pursuant to the transmission formula rate request discussed above, PECO made its annual formula rate updates in May 2018 and 2019, which included a
decrease of $6 million and an increase of $8 million, respectively, to the annual transmission revenue requirement. The updated transmission formula rates were
effective on June 1, 2018 and 2019, respectively, subject to refund.
Cost Management Programs
Exelon continues to be committed to managing its costs. On October 31, 2019, Exelon announced additional annual cost savings of approximately $100 million,
at Generation, to be achieved by 2022. These actions are in response to the continuing economic challenges confronting Generation’s business, necessitating
continued focus on cost management through enhanced efficiency and productivity.
FERC Order on the PJM MOPR
On December 19, 2019, FERC issued an order directing PJM to extend the MOPR to include new and existing resources, including nuclear, that receive state
subsidies, effective as of PJM’s next capacity auction. Unless Illinois and New Jersey can implement an FRR program in their PJM zones, the MOPR will apply
to Generation's nuclear plants in those states receiving ZEC benefits, resulting in higher offers for those units that may not clear the capacity market. On January
21, 2020, Exelon, PJM and a number of other entities submitted individual requests for rehearing. Exelon is currently working with PJM and other stakeholders
to pursue the FRR option but cannot predict whether the legislative and regulatory changes can be implemented prior to the next capacity auction in PJM. If
Generation’s state-supported nuclear plants in PJM or NYISO are subjected to the MOPR without compensation under an FRR or similar program, it could have
a material adverse impact on Exelon's and Generation's financial
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statements. See Note 3 — Regulatory Matters of the Combined Notes to Consolidated Financial Statements for additional information.
Early Plant Retirements
Oyster Creek. Generation permanently ceased generation operations at Oyster Creek on September 17, 2018. On July 31, 2018, Generation entered into an
agreement with Holtec International and its wholly owned subsidiary, Oyster Creek Environmental Protection, LLC, for the sale and decommissioning of Oyster
Creek. The sale was completed on July 1, 2019. Exelon and Generation recognized a loss on the sale in the third quarter 2019, which was immaterial. See
Note 2 — Mergers, Acquisitions and Dispositions of the Combined Notes to Consolidated Financial Statements for additional information.
Three Mile Island. Generation permanently ceased operations at TMI on September 20, 2019. As a result of the decision to early retire TMI, Exelon and
Generation recorded a $176 million incremental pre-tax net charge for the year ended December 31, 2019 primarily due to accelerated depreciation of the plant
assets, partially offset by a benefit associated with the remeasurement of the TMI ARO in the first quarter of 2019.
Salem. In 2017, PSEG announced that its New Jersey nuclear plants, including Salem, of which Generation owns a 42.59% ownership interest, were showing
increased signs of economic distress, which could lead to an early retirement. PSEG is the operator of Salem and also has the decision-making authority to
retire Salem. In 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. On April 18, 2019, the NJBPU approved the award of ZECs to Salem Unit 1 and Salem Unit 2. Assuming the continued effectiveness
of the New Jersey ZEC program, Generation no longer considers Salem to be at heightened risk for early retirement.
Dresden, Byron and Braidwood. Generation’s Dresden, Byron and Braidwood nuclear plants in Illinois are also showing increased signs of economic distress,
which could lead to an early retirement, in a market that does not currently compensate them for their unique contribution to grid resiliency and their ability to
produce large amounts of energy without carbon and air pollution. The May 2018 PJM capacity auction for the 2021-2022 planning year resulted in the largest
volume of nuclear capacity ever not selected in the auction, including all of Dresden, and portions of Byron and Braidwood. Exelon continues to work with
stakeholders on state policy solutions, while also advocating for broader market reforms at the regional and federal level.
See Note 3 — Regulatory Matters, Note 6 — Early Plant Retirements and Note 9 — Asset Retirement Obligations of the Combined Notes to Consolidated
Financial Statements for additional information.
CENG Put Option
On November 20, 2019, Generation received notice of EDF’s intention to exercise the put option and sell its 49.99% equity 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, the purchase price is
to be determined by agreement of the parties, or absent such agreement, by a third-party arbitration process. Any resulting sale would be subject to the approval
of the NYPSC, the FERC and the NRC. The process and regulatory approvals could take one to two years or more to complete. See Note 2 - Mergers,
Acquisitions and Dispositions for additional information.
Conowingo Hydroelectric Project
In connection with Generation’s pursuit of a new FERC license for Conowingo, on October 29, 2019, Generation and MDE filed with FERC a Joint Offer of
Settlement that would resolve all outstanding issues between the parties, effective upon and subject to FERC’s approval and incorporation of the terms into the
new license when issued. The financial impact of this settlement, along with other anticipated and prior license commitments, would be recognized over the term
of the new 50-year license and is estimated to be, on average, $11 million to $14 million per year, including capital and operating costs. The actual timing and
amount of a 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. See Note 3 — Regulatory Matters of the Combined Notes to Consolidated Financial Statements for additional
information.
Pacific Gas & Electric Bankruptcy
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Generation’s Antelope Valley, a 242 MW solar facility in Lancaster, CA, 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. As of December 31, 2019, Generation had approximately $725 million and $485 million of net long-
lived assets and nonrecourse debt outstanding, respectively, related to Antelope Valley. PG&E’s bankruptcy created an event of default for Antelope Valley’s
nonrecourse debt that provides 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 ongoing event of default and 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 and continues to be classified as current as of December 31,
2019.
In the first quarter of 2019, Generation assessed and determined that Antelope Valley’s long-lived assets were not impaired. Significant changes in assumptions
such as the likelihood of the PPA being rejected as part of the bankruptcy proceedings could potentially result in future impairments of Antelope Valley's net
long-lived assets, which could be material. Generation is monitoring the bankruptcy proceedings for any changes in circumstances that would indicate the
carrying amount of the net long-lived assets of Antelope Valley may not be recoverable.
See Note 11 — Asset Impairments and Note 16 — Debt and Credit Agreements of the Combined Notes to Consolidated Financial Statements for additional
information on the PG&E bankruptcy.
Exelon’s Strategy and Outlook for 2020 and Beyond
Exelon’s value proposition and competitive advantage come from its scope and its core strengths of operational excellence and financial discipline. Exelon
leverages its integrated business model to create value. Exelon’s regulated and competitive businesses feature a mix of attributes that, when combined, offer
shareholders and customers a unique value proposition:
•
•
The Utility Registrants provide a foundation for steadily growing earnings, which translates to a stable currency in our stock.
Generation’s competitive businesses provide free cash flow to invest primarily in the utilities and to reduce debt.
Exelon believes its strategy provides a platform for optimal success in an energy industry experiencing fundamental and sweeping change.
Exelon’s utility strategy is to improve reliability and operations and enhance the customer experience, while ensuring 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 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 generation to load matching to reduce earnings volatility. Generation
leverages its energy generation portfolio to deliver energy to both wholesale and retail customers. Generation’s customer-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.
Exelon’s financial priorities are to maintain investment grade credit metrics at each of the Registrants, to maintain optimal capital structure and to return value to
Exelon’s shareholders with an attractive dividend throughout the energy commodity market cycle and through stable earnings growth.
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As part of its strategic business planning process, Exelon routinely reviews its hedging policy, dividend policy, operating and capital costs, capital spending
plans, strength of its balance sheet and credit metrics, and sufficiency of its liquidity position, by performing various stress tests with differing variables, such as
commodity price movements, increases in margin-related transactions, changes in hedging practices, and the impacts of hypothetical credit downgrades.
Exelon’s Board of Directors approved a dividend policy providing a raise of 5% each year for the period covering 2018 through 2020, beginning with the March
2018 dividend.
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.
Exelon continues to be committed to managing its costs. In November 2017, Exelon announced a commitment for $250 million of cost savings, primarily at
Generation, to be achieved by 2020. In November 2018, Exelon announced the elimination of an approximately additional $200 million of annual ongoing costs,
through initiatives primarily at Generation and BSC, by 2021. Approximately $150 million is expected to be related to Generation, with the remaining amount
related to the Utility Registrants. In October 2019, Exelon announced additional annual cost savings of approximately $100 million, at Generation, to be achieved
by 2022. These actions are in response to the continuing economic challenges confronting Generation's business, necessitating continued focus on cost
management through enhanced efficiency and productivity.
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 $26 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 $13 billion by the end of 2023. 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.
See Note 3 — Regulatory Matters of the Combined Notes to Consolidated Financial Statements for additional information on the Smart Meter and Smart Grid
Investments and infrastructure development and enhancement programs.
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 long-term growth strategy is to ensure appropriate valuation of its generation
assets, in part through public policy efforts, identify and capitalize on opportunities that provide generation to load matching 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.
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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 over the last several years; in part reflecting an increase in supply due to strong natural gas production (due to shale gas development).
FERC Inquiry on Resiliency
On August 23, 2017, the DOE staff released its report on the reliability of the electric grid. One aspect of the wide-ranging report is the DOE’s recognition that
the electricity markets do not currently value the resiliency provided by base-load generation, such as nuclear plants. On September 28, 2017, the DOE issued a
Notice of Proposed Rulemaking (NOPR) that would entitle certain eligible resilient generating units (i.e., those located in organized markets, with a 90-day
supply of fuel on site, not already subject to state cost of service regulation and satisfying certain other requirements) to recover fully allocated costs and earn a
fair return on equity on their investment. On January 8, 2018, FERC issued an order terminating the rulemaking docket that it initiated to address the proposed
rule in the DOE NOPR, concluding the proposed rule did not sufficiently demonstrate there is a resiliency issue and that it proposed a remedy that did not
appear to be just, reasonable and nondiscriminatory as required under the Federal Power Act. At the same time, FERC initiated a new proceeding to consider
resiliency challenges to the bulk power system and evaluate whether additional FERC action to address resiliency would be appropriate. FERC directed each
RTO and ISO to respond within 60 days to 24 specific questions about how they assess and mitigate threats to resiliency. Thereafter, interested parties
submitted reply comments on May 9, 2018, and a few parties submitted further replies. Exelon has been and will continue to be an active participant in these
proceedings but cannot predict the final outcome or its potential financial impact, if any, on Exelon or Generation.
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, as amended, (the Act) from imports of uranium products, alleging that
these imports threaten national security (the Petition). The relief requested would have required U.S. nuclear reactors to purchase at least 25% of their uranium
needs from domestic mines for the next 10 years or more. The Act was promulgated by Congress to protect essential national security industries whose survival
is threatened by imports. As such, the Act authorizes the Secretary of Commerce (the Secretary) to conduct investigations to evaluate the effects of imports of
any item on the national security of the U.S. The Petition alleges that the loss of a viable U.S. uranium mining industry would have a significant detrimental
impact on the national, energy, and economic security of the U.S. and the ability of the country to sustain an independent nuclear fuel cycle.
On July 18, 2018, the Secretary announced that the DOC had initiated an investigation in response to the petition. The Secretary submitted a report to President
Trump on April 14, 2019 that has not been made public. On July 12, 2019, the President issued a memorandum indicating that he did not agree with the
Secretary's finding that uranium imports threaten to impair the national security of the United States, choosing not to impose any trade restrictions at this
time.The President found that a fuller analysis of national security considerations with respect to the entire nuclear fuel supply chain is necessary and directed
that a United States Nuclear Fuel Working Group (Working Group) be established to develop recommendations for reviving and expanding domestic nuclear fuel
production. The Working Group report has not yet been issued and is not expected to be made public. The Working Group is co-chaired by the Assistant to the
President for National Security Affairs and the Assistant to the President for Economic Policy. Exelon will monitor and volunteer to provide information to support
the Working Group's efforts. Exelon and Generation cannot currently predict the outcome of the Working Group report and subsequent actions.
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
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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
Modest economic growth partially offset by energy efficiency initiatives is resulting in relatively flat load growth in electricity for the Utility Registrants. ComEd,
PECO, BGE, Pepco, DPL and ACE are projecting load volumes to increase (decrease) by (0.3)%, (0.7)%, (1.2)%, (0.4)%, (0.5)% and (0.4)%, respectively, in
2020 compared to 2019.
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, 2019, the percentage of expected generation hedged for the Mid-Atlantic,
Midwest, New York and ERCOT reportable segments is 91%-94% and 61%-64% for 2020 and 2021, respectively. Generation has been and will continue to be
proactive in using hedging strategies to mitigate commodity price risk.
Generation procures natural gas through long-term and short-term contracts and spot-market purchases. Nuclear fuel assemblies are obtained predominantly
through long-term uranium concentrate supply contracts, contracted conversion services, contracted enrichment services, or a combination thereof, and
contracted fuel fabrication services. The supply markets for uranium concentrates and certain nuclear fuel services are subject to price fluctuations and
availability restrictions. Approximately 60% of Generation’s uranium concentrate requirements from 2020 through 2024 are supplied by three suppliers. In the
event of non-performance by these or other suppliers, Generation believes that replacement uranium concentrate can be obtained, although at prices that may
be unfavorable when compared to the prices under the current supply agreements. Non-performance by these counterparties could have a material adverse
impact on Exelon’s and Generation’s results of operations, cash flows and financial positions.
See Note 15 — Derivative Financial Instruments of the Combined Notes to Consolidated Financial Statements and
QUALITATIVE DISCLOSURES ABOUT MARKET RISK for additional information.
ITEM 7A. QUANTITATIVE AND
The Utility Registrants mitigate commodity price risk through regulatory mechanisms that allow them to recover procurement costs from retail customers.
Environmental Legislative and Regulatory Developments
Exelon was actively involved in the Obama Administration’s development and implementation of environmental regulations for the electric industry, in pursuit of
its business strategy to provide reliable, clean, affordable and innovative energy products. These efforts have most frequently involved air, water and waste
controls for fossil-fueled electric generating units, as set forth in the discussion below. These regulations have had a disproportionate adverse impact on coal-
fired power plants, requiring significant expenditures of capital and variable operating and maintenance expense, and have resulted in the retirement of older,
marginal facilities. Due to its low emission generation portfolio, Generation has not been significantly affected by these regulations, representing a competitive
advantage relative to electric generators that are more reliant on fossil fuel plants.
Through the issuance of a series of Executive Orders (EO), President Trump has initiated review of a number of EPA and other regulations issued during the
Obama Administration, with the expectation that the Administration will seek repeal or significant revision of these rules. Under these EOs, each executive
agency is required to evaluate existing regulations and make recommendations regarding repeal, replacement, or modification. The
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Administration’s actions are intended to result in less stringent compliance requirements under air, water, and waste regulations. The exact nature, extent, and
timing of the regulatory changes are unknown, as well as the ultimate impact on Exelon’s and its subsidiaries results of operations and cash flows.
In particular, the Administration has targeted existing EPA regulations for repeal, including notably the Clean Power Plan, as well as revoking many Executive
Orders, reports, and guidance issued by the Obama Administration on the topic of climate change or the regulation of greenhouse gases. The Executive Order
also disbanded the Interagency Working Group that developed the social cost of carbon used in rulemakings, and withdrew all technical support documents
supporting the calculation. Other regulations that have been specifically identified for review are the Clean Water Act rule relating to jurisdictional waters of the
U.S., the Steam Electric Effluent Guidelines relating to waste water discharges from coal-fired power plants, and the 2015 National Ambient Air Quality Standard
(NAAQS) for ozone. The review of final rules could extend over several years as formal notice and comment rulemaking process proceeds.
Air Quality
Mercury and Air Toxics Standard Rule (MATS). On December 16, 2011, the EPA signed a final rule to reduce emissions of toxic air pollutants from power
plants and signed revisions to the NSPS for electric generating units. The final rule, known as MATS, requires coal-fired electric generation 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. Numerous entities challenged MATS in the D.C. Circuit Court, and Exelon intervened in support of the rule. In April 2014, the D.C. Circuit Court
issued an opinion upholding MATS in its entirety. On appeal, the U.S. Supreme Court decided in June 2015 that the EPA unreasonably refused to consider
costs in determining whether it is appropriate and necessary to regulate hazardous air pollutants emitted by electric utilities, but did not vacate the rule. On April
27, 2017, the D.C. Circuit Court granted EPA’s motion to hold the litigation in abeyance, pending EPA’s review of the MATS rule pursuant to President Trump’s
EO discussed above. Notwithstanding the Court’s order to hold the litigation in abeyance, the MATS rule remains in effect. Exelon will continue to participate in
the remanded proceedings before the D.C. Circuit Court as an intervenor in support of the rule. On December 28, 2018, the EPA proposed to revoke the
"appropriate and necessary" finding underpinning the MATS rule. While the proposal would leave in place the rule, it would leave it vulnerable to future legal
challenge. On February 7, 2019, EPA published its Reconsideration of Supplemental Finding and Residual Risk and Technology Review. After considering
public comment, EPA transmitted a final version to the Office of Management and Budget for review prior to publication.
Clean Power Plan. On April 28, 2017, the D.C. Circuit Court issued orders in separate litigation related to the EPA’s actions under the Clean Power Plan (CPP)
to amend Clean Air Act Section 111(d) regulation of existing fossil-fired electric generating units and Section 111(b) regulation of new fossil-fired electric
generating units. In both cases, the Court has determined to hold the litigation in abeyance pending a determination whether the rule should be remanded to the
EPA. In June 2019, EPA issued a final rule that repealed the CPP, and finalized the Affordable Clean Energy rule to replace the CPP with less stringent
emissions guidelines based on heat rate improvement measures that could be achieved within the fence line of existing power plants. The Affordable Clean
Energy rule is currently being litigated.
2015 Ozone National Ambient Air Quality Standards (NAAQS). On April 11, 2017, the D.C. Circuit Court ordered that the consolidated 2015 ozone NAAQS
litigation be held in abeyance pending EPA’s further review of the 2015 Rule. On August 23, 2019, the D.C. Circuit Court upheld the stringency of NAAQS, but
remanded certain aspects of its secondary standard to EPA for revision.
Primary SO2 National Ambient Air Quality Standards (NAAQS). EPA took final action on April 17, 2019 to retain the current primary SO2 standard without
revision, leaving the standard established in 2010 in effect.
Climate Change. Exelon supports comprehensive climate change legislation or regulation, including a cap-and-trade program for GHG emissions, which
balances the need to protect consumers, business and the economy with the urgent need to reduce national GHG emissions. In the absence of Federal
legislation, the EPA is moving forward with the regulation of GHG emissions under the Clean Air Act. In addition, there have been recent developments in the
international regulation of GHG emissions pursuant to the United Nations Framework Convention on Climate Change (“UNFCCC” or “Convention”). See ITEM 1.
BUSINESS, "Global Climate Change" for additional information.
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Water Quality
Section 316(b) requires that the cooling water intake structures at electric power plants reflect the best technology available to minimize adverse environmental
impacts and is implemented through state-level NPDES permit programs. All of Generation’s power generation facilities with cooling water systems are subject
to the regulations. Facilities without closed-cycle recirculating systems (e.g., cooling towers) are potentially most affected by recent changes to the regulations.
For Generation, those facilities are Calvert Cliffs, Clinton, Dresden, Eddystone, Fairless Hills, FitzPatrick, Ginna, Gould Street, Handley, Mystic 7, Nine Mile Point
Unit 1, Peach Bottom, Quad Cities, and Salem. See ITEM 1. BUSINESS, "Water Quality" for additional information.
Clean Water Rule
In 2015, the EPA and the US Army Corps of Engineers, finalized the Clean Water Rule that significantly expanded the definition of the Waters of the United
States under the Clean Water Act and resulted in increased environmental costs for some projects. On October 22, 2019, the EPA and the US Army Corps of
Engineers repealed the 2015 Clean Water Rule and restored the definition of the Waters of the United States that existed prior to this rule. On January 23, 2020,
a new final rule was issued by the EPA and the US Army Corps of Engineers to streamline and clarify the definition of Waters of the United States and will be
effective sixty days after publication in the Federal Register. This rule represents final action by these government agencies to narrow the scope of Waters of the
United States that are regulated under the federal Clean Water Act.
Solid and Hazardous Waste
In October 2015, the first federal regulation for the disposal of coal combustion residuals (CCR) from power plants became effective. The rule classifies CCR as
non-hazardous waste under RCRA. Under the regulation, CCR will continue to be regulated by most states subject to coordination with the federal regulations.
Generation has previously recorded accruals consistent with state regulation for its owned coal ash sites, and as such, the regulation is not expected to impact
Exelon’s and Generation’s financial results. Generation does not have sufficient information to reasonably assess the potential likelihood or magnitude of any
remediation requirements that may be asserted under the new federal regulations for coal ash disposal sites formerly owned by Generation. For these reasons,
Generation is unable to predict whether and to what extent it may ultimately be held responsible for remediation and other costs relating to formerly owned coal
ash disposal sites under the new regulations.
See Note 18 — Commitments and Contingencies of the Combined Notes to Consolidated Financial Statements for additional information related to
environmental matters.
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 fixed resource requirement 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, including renewable resource developers, environmental advocates, and
coal-fueled generators. 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
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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 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 $10.5 billion at December 31, 2019. 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
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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 nuclear decommissioning trust 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 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. The successful operation of nuclear plants in the U.S. beyond the initial 40-year license terms has
prompted the NRC to consider regulatory and technical requirements for potential plant operations for an 80-year nuclear operating term. As power market and
regulatory environment developments occur, Generation evaluates and incorporates, as necessary, the impacts of such developments into its nuclear ARO
assumptions and estimates.
Generation’s probabilistic cash flow models also include an assessment of the timing of DOE acceptance of SNF for disposal. Generation currently assumes
DOE will begin accepting SNF in 2030. 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 that DOE will
begin accepting SNF, see Note 18 — 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 $10.5 billion to approximately $13.2 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
2018 CARFR rather than the 2019 CARFR
2019 CARFR increased by 50 basis points
2019 CARFR decreased by 50 basis points
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Increase (Decrease) to ARO at
December 31, 2019
$
(820)
(390)
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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
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(a)
Shorten each unit's probability weighted operating life assumption by 10 percent(b)
Extend the estimated date for DOE acceptance of SNF to 2035
__________
(a)
(b)
Excludes any sites in which management has committed to a specific decommissioning approach.
Excludes any retired sites.
Increase to ARO at
December 31, 2019
$
2,250
910
550
1,570
350
See Note 1 — Significant Accounting Policies, Note 6 — Early Plant Retirements and Note 9 — 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, 2019, Exelon’s $6.7 billion carrying amount of goodwill consists of $2.6 billion at ComEd, $4 billion at PHI and immaterial amounts at
Generation and DPL. 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 tested 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 12 — 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 test 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. In applying the second step, if needed, management must
estimate the fair value of specific assets and liabilities of the reporting unit.
While the 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.
Based on the results of the
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last annual quantitative goodwill tests performed as of November 1, 2016 and November 1, 2018 for ComEd and PHI, respectively, the estimated fair values of
the ComEd, Pepco, DPL and ACE reporting units would have needed to decrease by more than 30%, 30%, 20% and 30%, respectively, for ComEd and PHI to
fail the first step of their respective impairment tests.
See Note 1 — Significant Accounting Policies and Note 12 — Intangible Assets of the Combined Notes to Consolidated Financial Statements for additional
information.
Purchase Accounting (Exelon, Generation and PHI)
Assets acquired and liabilities assumed in an acquired business are recorded at their estimated fair values on the date of acquisition. The difference between the
purchase price amount and the net fair value of assets acquired and liabilities assumed is recognized as goodwill on the balance sheet if the purchase price
exceeds the estimated net fair value or as a bargain purchase gain on the income statement if the purchase price is less than the estimated net fair
value. Determining the fair value of assets acquired and liabilities assumed requires management’s judgment, often utilizes independent valuation experts and
involves the use of significant estimates and assumptions with respect to the timing and amounts of future cash inflows and outflows, discount rates, market
prices and asset lives, among other items. The judgments made in the determination of the estimated fair value assigned to the assets acquired and liabilities
assumed, as well as the estimated useful life of each asset and the duration of each liability, could significantly impact the financial statements in periods after
acquisition, such as through depreciation and amortization expense. The allocation of the purchase price may be modified up to one year after the acquisition
date as more information is obtained about the fair value of assets acquired and liabilities assumed. If the transaction is determined to be an asset acquisition
the purchase price is allocated to the assets acquired and the liabilities assumed and no goodwill or bargain purchase gain would be recorded. See Note 2 —
Mergers, Acquisitions and Dispositions 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 has 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, Note 2 — Mergers, Acquisitions and Dispositions and Note 12 — 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 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
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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 and there will usually be differences between prospective financial information and
actual results, and those differences 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 11 — 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 includes 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.
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. See Note 6 — 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.
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Defined Benefit Pension and Other Postretirement Employee Benefits (All Registrants)
Exelon sponsors defined benefit pension plans and other postretirement employee benefit 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 applied to benefit obligations, the long-term expected rate of return on plan
assets, the anticipated rate of increase of health care costs, Exelon’s expected level of contributions to the plans, the incidence of participant mortality, the
expected remaining service period of plan participants, the level of compensation and rate of compensation increases, employee age, length of service, 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. Exelon amortizes actuarial gains or losses in excess of a corridor of 10% of the greater of the projected benefit obligation
or the market-related value (MRV) of plan assets over the expected average remaining service period of plan participants.
Pension and other postretirement benefit 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 other postretirement benefit 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 other postretirement benefit plan assets and certain pension plan assets, Exelon uses fair value to calculate
the MRV.
Discount Rate. At December 31, 2019 and 2018, the discount rates were 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 other postretirement
benefit obligations. The spot rates are used to discount the estimated future benefit distribution amounts under the pension and other postretirement benefit
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 is supported by an actuarial experience
study of Exelon's plan participants and beginning in 2019, utilizes the Society of Actuaries' 2019 base table (Pri-2012) and MP-2019 improvement scale adjusted
to a 0.75% long-term rate reached in 2035.
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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 2019 cost:
Discount rate (a)
EROA
Change in benefit obligation at December 31, 2019:
Discount rate (a)
Actual Assumption
Pension
OPEB
Change in
Assumption
Pension
OPEB
Total
4.31%
4.31%
7.00%
7.00%
3.34%
3.34%
4.30%
4.30%
6.67%
6.67%
3.31%
3.31%
0.5%
(0.5)%
0.5%
(0.5)%
0.5%
(0.5)%
$
(47) $
(14) $
47
(88)
88
(1,244)
1,316
13
(11)
11
(247)
261
(61)
60
(99)
99
(1,491)
1,577
__________
(a)
In general, the discount rate will have a larger impact on the pension and other postretirement benefit cost and obligation as the rate moves closer to 0%. Therefore, the
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 14 — Retirement Benefits of the Combined Notes to Consolidated Financial Statements for additional information regarding the accounting for the
defined benefit pension plans and other postretirement benefit 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 would be recognized in the Consolidated Statements of Operations and Comprehensive Income and
could be material.
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 other postretirement benefit plans that are recorded as regulatory assets in
Exelon's Consolidated Balance Sheets:
December 31, 2019
Gain (loss)
Exelon
ComEd
PECO
BGE
PHI
Pepco
DPL
ACE
$
887 $
4,981 $
6 $
591 $
(696) $
(18) $
337 $
(43)
$
Charge against OCI(a)
___________
(a) Exelon's charge against OCI (before taxes) consists of up to $2.3 billion, $176 million, $176 million, $396 million, $191 million and $86 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 other postretirement benefit plans. Exelon also has a net
regulatory liability of $(44) million (before taxes) related to PECO’s portion of the deferred costs associated with Exelon’s other postretirement benefit plans that would
result in an increase in OCI if reversed.
—
3,864 $
— $
— $
— $
— $
— $
— $
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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 settlement at each balance sheet date and when regulatory events occur. This assessment includes
consideration of recent rate orders, historical regulatory treatment for similar costs in 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 15 — 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 to 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.
Normal Purchases and Normal Sales Exception. 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.
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
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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 17 — Fair Value of Financial Assets and Liabilities and
Note 15 — 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 13 — Income Taxes of the Combined Notes to Consolidated Financial Statements for additional information.
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
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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 18 — 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.
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 Alternative Revenue Program (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 independent
system operators.
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
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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 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, 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. 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 Uncollectible Accounts (Utility Registrants)
Utility Registrants estimate the allowance for uncollectible accounts on customer receivables by applying loss rates developed specifically for each company to
the outstanding receivable balance by customer risk segment. Risk segments represent a group of customers with similar credit quality indicators that are
comprised based on various attributes, including delinquency of their balances and payment history. 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 uncollectible accounts 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.
Results of Operations by Registrant
The Registrants' 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. For the Utility Registrants, their Operating revenues reflect the full and current
recovery of commodity procurement costs given the rider mechanisms approved by their respective state regulators. The commodity procurement costs, which
are recorded in Purchased power and fuel expense, and the associated revenues can be volatile. Therefore, the Utility Registrants believe that RNF is a useful
measure because it excludes the effect on Operating revenues caused by the volatility in these expenses.
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Results of Operations—Generation
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 (loss) on sales of assets and businesses
Bargain purchase gain
Gain on deconsolidation of business
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 income attributable to noncontrolling interests
Net income attributable to membership interest
Favorable
(unfavorable) 2019 vs.
2018 variance
Favorable
(unfavorable) 2018 vs.
2017 variance
2019
18,924 $
$
2018
20,437 $
(1,513) $
2017
18,500 $
10,856
11,693
837
9,690
8,068
8,744
(676)
8,810
4,718
1,535
519
6,772
27
—
—
1,323
(429)
1,023
594
1,917
516
(184)
1,217
92
5,464
1,797
556
7,817
48
—
—
975
(432)
(178)
(610)
365
(108)
(30)
443
73
746
262
37
1,045
(21)
—
—
348
3
1,201
1,204
1,552
(624)
(154)
774
(19)
6,299
1,457
555
8,311
2
233
213
947
(440)
948
508
1,455
(1,376)
(33)
2,798
88
$
1,125
$
370
$
755 $
2,710 $
Generation
1,937
(2,003)
(66)
835
(340)
(1)
494
46
(233)
(213)
28
8
(1,126)
(1,118)
(1,090)
(1,268)
3
(2,355)
(15)
(2,340)
Year Ended December 31, 2019 Compared to Year Ended December 31, 2018. Net income attributable to membership interest increased by $755 million
primarily due to:
•
•
•
•
•
•
•
Higher net unrealized and realized gains on NDT funds;
Decreased accelerated depreciation and amortization due to the early retirement of the Oyster Creek nuclear facility in September 2018 and TMI in
September 2019 and the absence of a charge associated with the remeasurement of the Oyster Creek ARO;
Decreased operating and maintenance expense at Generation which includes the impacts of previous cost management programs and lower
pension and OPEB costs, and increased NEIL insurance distributions;
A benefit associated with the remeasurement of the TMI ARO in the first quarter of 2019 and the annual nuclear ARO update in the third quarter of
2019;
Decreased nuclear outage days;
Lower mark-to-market losses;
Research and development income tax credits.
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The increases were partially offset by;
•
•
Lower realized energy prices; and
Lower capacity prices.
Generation
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.
During the first quarter of 2019, due to a change in economics in our New England region, Generation changed the way that information is reviewed by the
CODM. The New England region will no longer be regularly reviewed as a separate region by the CODM nor will it be presented separately in any external
information presented to third parties. Information for the New England region will be reviewed by the CODM as part of 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 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, 2019 compared to 2018, RNF by region were as follows:
2019
2018
Variance
% Change
2019 vs. 2018
Mid-Atlantic(a)
Midwest(b)
New York
ERCOT
Other Power Regions
Total electric revenues net of purchased power and fuel expense
Mark-to-market losses
Other
$
2,655 $
3,073 $
2,962
1,094
308
620
7,639
(215)
644
3,135
1,122
258
729
8,317
(319)
746
Total revenue net of purchased power and fuel expense
$
8,068
$
8,744
$
_________
(a)
(b)
Includes results of transactions with PECO, BGE, Pepco, DPL and ACE.
Includes results of transactions with ComEd.
(418)
(173)
(28)
50
(109)
(678)
104
(102)
(676)
(13.6)%
(5.5)%
(2.5)%
19.4 %
(15.0)%
(8.2)%
(32.6)%
(13.7)%
(7.7)%
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Generation’s supply sources by region are summarized below:
Supply Source (GWhs)
Nuclear Generation(a)
Mid-Atlantic
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
Mid-Atlantic(b)
Midwest(b)
New York
ERCOT
Other Power Regions
Total Supply/Sales by Region
Generation
2019
2018
Variance
% Change
2019 vs. 2018
58,347
94,890
28,088
64,099
94,283
26,640
181,325
185,022
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
3,670
1,373
3
11,180
13,256
29,482
6,506
996
6,550
44,998
59,050
74,275
96,652
26,643
17,730
58,254
280,344
273,554
(5,752)
607
1,448
(3,697)
(786)
1
2
2,392
(1,780)
(171)
8,284
428
(1,729)
3,675
10,658
1,746
1,036
1,450
663
1,895
6,790
(9.0)%
0.6 %
5.4 %
(2.0)%
(21.4)%
0.1 %
66.7 %
21.4 %
(13.4)%
(0.6)%
127.3 %
43.0 %
(26.4)%
8.2 %
18.0 %
2.4 %
1.1 %
5.4 %
3.7 %
3.3 %
2.5 %
__________
(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)
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Generation
For the years ended December 31, 2019 compared to 2018 changes in RNF by region were as follows:
Mid-Atlantic
Midwest
New York
ERCOT
Other Power Regions
Mark-to-market(a)
Other
Total
(Decrease)/Increase
$
(418)
(173)
(28)
2019 vs. 2018
Description
• decreased revenue due to the permanent cease of generation operations at
Oyster Creek in the third quarter of 2018 and Three Mile Island in the third
quarter of 2019
• lower realized energy prices
• decreased capacity prices, partially offset by
• increased ZEC revenues due to the approval of the NJ ZEC program in the
second quarter of 2019
• the absence of the revenue recognized in the first quarter of 2018 related to
ZECs generated in Illinois from June through December 2017
• decreased capacity prices
• lower realized energy prices
• decreased capacity prices, partially offset by
• increased ZEC revenues due to higher ZEC prices and increased nuclear
output
• decreased nuclear outage days
50
• higher realized energy prices
(109)
104
(102)
• decreased capacity prices
• lower realized energy prices
• losses on economic hedging activities of $215 million in 2019 compared to
losses of $319 million in 2018
• the absence of the gain on the settlement of a long-term gas supply
agreement
• congestion activity, partially offset by
• decrease in accelerated nuclear fuel amortization associated with announced
early plant retirements
$
(676)
_________
(a) See Note 15 — Derivative Financial Instruments for additional information on mark-to-market losses.
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
88
2019
2018
95.7%
209
51
94.6%
274
38
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The changes in Operating and maintenance expense, consisted of the following:
Labor, other benefits, contracting, materials(a)
Nuclear refueling outage costs, including the co-owned Salem plants
Corporate allocations
Insurance(b)
Merger and integration costs
Plant retirements and divestitures(c)
Change in environmental liabilities
ARO update(d)
Asset Impairments(e)
Pension and non-pension postretirement benefits expense
Allowance for uncollectible accounts
Accretion expense
Other(f)
Decrease in operating and maintenance expense
Generation
(Decrease) Increase
2019 vs. 2018
(174)
(87)
(82)
(47)
(4)
(175)
7
(70)
(32)
(62)
(14)
(77)
71
(746)
$
$
__________
(a) Primarily reflects decreased costs related to the permanent cease of generation operations at Oyster Creek, lower labor costs resulting from previous cost management
programs, and lower pension and OPEB costs.
(b) Primarily reflects a supplemental NEIL insurance distribution received in the fourth quarter of 2019.
(c) Primarily due to the benefit recorded in the first quarter of 2019 for the remeasurement of the TMI ARO and the absence of a charge associated with the remeasurement
of the Oyster Creek ARO in the third quarter of 2018.
(d) Primarily reflects a benefit related to Generation's annual nuclear ARO update for non-regulatory units.
(e) Primarily due to the impairment of certain wind projects recorded in the second quarter of 2018.
(f) Primarily due to the increased revenue as a result of a research and development tax refund.
Depreciation and amortization expense for the year ended December 31, 2019 compared to the year ended December 31, 2018 decreased primarily due to
the permanent cessation of generation operations at Oyster Creek in the third quarter of 2018 and TMI in the fourth quarter of 2019.
Gain (loss) on sales of assets and businesses for the year ended December 31, 2019 compared to the year ended December 31, 2018 decreased primarily
due to Generation's sale of Oyster Creek.
Other, net for the year ended December 31, 2019 compared to the same period in 2018 increased for the twelve months ended December 31, 2019 compared
to the same period in 2018 due to activity associated with NDT funds as described in the table below.
Net unrealized gains (losses) on NDT funds(a)
Net realized gains on sale of NDT funds(a)
Interest and dividend income on NDT funds(a)
Contractual elimination of income tax expense(b)
Other
Total other, net
2019
2018
$
$
411 $
253
110
216
33
1,023 $
(483)
180
122
(38)
41
(178)
_________
(a) Unrealized gains (losses), realized gains and interest and dividend income on the NDT funds are associated with the Non-Regulatory Agreement units.
(b) Contractual elimination of income tax expense is associated with the income taxes on the NDT funds of the Regulatory Agreement units.
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Generation
Effective income tax rates were 26.9% and (29.5)% for the years ended December 31, 2019 and 2018, respectively. The change in 2019 is primarily related to
research and development claims, renewable tax credits and one-time adjustments. See Note 13 — Income Taxes of the Combined Notes to Consolidated
Financial Statements for additional information.
Equity in losses of unconsolidated affiliates for the twelve months ended December 31, 2019 compared to the same period in 2018 decreased primarily due
to the impairment of equity method investments in certain distributed energy companies.
Net income attributable to noncontrolling interests for the twelve months ended December 31, 2019 compared to the same period in 2018 decreased
primarily due to the offsetting noncontrolling interest impact of the impairment of equity method investments in certain distributed energy companies.
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Results of Operations—ComEd
Operating revenues
Purchased power expense
Revenues net of purchased power expense
Other operating expenses
Operating and maintenance
Depreciation and amortization
Taxes other than income taxes
Total other 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
ComEd
2019
2018
Favorable (unfavorable)
2019 vs. 2018 variance
2017
Favorable (unfavorable)
2018 vs. 2017 variance
$
5,747 $
5,882 $
(135)
$
5,536 $
1,941
3,806
1,305
1,033
301
2,639
4
1,171
(359)
39
(320)
851
163
2,155
3,727
1,335
940
311
2,586
5
1,146
(347)
33
(314)
832
168
214
79
30
(93)
10
(53)
(1)
25
(12)
6
(6)
19
5
1,641
3,895
1,427
850
296
2,573
1
1,323
(361)
22
(339)
984
417
$
688 $
664 $
24 $
567 $
346
(514)
(168)
92
(90)
(15)
(13)
4
(177)
14
11
25
(152)
249
97
Year Ended December 31, 2019 Compared to Year Ended December 31, 2018. Net income increased by $24 million primarily due to higher electric
distribution, transmission and energy efficiency formula rate earnings (reflecting the impacts of higher rate base, partially offset by lower allowed electric
distribution ROE due to a decrease in treasury rates).
Revenues Net of Purchased Power Expense. There are certain drivers of Operating revenues that are fully offset by their impact on Purchased power
expense, such as commodity, REC and ZEC procurement costs and participation in customer choice programs. ComEd recovers electricity, REC and ZEC
procurement costs from customers without mark-up. Therefore, fluctuations in these costs have no impact on RNF.
Customers have the choice to purchase electricity from a competitive electric generation supplier. Customer choice programs do not impact the volume of
deliveries, but do impact Operating revenues related to supplied electricity.
The changes in RNF consisted of the following:
Electric distribution revenue
Transmission revenue
Energy efficiency revenue
Uncollectible accounts recovery, net
Other
Total increase
91
Increase (Decrease)
2019 vs. 2018
$
$
47
32
47
(7)
(40)
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ComEd
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 a change to the electric distribution formula rate pursuant to FEJA.
Distribution Revenue. EIMA and FEJA provide for a performance-based formula rate, which requires an annual reconciliation of the revenue requirement in
effect to the actual costs that the ICC determines are prudently and reasonably incurred in a given year. Electric distribution revenue varies from year to year
based upon fluctuations in the underlying costs (e.g., severe weather and storm restoration), investments being recovered and allowed ROE. During the year
ended December 31, 2019, as compared to the same period in 2018, electric distribution revenue increased primarily due to the impact of higher rate base and
increased depreciation expenses, offset by lower allowed ROE due to a decrease in treasury rates. See Operating and Maintenance Expense below and 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, 2019, as compared to
the same period in 2018, transmission revenue increased primarily due to the impact of increased peak load, higher rate base, and higher fully recoverable
costs. See Operating and Maintenance Expense below and Note 3 — Regulatory Matters of the Combined Notes to Consolidated Financial Statements for
additional information.
Energy Efficiency Revenue. FEJA provides for a performance-based formula rate, which requires an annual reconciliation of the revenue requirement in effect
to the actual costs that the ICC determines are prudently and reasonably incurred in a given year. 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, 2019, as compared to the same period in 2018, primarily due to the impact of higher rate base and increased regulatory asset amortization. See
Depreciation and amortization expense discussions below and Note 3 — Regulatory Matters of the Combined Notes to Consolidated Financial Statements for
additional information.
Uncollectible Accounts Recovery, Net represents recoveries under the uncollectible accounts tariff. See Operating and maintenance expense discussion
below for additional information on this tariff.
Other revenue includes rental revenue, revenue related to late payment charges, mutual assistance revenues and recoveries of environmental costs associated
with MGP sites. The decrease in Other revenue for the year ended December 31, 2019, as compared to the same period in 2018, primarily reflects absence of
mutual assistance revenues associated with hurricane and winter storm restoration efforts that occurred in Q1 2018. An equal and offsetting amount was
included in Operating and maintenance expense.
See Note 5 — Segment Information of the Combined Notes to Consolidated Financial Statements for the presentation of ComEd's revenue disaggregation.
The changes in Operating and maintenance expense consisted of the following:
Baseline
Pension and non-pension postretirement benefits expense(a)
Labor, other benefits, contracting and materials(b)
Uncollectible accounts expense(c)
Storm costs
Other
Total decrease
92
(Decrease) Increase
2019 vs. 2018
$
$
(36)
(27)
(7)
31
9
(30)
Table of Contents
ComEd
__________
(a) Primarily reflects an increase in discount rates and the favorable impacts of the merger of two of Exelon’s pension plans
effective in January 2019, partially offset by lower than expected asset returns in 2018.
(b) Primarily reflects absence of mutual assistance expenses and decreased contracting costs. An equal and offsetting increase has been recognized in Operating revenues
for the period presented.
(c) ComEd is allowed to recover from or refund to customers the difference between its annual uncollectible accounts expense and the amounts collected in rates annually
through a rider mechanism. ComEd recorded a net decrease in uncollectible accounts for the year ended December 31, 2019, as compared to the same period in 2018,
primarily due to the timing of regulatory cost recovery. An equal and offsetting amount has been recognized in Operating revenues for the periods presented.
The changes in Depreciation and amortization expense consisted of the following:
Depreciation expense(a)
Regulatory asset amortization(b)
Total increase
__________
(a) Reflects ongoing capital expenditures and higher depreciation rates effective January 2019.
(b)
Includes amortization of ComEd's energy efficiency formula rate regulatory asset.
Increase
2019 vs. 2018
58
35
93
$
$
Effective income tax rates for the years ended December 31, 2019 and 2018, were 19.2% and 20.2% , respectively. See Note 13 — 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
Purchased power and fuel expense
Revenues net of purchased power and fuel expense
2019
2018
$
3,100 $
3,038 $
1,029
2,071
1,090
1,948
Other operating expenses
Operating and maintenance
Depreciation and amortization
Taxes other than income taxes
861
333
165
898
301
163
Total other operating expenses
1,359
1,362
PECO
Favorable (unfavorable)
2019 vs. 2018 variance
2017
Favorable (unfavorable)
2018 vs. 2017 variance
$
2,870 $
62
61
123
37
(32)
(2)
3
969
1,901
806
286
154
1,246
—
655
(126)
9
(117)
538
104
168
(121)
47
(92)
(15)
(9)
(116)
1
(68)
(3)
(1)
(4)
(72)
98
26
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
1
713
(136)
16
(120)
593
65
1
587
(129)
8
(121)
466
6
—
126
(7)
8
1
127
(59)
$
528 $
460 $
68
$
434 $
Year Ended December 31, 2019 Compared to Year Ended December 31, 2018. Net income increased by $68 million primarily due to higher electric
distribution rates that became effective January 2019, higher natural gas distribution rates and lower storm costs, partially offset by unfavorable weather
conditions and volume.
Revenues Net of Purchased Power and Fuel Expense. There are certain drivers of Operating revenues that are fully offset by their impact on Purchased
power and fuel expenses such as commodity and REC procurement costs and participation in customer choice programs. PECO's recovers electricity, natural
gas and REC procurement costs from customers without mark-up. Therefore, fluctuations in these costs have no impact on RNF.
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 or RNF, but impact Operating revenues related to supplied electricity and natural gas.
The changes in RNF consisted of the following:
Weather
Volume
Pricing
Regulatory required programs
Transmission Revenue
Other
Total increase
2019 vs. 2018
(Decrease) Increase
Electric
Gas
Total
(11) $
(8) $
(22)
112
42
(13)
(2)
6
10
9
—
—
106 $
17 $
(19)
(16)
122
51
(13)
(2)
123
$
$
94
Table of Contents
PECO
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, 2019 compared to the same period in 2018 RNF was decreased by the impact of unfavorable weather conditions in PECO's service territory.
Heating and cooling degree days are quantitative indices that reflect the demand for energy needed to heat or cool a home or business. Normal weather is
determined based on historical average heating and cooling degree 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, 2019 and December 31, 2018 compared to the same periods in 2018 and 2017,
respectively, and normal weather consisted of the following:
Heating and Cooling Degree-Days
Heating Degree-Days
Cooling Degree-Days
2019
2018
Normal
2019 vs. 2018
2019 vs. Normal
4,307
1,610
4,539
1,584
4,458
1,415
(5.1)%
1.6 %
(3.4)%
13.8 %
For the Years Ended December 31,
% Change
Volume. Electric volume, exclusive of the effects of weather, for the year ended December 31, 2019 compared to the same period in 2018, decreased due to
lower customer usages for residential, commercial and industrial electric classes, partially offset by the impact of customer growth. Natural gas volume for the
year ended December 31, 2019 compared to the same period in 2018, increased due to customer and economic growth.
Electric Retail Deliveries to Customers (in GWhs)
Retail Deliveries (a)
Residential
Small commercial & industrial
Large commercial & industrial
Public authorities & electric railroads
Total electric retail deliveries
2019
2018
% Change 2019 vs.
2018
Weather - Normal %
Change(b)
13,650
7,983
14,958
725
14,005
8,177
15,516
761
37,316
38,459
(2.5)%
(2.4)%
(3.6)%
(4.7)%
(3.0)%
(1.4)%
(1.2)%
(3.4)%
(5.0)%
(2.3)%
__________
(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
95
As of December 31,
2019
2018
1,494,462
154,000
3,104
10,039
1,480,925
152,797
3,118
9,565
1,661,605
1,646,405
Table of Contents
Natural Gas Deliveries to customers (in mmcf)
Retail Deliveries (a)
Residential
Small commercial & industrial
Large commercial & industrial
Transportation
Total natural gas deliveries
PECO
2019
2018
% Change 2019 vs.
2018
Weather - Normal %
Change(b)
40,196
23,828
50
25,822
89,896
43,450
21,997
65
26,595
92,107
(7.5)%
8.3 %
(23.1)%
(2.9)%
(2.4)%
0.9 %
1.4 %
7.4 %
(1.3)%
0.4 %
__________
(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 Gas Customers
Residential
Small commercial & industrial
Large commercial & industrial
Transportation
Total
As of December 31,
2019
2018
487,337
44,374
2
730
482,255
44,170
1
754
532,443
527,180
Pricing for the year ended December 31, 2019 compared to the same period in 2018 increased primarily due to an increase in electric distribution rates charged
to customers. The increase in electric distribution rates was effective January 1, 2019 in accordance with the 2018 PAPUC approved electric distribution rate
case settlement. Additionally, the increase represents revenue from higher natural gas distribution rates. See Note 3 — Regulatory Matters of the Combined
Notes to Consolidated Financial Statements for additional information.
Regulatory Required Programs represent 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
Operating and maintenance expense, Depreciation and amortization expense and Income taxes.
Transmission Revenue. Under a FERC approved formula, transmission revenue varies from year to year based upon fluctuations in the underlying costs and
capital investments being recovered. Transmission revenue for the year ended December 31, 2019 compared to the same period in 2018 decreased primarily
due to lower operating and maintenance expenses and the terms of the settlement agreement approved by FERC in December 2019. 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 and mutual assistance revenues.
See Note 5—Segment Information of the Combined Notes to Consolidated Financial Statements for the presentation of PECO's revenue disaggregation.
96
Table of Contents
The changes in Operating and maintenance expense consisted of the following:
Baseline
Storm-related costs (a)
Pension and non-pension postretirement benefits expense
Uncollectible accounts expense
BSC costs
Labor, other benefits, contracting and materials
Other
Regulatory required programs
Energy efficiency
Decrease in operating and maintenance expense
__________
(a) Reflects decreased storm costs due to the March 2018 winter storms.
The changes in Depreciation and amortization expense consisted of the following:
Depreciation expense (a)
Regulatory asset amortization
Increase in depreciation and amortization expense
__________
(a) Depreciation expense increased due to ongoing capital expenditures.
PECO
(Decrease) Increase
2019 vs. 2018
$
$
$
$
(30)
(5)
(2)
2
1
(7)
(41)
4
(37)
28
4
32
Increase
2019 vs. 2018
Effective income tax rates were 11.0% and 1.3% for the years ended December 31, 2019 and 2018, respectively. See Note 13 — Income Taxes of the
Combined Notes to Consolidated Financial Statements for additional information of the change in effective income tax rates.
97
Table of Contents
Results of Operations—BGE
BGE
2019
2018
Favorable (unfavorable)
2019 vs. 2018 variance
2017
Favorable (unfavorable)
2018 vs. 2017 variance
Operating revenues
$
Purchased power and fuel expense
Revenues net of purchased power and fuel
expense
Other operating expenses
3,106 $
1,052
3,169 $
1,182
2,054
1,987
Operating and maintenance
Depreciation and amortization
Taxes other than income taxes
Total other 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
Net income attributable to common
shareholder
760
502
260
1,522
—
532
(121)
28
(93)
439
79
360
777
483
254
1,514
1
474
(106)
19
(87)
387
74
313
(63)
$
130
67
17
(19)
(6)
(8)
(1)
58
(15)
9
(6)
52
(5)
47
3,176 $
1,133
2,043
716
473
240
1,429
—
614
(105)
16
(89)
525
218
307
(7)
(49)
(56)
(61)
(10)
(14)
(85)
1
(140)
(1)
3
2
(138)
144
6
6
$
360 $
313 $
47
$
307 $
Year Ended December 31, 2019 Compared to Year Ended December 31, 2018. Net income attributable to common shareholder increased by $47 million
primarily due to higher natural gas distribution rates that became effective January 2019 and December 2019, higher electric distribution rates that became
effective December 2019, and lower storm costs, partially offset by an increase in various expenses, including interest.
Revenues Net of Purchased Power and Fuel Expense. There are certain drivers to Operating revenues that are fully offset by their impact on Purchased
power and fuel expense, such as commodity procurement costs and participation in customer choice programs. BGE recovers electricity, natural gas and other
procurement costs from customers without mark-up. Therefore, fluctuations in these costs have no impact on RNF.
Customers have the choice to purchase electricity and natural gas from electric generation and natural gas competitive suppliers. Customer choice programs do
not impact the volume of deliveries or RNF but impact Operating revenues related to supplied electricity and natural gas.
98
Table of Contents
The changes in RNF consisted of the following:
Distribution revenue
Regulatory required programs
Transmission revenue
Other, net
Total increase
BGE
79
(10)
10
(12)
67
2019 vs. 2018
Increase (Decrease)
Electric
Gas
Total
11 $
68 $
(6)
10
(7)
(4)
—
(5)
8 $
59
$
$
$
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,
2019
2018
1,177,333
1,168,372
114,504
12,322
268
113,915
12,253
262
1,304,427
1,294,802
As of December 31,
2019
2018
639,426
38,345
6,037
683,808
633,757
38,332
5,954
678,043
Distribution Revenues increased during the year ended December 31, 2019, compared to the same period in 2018, primarily due to the impact of higher
natural gas distribution rates that became effective in both January 2019 and December 2019 and higher electric distribution rates that became effective in
December 2019. See Note 3 — Regulatory Matters of the Combined Notes to Consolidated Financial Statements for additional information.
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 Operating and maintenance expense, Depreciation and amortization expense and Taxes other than
income taxes.
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 increased during the year ended
December 31, 2019 compared to the same period in 2018, primarily due to increases in capital investment and operating and maintenance expense recoveries.
See Operating and maintenance expense below and Note 3 — Regulatory Matters of the Combined Notes to Consolidated Financial Statements for additional
information.
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Table of Contents
BGE
Other revenue includes revenue related to late payment charges, mutual assistance revenues, off-system sales and service application fees.
See Note 5 — Segment Information of the Combined Notes to Consolidated Financial Statements for the presentation of BGE's revenue disaggregation.
The changes in Operating and maintenance expense consisted of the following:
Baseline
Storm-related costs(a)
Uncollectible accounts expense
BSC costs
Labor, other benefits, contracting and materials
Pension and non-pension postretirement benefits expense
Other
Regulatory Required Programs
Total (decrease) increase
__________
(a) Reflects decreased storm restoration costs due to the March 2018 winter storms.
The changes in Depreciation and amortization expense consisted of the following:
Depreciation expense(a)
Regulatory asset amortization
Regulatory required programs
Increase in depreciation and amortization expense
__________
(a) Depreciation expense increased due to ongoing capital expenditures.
(Decrease) Increase
2019 vs. 2018
(24)
(2)
(1)
8
1
2
(16)
(1)
(17)
Increase (Decrease)
2019 vs. 2018
24
4
(9)
19
$
$
$
$
Interest expense, net increased during the year ended December 31, 2019 compared to the same period in 2018, primarily due to the issuances of debt in
September 2018 and September 2019.
Other, net increased during the year ended December 31, 2019 compared to the same period in 2018, primarily due to higher AFUDC equity.
Effective income tax rates were 18% and 19.1% for the years ended December 31, 2019 and 2018, respectively. See Note 13 — 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. See the results of operations for Pepco, DPL, and ACE for additional information.
PHI
Pepco
DPL
ACE
2019
2018(a)
Favorable (unfavorable)
2019 vs. 2018 variance
2017(a)
Favorable (unfavorable)
2018 vs. 2017 variance
$
477 $
393 $
243
147
99
205
120
75
84
38
27
24
$
355 $
198
121
77
38
7
(1)
(2)
Other(b)
_________
(a) PHI's and Pepco's amounts have been revised to reflect the correction of an error related to Pepco's decoupling mechanism. See Note 1 - Significant Accounting Policies
(12)
(41)
(7)
(5)
34
of the Combined Notes to Consolidated Financial Statements for additional information.
(b) Primarily includes eliminating and consolidating adjustments, PHI's corporate operations, shared service entities and other financing activities.
Year Ended December 31, 2019 Compared to Year Ended December 31, 2018. Net income increased by $84 million primarily due to higher electric and
natural gas distribution rates (not reflecting the impact of TCJA), higher transmission revenues due to an increase in transmission rates and the highest daily
peak load, lower contracting costs, the absence of the charge associated with a remeasurement of the Buzzard Point ARO, lower uncollectible accounts
expense, and lower write-offs of construction work in progress, partially offset by an increase in environmental liabilities and various expenses.
101
Total other operating expenses
1,234
1,265
Table of Contents
Results of Operations—Pepco
Operating revenues
Purchased power expense
Revenues net of purchased power expense
Other operating expenses
Operating and maintenance
Depreciation and amortization
Taxes other than income taxes
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
Pepco
2019
2018(a)
Favorable (unfavorable)
2019 vs. 2018 variance
2017(a)
Favorable (unfavorable)
2018 vs. 2017 variance
$
2,260 $
2,232 $
28
$
2,151 $
665
1,595
482
374
378
654
1,578
501
385
379
—
361
(133)
31
(102)
259
16
—
313
(128)
31
(97)
216
11
(11)
17
19
11
1
31
—
48
(5)
—
(5)
43
(5)
614
1,537
454
321
371
1,146
1
392
(121)
32
(89)
303
105
81
(40)
41
(47)
(64)
(8)
(119)
(1)
(79)
(7)
(1)
(8)
(87)
94
7
$
243 $
205 $
38
$
198 $
__________
(a) Amounts have been revised to reflect the correction of an error related to Pepco’s decoupling mechanism. See Note 1 — Significant Accounting Policies of the Combined
Notes to Consolidated Financial Statements for additional information.
Year Ended December 31, 2019 Compared to Year Ended December 31, 2018. Net income increased by $38 million primarily due to higher electric
distribution rates in Maryland that became effective August 2019 and June 2018 (not reflecting the impact of TCJA), higher electric distribution rates in the
District of Columbia that became effective August 2018 (not reflecting the impact of TCJA), higher transmission revenues due to an increase in transmission
rates and the highest daily peak load, the absence of the charge associated with a remeasurement of the Buzzard Point ARO, and lower contracting costs,
partially offset by an increase in environmental liabilities.
Revenues Net of Purchased Power Expense. There are certain drivers of Operating revenues that are fully offset by their impact on Purchased power
expense, such as commodity and REC procurement costs and participation in customer choice programs. Pepco recovers electricity and REC procurement
costs from customers with a slight mark-up. Therefore, fluctuations in these costs have minimal impact on RNF.
Customers have the choice to purchase electricity from competitive electric generation suppliers. Customer choice programs do not impact the volume of
deliveries or RNF, but impact Operating revenues related to supplied electricity.
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Table of Contents
The changes in RNF consisted of the following:
Volume
Distribution revenue
Regulatory required programs
Transmission revenues
Other
Total increase
Pepco
Increase (Decrease)
2019 vs. 2018
12
20
(35)
18
2
17
$
$
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.
Volume, exclusive of the effects of weather, increased for the year ended December 31, 2019 compared to the same period in 2018 primarily due to the impact
of residential customer growth.
Number of Electric Customers
Residential
Small commercial & industrial
Large commercial & industrial
Public authorities & electric railroads
Total
As of December 31,
2019
2018
817,770
54,265
22,271
160
894,466
807,442
54,306
22,022
150
883,920
Distribution Revenues increased for the year ended December 31, 2019 compared to the same period in 2018 primarily due to higher electric distribution rates
in Maryland that became effective in August 2019 and June 2018 (not reflecting the impact of TCJA), higher electric distribution rates (not reflecting the impact of
TCJA) in the District of Columbia that became effective in August 2018, partially offset by the accelerated amortization of certain deferred income tax regulatory
liabilities established upon the enactment of TCJA as the result of regulatory settlements. See Note 3 — Regulatory Matters of the Combined Notes to
Consolidated Financial Statements for additional information.
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 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 Operating and maintenance expense, Depreciation and amortization expense, and Taxes other than
income taxes. Revenues from regulatory programs decreased for the year ended December 31, 2019 compared to the same period in 2018 due to lower
surcharge rates effective January 2019 for energy efficiency programs that were implemented to reflect the impacts of the enactment of TCJA.
Transmission Revenues. 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 increased for the year ended
December 31, 2019 compared to the same period in 2018 due to rate increases and an increase in the highest daily peak load.
Other revenue includes revenue related to late payment charges, mutual assistance revenues, off-system sales and service application fees.
103
Table of Contents
Pepco
See Note 5 - Segment Information for the Combined Notes to Consolidated Financial Statements for the presentation of Pepco's revenue disaggregation.
The changes in Operating and maintenance expense consisted of the following:
Baseline
BSC and PHISCO costs
Labor, other benefits, contracting and materials
Uncollectible accounts expense
Pension and Non-Pension Postretirement Benefits
Other
Regulatory required programs
Total decrease
Depreciation expense(a)
Regulatory asset amortization
Regulatory required programs
Total decrease
(Decrease) Increase
2019 vs. 2018
Increase (Decrease)
2019 vs. 2018
(16)
(11)
(3)
6
8
(16)
(3)
(19)
21
4
(36)
(11)
$
$
$
$
__________
(a) Depreciation and amortization increased primarily due to ongoing capital expenditures.
Interest expense, net for the year ended December 31, 2019 compared to the same period in 2018 increased primarily due to higher outstanding debt.
Effective income tax rates for the years ended December 31, 2019 and 2018 were 6.2% and 5.1%, respectively. See Note 13 — Income Taxes of the
Combined Notes to Consolidated Financial Statements for additional information regarding the components of the change in effective income tax rates.
104
Table of Contents
Results of Operations—DPL
DPL
2019
2018
Favorable (unfavorable)
2019 vs. 2018 variance
2017
Favorable (unfavorable)
2018 vs. 2017 variance
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
Operating income
Other income and (deductions)
Interest expense, net
Other, net
Total other income and (deductions)
Income before income taxes
Income taxes
Net income
$
1,306 $
1,332 $
(26)
$
1,300 $
526
780
323
184
56
563
—
217
(61)
13
(48)
169
22
561
771
344
182
56
582
1
190
(58)
10
(48)
142
22
35
9
21
(2)
—
19
(1)
27
(3)
3
—
27
—
532
768
315
167
57
539
—
229
(51)
14
(37)
192
71
$
147 $
120 $
27
$
121 $
32
(29)
3
(29)
(15)
1
(43)
1
(39)
(7)
(4)
(11)
(50)
49
(1)
Year Ended December 31, 2019 Compared to Year Ended December 31, 2018. Net income increased by $27 million primarily due to higher transmission
revenues due to an increase in the transmission rates and the highest daily peak load, higher electric distribution rates in Maryland and Delaware that became
effective throughout 2018 (not reflecting the impact of TCJA), higher natural gas distribution rates in Delaware that became effective throughout 2018 (not
reflecting the impact of TCJA), and lower write-offs of construction work in progress.
Revenues Net of Purchased Power and Fuel Expense. There are certain drivers to Operating revenues that are fully offset by their impact on Purchased
power and fuel expense, such as commodity and REC procurement costs and participation in customer choice programs. DPL recovers electricity and REC
procurement costs from customers with a slight mark-up and natural gas costs from customers without mark-up. Therefore, fluctuations in these costs have
minimal impact on RNF.
Customers have the choice to purchase electricity from competitive electric generation suppliers. Customer choice programs do not impact the volume of
deliveries or RNF, but impact Operating revenues related to supplied electricity.
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Table of Contents
The changes in RNF consisted of the following:
Weather
Volume
Distribution revenue
Regulatory required programs
Transmission revenues
Other
Total increase
DPL
(7)
3
3
(5)
19
(4)
9
2019 vs. 2018
Increase (Decrease)
Electric
Gas
Total
$
(3) $
(4) $
1
2
(7)
19
(4)
2
1
2
—
—
$
8
$
1
$
Revenue Decoupling. The demand for electricity is affected by weather and customer usage. However, Operating revenues from electric distribution customers
in Maryland are not affected by unseasonably warmer or colder weather because a bill stabilization adjustment (BSA) that provides for a fixed distribution charge
per customer by customer class. While Operating revenues from electric distribution customers in Maryland are not impacted by abnormal weather or usage per
customer, they are impacted by changes in the number of customers.
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, 2019 compared to the same period in 2018, RNF related to weather decreased primarily due to unfavorable weather conditions in
DPL's Delaware 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 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, 2019 compared to same period in 2018 and normal weather consisted of the following:
Delaware Electric Service Territory
For the Years Ended December 31,
% Change
Heating and Cooling Degree-Days
2019
2018
Normal
2019 vs. 2018
2019 vs. Normal
Heating Degree-Days
Cooling Degree-Days
4,475
1,476
4,713
1,456
4,656
1,224
(5.0)%
1.4 %
(3.9)%
20.6 %
Delaware Natural Gas Service Territory
For the Years Ended December 31,
% Change
Heating Degree-Days
Heating Degree-Days
2019
2018
Normal
2019 vs. 2018
2019 vs. Normal
4,475
4,713
4,698
(5.0)%
(4.7)%
Volume, exclusive of the effects of weather, remained relatively consistent for the year ended December 31, 2019 compared to the same period in 2018.
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Table of Contents
DPL
Electric Retail Deliveries to Delaware Customers (in GWhs)
2019
2018
% Change 2019 vs.
2018
Weather - Normal
% Change (b)
Retail Deliveries
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
3,149
1,320
3,424
34
7,927
3,204
1,344
3,636
33
8,217
(1.7)%
(1.8)%
(5.8)%
3.0 %
(3.5)%
(0.2)%
(1.4)%
(5.7)%
0.9 %
(2.9)%
As of December 31,
2019
2018
468,162
61,721
1,411
613
463,670
61,381
1,406
621
Total
__________
(a) Reflects delivery volumes and revenues from customers purchasing electricity directly from DPL and customers purchasing electricity from a competitive electric
527,078
531,907
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)
2019
2018
% Change
2019 vs. 2018
Weather - Normal
% Change(b)
Retail Deliveries
Residential
Small commercial & industrial
Large commercial & industrial
Transportation
Total natural gas deliveries(a)
Number of Delaware Gas Customers
Residential
Small commercial & industrial
Large commercial & industrial
Transportation
8,613
4,287
1,811
6,733
8,633
4,134
1,952
6,831
21,444
21,550
(0.2)%
3.7 %
(7.2)%
(1.4)%
(0.5)%
4.2 %
7.8 %
(7.1)%
(0.2)%
2.5 %
As of December 31,
2019
2018
125,873
9,999
17
159
124,183
9,986
18
156
Total
_________
(a) Reflects delivery volumes and revenues from customers purchasing natural gas directly from DPL and customers purchasing natural gas from a competitive natural gas
134,343
136,048
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, 2019 compared to the same period in 2018 primarily due to higher electric distribution rates
(not reflecting the impact of TCJA) in Maryland and Delaware that became effective throughout 2018 and higher natural gas distribution rates (not reflecting the
impact of TCJA) in Delaware that became effective throughout 2018, partially offset by the accelerated amortization of certain deferred income tax regulatory
liabilities established upon the enactment of TCJA as the result of regulatory settlements. See Note 3 — Regulatory Matters of the Combined Notes to
Consolidated Financial Statements for additional information.
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DPL
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 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 Operating and maintenance expense, Depreciation and
amortization expense and Taxes other than income taxes.
Transmission Revenues. 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 increased for the year ended
December 31, 2019 compared to the same period in 2018 due to rate increases and an increase in the highest daily peak load.
Other revenue includes revenue related to late payment charges, mutual assistance revenues, off-system sales and service application fees.
See Note 5 - Segment Information for the Combined Notes to Consolidated Financial Statements for the presentation of DPL's revenue disaggregation.
The changes in Operating and maintenance expense consisted of the following:
Baseline
BSC and PHISCO costs
Write-off of construction work in progress
Uncollectible accounts expense
Pension and non-pension postretirement benefits expense
Labor, other benefits, contracting and materials
Storm-related costs
Other
Regulatory required programs
Total decrease
The changes in Depreciation and amortization expense consisted of the following:
Depreciation expense(a)
Regulatory asset amortization
Regulatory required programs
Total increase
_________
(a) Depreciation and amortization increased primarily due to ongoing capital expenditures.
(Decrease) Increase
2019 vs. 2018
(10)
(7)
(2)
4
2
(1)
(6)
(20)
(1)
(21)
Increase (Decrease)
2019 vs. 2018
14
(1)
(11)
2
$
$
$
$
Interest expense, net for the year ended December 31, 2019 compared to the same period in 2018 increased primarily due to higher outstanding debt.
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DPL
Effective income tax rates for the years ended December 31, 2019 and 2018 were 13.0% and 15.5%, respectively. See Note 13 — Income Taxes of the
Combined Notes to Consolidated Financial Statements for additional information regarding the components of the change in effective income tax rates
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Results of Operations—ACE
Operating revenues
Purchased power expense
Revenues net of purchased power expense
Other operating expenses
Operating and maintenance
Depreciation and amortization
Taxes other than income taxes
Total other operating expenses
Gain on sales of assets
Operating income
Other income and (deductions)
Interest expense, net
Other, net
Total other income and
(deductions)
Income (loss) before income taxes
Income taxes
Net income
2019
2018
$
1,240 $
1,236 $
608
632
320
157
4
481
—
151
(58)
6
(52)
99
—
616
620
330
136
5
471
—
149
(64)
2
(62)
87
12
$
99 $
75 $
ACE
Favorable (unfavorable)
2019 vs. 2018 variance
2017
Favorable (unfavorable)
2018 vs. 2017 variance
$
1,186 $
—
4
8
12
10
(21)
1
(10)
2
6
4
10
12
12
24
570
616
307
146
6
459
—
157
(61)
7
(54)
103
26
$
77 $
50
(46)
4
(23)
10
1
(12)
—
(8)
(3)
(5)
(8)
(16)
14
(2)
Year Ended December 31, 2019 Compared to Year Ended December 31, 2018. Net income increased $24 million primarily due to higher electric distribution
rates that became effective April 2019 and higher transmission revenues due to an increase in the transmission rates and the highest daily peak load, partially
offset by lower average residential usage.
Revenues Net of Purchased Power Expense. There are certain drivers of Operating revenues that are fully offset by their impact on Purchased power
expense, such as commodity and REC procurement costs and participation in customer choice programs. ACE recovers electricity and REC procurement costs
from customers without mark-up. Therefore, fluctuations in these costs have no impact on RNF.
Customers have the choice to purchase electricity from competitive electric generation suppliers. Customer choice programs of supplier do not impact the
volume of deliveries or RNF, but impact revenues related to supplied electricity.
The changes in RNF, consisted of the following:
Weather
Volume
Distribution revenue
Regulatory required programs
Transmission revenues
Other
Total increase
110
(Decrease) Increase
2019 vs. 2018
(6)
(11)
36
(23)
20
(4)
12
$
$
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ACE
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. During the year ended December 31, 2019 compared to the same period in 2018, RNF related to weather was lower
due to the impact of unfavorable weather conditions in ACE'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 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, 2019 compared to same period in 2018, and normal weather consisted of the following:
Heating and Cooling Degree-Days
2019
2018
Normal
2019 vs. 2018
2019 vs. Normal
Heating Degree-Days
Cooling Degree-Days
4,467
1,374
4,523
1,535
4,676
1,158
(1.2)%
(10.5)%
(4.5)%
18.7 %
For the Years Ended December 31,
% Change
Volume, exclusive of the effects of weather, decreased for the year ended December 31, 2019 compared to the same period in 2018, primarily due to lower
average residential and commercial usage.
Electric Retail Deliveries to Customers (in GWhs)
Retail Deliveries
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
2019
2018
% Change 2019 vs.
2018
Weather - Normal %
Change(b)
3,966
1,346
3,429
47
8,788
4,185
1,361
3,565
49
9,160
(5.2)%
(1.1)%
(3.8)%
(4.1)%
(4.1)%
(3.5)%
0.1 %
(3.4)%
(2.9)%
(2.9)%
As of December 31,
2019
2018
494,596
61,497
3,392
679
490,975
61,386
3,515
656
Total
__________
(a) Reflects delivery volumes and revenues from customers purchasing electricity directly from ACE and customers purchasing electricity from a competitive electric
556,532
560,164
generation supplier as all customers are assessed distribution charges.
(b) Reflects the change in delivery volumes assuming normalized weather based on the historical 20-year average.
Distribution Revenue increased for the year ended December 31, 2019 compared to the same period in 2018 primarily due to higher electric distribution base
rates that became effective in April 2019, partially offset by the accelerated amortization of certain deferred income tax regulatory liabilities established upon the
enactment of TCJA as the result of regulatory settlements. See Note 3 — Regulatory Matters of the Combined Notes to Consolidated Financial Statements for
additional information.
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 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 Operating and maintenance expense, Depreciation and
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ACE
amortization expense and Taxes other than income taxes. Revenues from regulatory programs decreased for the year ended December 31, 2019 compared to
the same period in 2018 due to rate decreases effective October 2018 for the ACE Transition Bonds.
Transmission Revenues. 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 increased for the year ended
December 31, 2019 compared to the same period in 2018 primarily due to rate increases and an increase in the highest daily peak load.
Other revenue includes revenue related to late payment charges, mutual assistance revenues, off-system sales and service application fees.
See Note 5 - Segment Information of the Combined Notes to Consolidated Financial Statements for the presentation of ACE's revenue disaggregation.
The changes in Operating and maintenance expense consisted of the following:
Baseline
BSC and PHISCO costs
Uncollectible accounts expense(a)
Labor, other benefits, contracting and materials
Storm-related costs
Pension and non-pension postretirement benefits expense
Other
Total decrease
(Decrease) Increase
2019 vs. 2018
$
$
(8)
(6)
(5)
2
1
6
(10)
__________
(a) ACE is allowed to recover from or refund to customers the difference between its annual uncollectible accounts expense and the amounts collected in rates annually
through a rider mechanism. An equal and offsetting amount has been recognized in Operating revenues for the periods presented.
The changes in Depreciation and amortization expense consisted of the following:
Depreciation expense(a)
Regulatory asset amortization
Regulatory required programs
Total increase
Increase (Decrease)
2019 vs. 2018
29
6
(14)
21
$
$
__________
(a) Depreciation and amortization increased primarily due to ongoing capital expenditures.
Interest expense, net for the year ended December 31, 2019 compared to the same period in 2018 decreased primarily due to lower outstanding debt.
Other, net for the year ended December 31, 2019 compared to the same period in 2018 increased primarily due to higher AFUDC equity.
Effective income tax rates were 0.0% and 13.8% for the years ended December 31, 2019 and 2018, respectively. See Note 13 — 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 as well as funds from external
sources in the capital markets and through bank borrowings. The Registrants’ businesses are capital intensive and require considerable capital resources. Each
of the Registrants annually evaluates its financing plan, dividend practices and credit line sizing, focusing on maintaining its investment grade ratings while
meeting its cash needs to fund capital requirements, retire debt, pay dividends, fund pension and OPEB obligations and invest in new and existing ventures. A
broad spectrum of financing alternatives beyond the core financing options can be used to meet its needs and fund growth including monetizing assets in the
portfolio via project financing, asset sales, and the use of other financing structures (e.g., joint ventures, minority partners, etc.). Each Registrant’s access to
external financing on reasonable terms depends on its credit ratings and current overall capital market business conditions, including that of the utility industry in
general. If these conditions deteriorate to the extent that the Registrants no longer have access to the capital markets at reasonable terms, the
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Registrants have access to credit facilities with aggregate bank commitments of $10.6 billion. The Registrants utilize their credit facilities to support their
commercial paper programs, provide for other short-term borrowings and to issue letters of credit. See the “Credit Matters” section below for additional
information. The Registrants expect cash flows to be sufficient to meet operating expenses, financing costs and capital expenditure requirements.
The Registrants primarily use their capital resources, including cash, to fund capital requirements, including construction expenditures, retire debt, pay dividends,
fund pension and other postretirement benefit 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, ComEd, PECO, BGE, Pepco, DPL and ACE 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 16 — Debt and Credit Agreements of the Combined Notes to Consolidated Financial Statements for additional information of the
Registrants’ debt and credit agreements.
NRC Minimum Funding Requirements
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 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 9 - 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 fund investments 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.
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, the NRC must approve an exemption in order for the plant’s owner(s) to utilize the
NDT fund to pay for non-radiological decommissioning costs (i.e., spent fuel management and site restoration costs). If a unit does not receive this exemption,
the costs would be borne by the owner(s) without reimbursement from or access to the NDT funds. The ultimate costs for spent fuel management may vary
greatly and could be reduced by alternate decommissioning scenarios and/or reimbursement of certain costs under the DOE reimbursement agreements.
As of December 31, 2019, 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
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lives. Additionally, project finance has credit facilities. See Note 16 — Debt and Credit Agreements of the Combined Notes to Consolidated Financial Statements
for additional information on nonrecourse debt.
Cash Flows from Operating Activities
General
Generation’s cash flows from operating activities primarily result from the sale of electric energy and energy-related products and services 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, competitive suppliers, and their ability to achieve operating cost reductions.
See Note 3 — Regulatory Matters and Note 18 — Commitments and Contingencies of the Combined Notes to Consolidated Financial Statements for additional
information of regulatory and legal proceedings and proposed legislation.
The following table provides a summary of the change in cash provided by (used in) operating activities for the years ended December 31, 2019, 2018 and 2017:
2019 vs. 2018 Variance
Exelon
Generation
ComEd
PECO
BGE
PHI
Pepco
DPL
ACE
$
949
$
774
$
24 $
68 $
47 $
84 $
38 $
27 $
24
Net income
Add (subtract):
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 received (paid), net
Collateral posted (received), net
Net cash flows provided by (used in) operations
$
(1,985)
$
(835)
(36)
495
(855)
14
(545)
(988)
(34)
(35)
33
(71)
—
37
$
(46)
$
43
—
100
6
(12)
49
(49)
(47)
(18)
(50)
—
—
12 $
(139)
(118)
—
(8)
—
—
(41)
$
(15)
$
(1)
3
22
(24)
—
—
38 $
(26)
(3)
(1)
10
(68)
—
—
(58)
$
5
4
3
—
—
33
2018 vs. 2017 Variance
Exelon
Generation
ComEd
PECO
BGE
PHI
Pepco
DPL
ACE
$
(1,790)
$
(2,355)
$
97
$
26
$
6 $
38 $
7 $
(1)
$
(2)
Net income
Add (subtract):
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 received (paid), net
Collateral posted (received), net
3,116
9
(689)
359
(71)
193
562
(232)
(1)
370
(49)
—
37
222
$
(12)
(4)
(19)
(7)
—
—
(73)
(1)
(80)
112
—
4
(124)
25
(17)
55
(41)
(17)
2
(45)
(94)
(24)
288
—
—
182 $
116
—
—
67 $
95
—
—
31 $
14
9
18
—
—
22
Net cash flows provided by (used in) operations
$
1,164
$
$
(16)
$
(32)
$
Changes in Registrants' cash flows from operations for 2019, 2018 and 2017 were generally consistent with changes in each Registrant’s respective results of
operations, as adjusted for non-cash operating activities, and changes in working capital in the normal course of business. In addition, significant operating cash
flow impacts for the Registrants for 2019, 2018 and 2017 were as follows:
114
(778)
(25)
(404)
(1,221)
14
(520)
2,133
22
41
589
(71)
240
Table of Contents
•
•
•
See Note 23 —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 13 —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.
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
Accumulated Benefit Obligation (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 beginning in 2020. 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 other postretirement 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 other postretirement plans in 2020:
Exelon
Generation
ComEd
PECO
BGE
PHI
Pepco
DPL
ACE
Qualified Pension Plans
Non-Qualified Pension Plans
OPEB
$
505 $
227
141
17
56
22
—
—
2
36 $
14
2
1
2
9
2
1
—
42
16
3
—
16
7
7
—
—
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.
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Cash Flows from Investing Activities
The following table provides a summary of the change in cash provided by (used in) investing activities for the years ended December 31, 2019, 2018 and 2017:
2019 vs. 2018 Variance
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
Other investing activities
Net cash flows provided by (used in) investing activities
2018 vs. 2017 Variance
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
Other investing activities
$
$
$
Net cash flows provided by (used in) investing activities
$
Exelon
Generation
ComEd
PECO
BGE
PHI
Pepco
DPL
ACE
$
346
199
113
(38)
—
(46)
574
$
$
397
199
113
(38)
—
(7)
664
$
211 $
—
—
—
—
—
211 $
$
(90)
—
—
—
(68)
(10)
(186)
$
—
—
—
—
(1)
(168)
$
(187)
$
20 $
—
—
—
—
(7)
13 $
30 $
—
—
—
—
1
31 $
16 $
—
—
—
—
(1)
15 $
(40)
—
—
—
—
(2)
(42)
Exelon
Generation
ComEd
PECO
BGE
PHI
Pepco
DPL
ACE
(10)
$
33
54
(128)
—
188
137
$
$
17
33
54
(128)
—
155
131
$
124 $
—
—
—
—
9
133 $
(117)
$
—
—
—
(131)
5
$
(77)
—
—
—
—
2
(243)
$
(75)
$
21 $
—
—
—
—
5
26 $
$
(28)
—
—
—
—
2
(26)
$
64 $
—
—
—
—
3
67 $
(23)
—
—
—
—
2
(21)
Significant investing cash flow impacts for the Registrants for 2019, 2018 and 2017 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.
During 2018, Exelon and Generation had expenditures of $81 million and $57 related to the acquisitions of the Everett Marine Terminal and the
Handley generating station.
During 2017, Exelon and Generation had expenditures of $23 million and $178 million related to the acquisitions of ConEdison Solutions and the
FitzPatrick nuclear generating station.
During 2018, Exelon and Generation had proceeds of $85 million relating to the sale of Generation’s interest in an electrical contracting business that
primarily installs, maintains and repairs underground and high-voltage cable transmission and distribution services.
During 2017, Exelon and Generation had proceeds of $218 million from sales of long-lived assets, primarily related to the sale back of turbine
equipment.
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 2020 are as follows:
(in millions)
Exelon
Generation
ComEd
PECO
BGE
Pepco
DPL
ACE
Transmission
Distribution
Gas
Total
N/A
N/A
475
125
275
175
125
150
N/A
N/A
1,875
700
575
675
225
225
N/A $
N/A
N/A
275
475
N/A
100
N/A
8,175
1,725
2,350
1,100
1,325
850
450
375
Projected capital expenditures and other investments are subject to periodic review and revision to reflect changes in economic conditions and other factors.
Generation
Approximately 45% of projected 2020 capital expenditures at Generation are for the acquisition of nuclear fuel, with the remaining amounts reflecting additions
and upgrades to existing generation facilities (including material condition improvements during nuclear refueling outages), and additional investment in new
generation facilities. Generation anticipates that it will fund capital expenditures with internally generated funds and borrowings.
Utility Registrants
Projected 2020 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. ComEd and 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. ComEd’s and PECO’s forecasted 2020 capital expenditures
above reflect capital spending for remediation to be completed through 2020. BGE, DPL and ACE are complete with their assessments and Pepco has
substantially completed its assessment and thus do not expect significant capital expenditures related to this guidance in 2020.
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
The following tables provides a summary of the change in cash provided by (used in) financing activities for the years ended December 31, 2019, 2018 and
2017:
2019 vs. 2018 Variance
Exelon
Generation
ComEd
PECO
BGE
PHI
Pepco
Changes in short-term borrowings, net
Long-term debt, net
Changes in Exelon intercompany money pool
Common stock issued from treasury stock
Dividends paid on common stock
Distributions to member
Contributions from parent/member
Sale of noncontrolling interest
Other financing activities
Net cash flows provided by (used in) financing activities
2018 vs. 2017 Variance
Changes in short-term borrowings, net
Long-term debt, net
Changes in Exelon intercompany money pool
Common stock issued from treasury stock
Dividends paid on common stock
Distributions to member
Contributions from parent/member
Sale of noncontrolling interest
Other financing activities
$
869
$
320
$
130
$
(665)
—
—
(76)
—
—
—
33
161
$
(645)
(146)
—
—
102
(114)
—
4
(110)
—
—
(49)
—
(250)
—
1
(479)
$
(278)
$
— $
125
—
—
(52)
—
99
—
16
188 $
82 $
100
—
—
(15)
—
84
—
(6)
200 $
28 $
(123)
12
—
—
(200)
13
—
4
(51)
—
—
(44)
—
(6)
—
1
245 $
(94)
$
(72)
$
DPL
ACE
272 $ (100)
(133)
—
—
(43)
—
(87)
—
1
10 $
63
—
—
(65)
—
108
—
2
8
$
$
127
$
599
—
(1,150)
(96)
—
—
(396)
(70)
Exelon
Generation
ComEd
PECO
BGE
PHI
699
$
— $
— $
Pepco
DPL
11 $ (432)
$
1 $
(510)
47
—
—
(342)
53
(396)
(1)
(65)
—
—
(37)
—
(151)
—
(2)
$
(74)
291
—
—
(11)
—
(75)
—
3
134 $
418
—
—
—
(15)
(373)
—
(7)
24 $
(125)
—
—
(18)
—
73
—
(19)
(89)
$
ACE
(77)
104
—
—
9
—
67
—
(3)
—
—
(36)
—
5
—
236
—
—
16
—
150
—
(3)
(2)
(3)
(26)
$
(32)
$
100
Net cash flows provided by (used in) financing activities
$
(986)
$
(450)
$
(255)
$
Significant investing cash flow impacts for the Registrants for 2019, 2018 and 2017 were as follows:
•
•
•
•
•
Changes in short-term borrowings, net, is driven by repayments on and issuances of notes due in less than 90 days. Refer to Note 16 - 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 more
information.
Changes in intercompany money pool are driven by short-term borrowing needs. Refer to more information regarding the intercompany money
pool below.
Exelon issued common stock in 2017 to fund the PHI merger. Refer to Note 19 - Shareholders' Equity of the Combined Notes to Consolidated
Financial statements for additional information on common stock issuances.
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 18 - Commitments and Contingencies of the Combined Notes to Consolidated Financial Statements for additional information on dividend
restrictions. See below for quarterly dividends declared.
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•
The change in sale of controlling interest from 2017 to 2018 was primarily related to cash received in 2017 for the sale of a 49% interest in EGRP.
Refer to Note 22 - Variable Interest Entities of the Combined Notes to Consolidated Financial Statements for additional information on sale of
controlling interest.
Debt Issuances and Redemptions
See Note 16 — Debt and Credit Agreements of the Combined Notes to Consolidated Financial Statements for additional information of the Registrants’ debt
issuances and retirements. Debt activity for 2019, 2018 and 2017 by Registrant was as follows:
During 2019, the following long-term debt was issued:
Company
Generation
Generation
Generation
ComEd
ComEd
PECO
BGE
Pepco
Pepco
DPL
ACE
ACE
Type
Interest Rate
Maturity
Amount
Use of Proceeds
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%
August 31, 2020
3.46%
May 1, 2020
2.53%
April 30, 2021
4.00%
March 1, 2049
3.20%
November 15, 2049
3.00%
September 15, 2049
3.20%
September 15, 2049
First Mortgage Bonds
3.45%
June 13, 2029
Unsecured Tax-Exempt
Bonds
First Mortgage Bonds
1.70%
September 1, 2022
4.14%
December 12, 2049
First Mortgage Bonds
3.50%
May 21, 2029
First Mortgage Bonds
4.14%
May 21, 2049
$
$
$
$
$
$
$
$
$
$
$
$
4
39
2
400
300
325
400
150
110
75
100
50
Funding to install energy conservation measures
for the Fort Meade project.
Funding to install energy conservation measures
for the Marine Corps. Logistics Project.
Funding to install energy conservation measures
for the Fort AP Hill project.
Repay a portion of ComEd’s outstanding
commercial paper obligations and fund other
general corporate purposes.
Repay a portion of ComEd’s outstanding
commercial paper obligations and fund other
general corporate purposes.
Repay short-term borrowings and for general
corporate purposes.
Repay commercial paper obligations and for
general corporate purposes.
Repay existing indebtedness and for general
corporate purposes.
Refinance existing indebtedness.
Repay existing indebtedness and for general
corporate purposes.
Repay existing indebtedness and for general
corporate purposes.
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.
119
Table of Contents
During 2018, the following long term debt was issued:
Company
Generation
Generation
Generation
Generation
Generation
ComEd
ComEd
PECO
PECO
PECO
BGE
Pepco
Pepco
DPL
ACE
Type
Interest Rate
Maturity
Amount
Use of Proceeds
Energy Efficiency Project
Financing(a)
Energy Efficiency Project
Financing(a)
Energy Efficiency Project
Financing(a)
Energy Efficiency Project
Financing(a)
Energy Efficiency Project
Financing(a)
First Mortgage Bonds,
Series 124
First Mortgage Bonds,
Series 125
First and Refunding
Mortgage Bonds
Loan Agreement
First and Refunding
Mortgage Bonds
3.72%
March 31, 2019
3.17%
January 31, 2019
2.61%
September 30, 2018
4.17%
January 31, 2019
4.26%
May 31, 2019
4.00%
March 1, 2048
3.70%
August 15, 2028
3.90%
March 1, 2048
2.00%
June 20, 2023
3.90%
March 1, 2048
Senior Notes
4.25%
September 15, 2048
First Mortgage Bonds
4.27%
June 15, 2048
First Mortgage Bonds
4.31%
November 1, 2048
First Mortgage Bonds
4.27%
June 15, 2048
First Mortgage Bonds
4.00%
October 15, 2028
$
$
$
$
$
$
$
$
$
$
$
$
$
$
$
4
1
5
1
3
800
550
325
50
325
300
100
100
200
350
Funding to install energy conservation measures
for the Smithsonian Zoo project.
Funding to install energy conservation measures in
Brooklyn, NY.
Funding to install energy conservation measures
for the Pensacola project.
Funding to install energy conservation measures
for the General Services Administration
Philadelphia project.
Funding to install energy conservation measures
for the National Institutes of Health Multi-Buildings
Phase II project.
Refinance one series of maturing first mortgage
bonds, to repay a portion of ComEd’s outstanding
commercial paper obligations and to fund general
corporate purposes.
Repay a portion of ComEd’s outstanding
commercial paper obligations and for general
corporate purposes.
Refinance a portion of maturing mortgage bonds.
Funding to implement Electric Long-term
Infrastructure Improvement Plan.
Satisfy short-term borrowings from the Exelon
intercompany money pool and for general
corporate purposes.
Repay commercial paper obligations and for
general corporate purposes.
Repay outstanding commercial paper and for
general corporate purposes.
Repay outstanding commercial paper and for
general corporate purposes.
Repay outstanding commercial paper and for
general corporate purposes.
Refinance ACE’s 7.75% First Mortgage Bonds due
November 15, 2018, reduce short-term borrowings
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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Table of Contents
During 2017, the following long term-debt was issued:
Company
Type
Interest Rate
Maturity
Exelon Corporate
Junior Subordinated Notes
3.50%
June 1, 2022
Generation
Generation
Generation
Generation
Generation
Generation
Albany Green Energy
Project Financing(a)
Energy Efficiency Project
Financing(a)
Energy Efficiency Project
Financing(a)
Energy Efficiency Project
Financing(a)
Energy Efficiency Project
Financing(a)
Senior Notes
LIBOR + 1.25%
November 17, 2017
3.90%
February 1, 2018
3.72%
May 1, 2018
2.61%
September 30, 2018
3.53%
April 1, 2019
2.95%
January 15, 2020
Generation
Senior Notes
3.40%
March 15, 2020
Generation
Generation
ComEd
ComEd
PECO
BGE
Pepco
Pepco
ExGen Texas Power
Nonrecourse Debt(b)(c)
ExGen Renewables IV,
Nonrecourse Debt(b)
First Mortgage Bonds,
Series 122
First Mortgage Bonds,
Series 123
First and Refunding
Mortgage Bonds
Senior Notes
LIBOR + 4.75%
September 18, 2021
LIBOR + 3.00%
November 30, 2024
2.95%
August 15, 2027
3.75%
August 15, 2047
3.70%
September 15, 2047
3.75%
August 15, 2047
Energy Efficiency Project
Financing(a)
First Mortgage Bonds
3.30%
December 15, 2017
4.15%
March 15, 2043
$
$
$
$
$
$
$
$
$
$
$
$
$
$
$
$
Amount
1,150
14
19
5
13
8
250
500
6
Use of Proceeds
Refinance Exelon's Junior Subordinated Notes
issued in June 2014.
Albany Green Energy biomass generation
development.
Funding to install energy conservation measures
for the Naval Station Great Lakes project.
Funding to install energy conservation measures
for the Smithsonian Zoo project.
Funding to install energy conservation measures
for the Pensacola project.
Funding to install energy conservation measures
for the State Department project.
Repay outstanding commercial paper obligations
and for general corporate purposes.
Repay outstanding commercial paper obligations
and for general corporate purposes.
General corporate purposes.
850
General corporate purposes.
350
650
325
300
2
200
Refinance maturing mortgage bonds, repay a
portion of ComEd’s outstanding commercial paper
obligations and for general corporate purposes.
Refinance maturing mortgage bonds, repay a
portion of ComEd’s outstanding commercial paper
obligations and for general corporate purposes.
General corporate purposes.
Redeem $250 million in principal amount of the
6.20% Deferrable Interest Subordinated
Debentures due October 15, 2043 issued by BGE's
affiliate BGE Capital Trust II, repay commercial
paper obligations and for general corporate
purposes.
Funding to install energy conservation measures
for the DOE Germantown project.
Funding to repay outstanding commercial paper
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.
(b) See Note 16 — Debt and Credit Agreements of the Combined Notes to Consolidated Financial Statements for additional information of nonrecourse debt.
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Table of Contents
(c) As a result of the bankruptcy filing for EGTP on November 7, 2017, the nonrecourse debt was deconsolidated from Exelon's and Generation's consolidated financial
statements. See Note 2 — Mergers, Acquisitions and Dispositions of the Combined Notes to Consolidated Financial Statements for additional information.
During 2019, the following long-term debt was retired and/or redeemed:
Company(a)
Type
Exelon
Generation
Generation
Generation
Generation
Generation
Generation
Generation
Generation
Generation
Generation
Generation
Generation
Generation
Generation
Generation
Generation
Generation
ComEd
Pepco
DPL
Long-Term Software License Agreement
Antelope Valley DOE Nonrecourse Debt(b)
Kennett Square Capital Lease
Continental Wind Nonrecourse Debt(b)
Pollution control notes
Renewable Power Generation Nonrecourse Debt(b)
Energy Efficiency Project Financing
ExGen Renewables IV Nonrecourse debt(b)
Hannie Mae, LLC Defense Financing
Energy Efficiency Project Financing
NUKEM
SolGen Nonrecourse Debt(b)
Energy Efficiency Project Financing
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%
Maturity
May 1, 2024
2.33% - 3.56%
January 5, 2037
7.83%
6.00%
2.50%
4.11%
3.46%
3mL +3%
4.12%
3.72%
3.15%
3.93%
4.17%
3.53%
4.26%
5.20%
3.17%
3.55%
2.15%
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
6.20% - 7.49%
2021 - 2022
7.61%
December 2, 2019
Amount
18
23
5
32
23
10
39
38
1
25
36
6
1
1
1
600
18
1
300
110
12
18
$
$
$
$
$
$
$
$
$
$
$
$
$
$
$
$
$
$
$
$
$
$
ACE
__________
(a) On January 15, 2020, Generation redeemed $1 billion of 2.95% Senior Notes at maturity.
(b) See Note 16 — Debt and Credit Agreements of the Combined Notes to Consolidated Financial Statements for additional information of nonrecourse debt.
October 20, 2023
5.55%
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During 2018, the following long-term debt was retired and/or redeemed:
Company
Type
Interest Rate
Maturity
Amount
Exelon Corporate Long-Term Software License Agreement
Generation
Generation
Generation
Generation
Generation
Generation
Generation
Generation
Generation
Generation
Generation
Generation
ComEd
ComEd
PECO
DPL
Pepco
Pepco
ACE
Naval Station Great Lakes Project Financing
Smithsonian Zoo Project Financing
Pensacola Project Financing
Fort Detrick Project Financing
Holyoke Nonrecourse Debt(a)
SolGen Nonrecourse Debt(a)
Antelope Valley DOE Nonrecourse Debt(a)
Continental Wind Nonrecourse Debt(a)
Renewable Power Generation Nonrecourse Debt(a)
Kennett Square Capital Lease
ExGen Renewables IV Nonrecourse Debt(a)
NUKEM
First Mortgage Bonds
Notes
First Mortgage Bonds
Medium Term Notes, Unsecured
Notes
Third Party Financing
First Mortgage Bonds
Transition Bonds
3.95%
3.90%
3.72%
2.61%
3.55%
5.25%
3.93%
2.29% - 3.56%
6.00%
4.11%
7.83%
3mL+300 bps
3.15% - 3.35%
5.80%
6.95%
5.35%
6.81%
3.30%
7.28-7.99%
7.75%
May 1, 2024
June 30, 2018
March 31, 2019
September 30, 2018
June 30, 2019
December 31, 2031
September 30, 2036
January 5, 2037
February 28, 2033
March 31, 2035
September 20, 2020
November 30, 2024
2018 - 2020
March 15, 2018
July 15, 2018
March 1, 2018
January 9, 2018
August 31, 2018
2021 - 2023
November 15, 2018
$
$
$
$
$
$
$
$
$
$
$
$
$
$
$
$
$
$
$
$
$
6
41
1
21
19
1
10
22
33
11
4
16
43
700
140
500
4
5
1
250
31
ACE
__________
(a) See Note 16 — Debt and Credit Agreements of the Combined Notes to Consolidated Financial Statements for additional information of nonrecourse debt.
5.05% - 5.55%
2020 - 2023
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During 2017, the following long-term debt was retired and/or redeemed:
Company
Type
Interest Rate
Maturity
Amount
Exelon Corporate Long-Term Software License Agreement
Exelon Corporate Senior Notes
Generation
Generation
Generation
Generation
Generation
Generation
Generation
Generation
Generation
Generation
Generation
Generation
Generation
ComEd
BGE
BGE
PHI
DPL
DPL
Pepco
Senior Notes - Exelon Wind
CEU Upstream Nonrecourse Debt(a)
SolGen Nonrecourse Debt(a)
Antelope Valley DOE Nonrecourse Debt(a)
Kennett Square Capital Lease
Continental Wind Nonrecourse Debt(a)
PES - PGOV Notes Payable
ExGen Texas Power Nonrecourse Debt (a)(b)
Renewable Power Generation Nonrecourse Debt(a)
NUKEM
ExGen Renewables I, Nonrecourse Debt(a)
Senior Notes
Albany Green Energy Project Financing
First Mortgage Bonds
Rate Stabilization Bonds
Capital Trust Preferred Securities
Senior Notes
Medium Term Notes, Unsecured
Variable Rate Demand Bonds
Third Party Financing
Transition Bonds
3.95%
1.55%
2.00%
May 1, 2024
June 9, 2017
July 31, 2017
LIBOR + 2.25%
January 14, 2019
3.93%
September 30, 2036
2.29% - 3.56%
January 5, 2037
7.83%
6.00%
September 20, 2020
February 28, 2033
6.70-7.60%
2017 - 2018
LIBOR + 4.75%
September 18, 2021
4.11%
3.25% - 3.35%
LIBOR + 4.25%
6.20%
March 31, 2035
June 30, 2018
February 6, 2021
October 1, 2017
LIBOR + 1.25%
November 17, 2017
6.15%
5.82%
6.20%
6.13%
7.56% - 7.58%
Variable
6.97% - 7.99%
September 15, 2017
April 1, 2017
October 15, 2043
June 1, 2017
February 1, 2017
October 1, 2017
2018 - 2022
$
$
$
$
$
$
$
$
$
$
$
$
$
$
$
$
$
$
$
$
$
$
$
24
550
1
6
2
22
2
31
1
665
14
23
233
700
212
425
41
258
81
14
26
1
ACE
__________
(a) See Note 16 — Debt and Credit Agreements of the Combined Notes to Consolidated Financial Statements for additional information of nonrecourse debt.
(b) As a result of the bankruptcy filing for EGTP on November 7, 2017, the nonrecourse debt was deconsolidated from Exelon's and Generation's consolidated financial
5.05% - 5.55%
2020 - 2023
35
statements. See Note 2 — Mergers, Acquisitions and Dispositions for additional information.
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.
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Table of Contents
Dividends
Quarterly dividends declared by the Exelon Board of Directors during the year ended December 31, 2019 and for the first quarter of 2020 were as follows:
Period
Declaration Date
Shareholder of Record Date
Dividend Payable Date
First Quarter 2019
Second Quarter 2019
Third Quarter 2019
Fourth Quarter 2019
February 5, 2019
February 20, 2019
April 30, 2019
July 30, 2019
May 15, 2019
August 15, 2019
November 1, 2019
November 15, 2019
March 8, 2019 $
Cash per Share(a)
0.3625
June 10, 2019 $
September 10, 2019 $
December 10, 2019 $
0.3625
0.3625
0.3625
First Quarter 2020
___________
(a) Exelon's Board of Directors approved an updated dividend policy providing an increase of 5% each year for the period covering 2018 through 2020, beginning with the
February 20, 2020
March 10, 2020 $
January 28, 2020
0.3825
March 2018 dividend.
Other
For the year ended December 31, 2019, other financing activities primarily consists of debt issuance costs. See Note 16 — Debt and Credit Agreements of the
Combined Notes to Consolidated Financial Statements’ for additional information.
Credit Matters
Market Conditions
The Registrants fund liquidity needs for capital investment, working capital, energy hedging and other financial commitments through 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 $7.4 billion was available to support additional commercial paper as of December 31, 2019, 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 market during 2019 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, 2019, it would have been required to provide incremental collateral of $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 $4.2 billion of available credit capacity of its revolver.
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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, 2019 and available credit facility capacity prior to any incremental collateral at December 31, 2019:
PJM Credit Policy
Collateral
Other Incremental Collateral
Required(a)
Available Credit Facility Capacity Prior to
Any Incremental Collateral
ComEd
PECO
BGE
Pepco
DPL
ACE
__________
(a) Represents incremental collateral related to natural gas procurement contracts.
Exelon Credit Facilities
$
11 $
—
11
11
4
—
— $
44
50
—
11
—
868
600
524
218
244
230
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 16 — 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.
Other Credit Matters
Capital Structure. At December 31, 2019, the capital structures of the Registrants consisted of the following:
Long-term debt
Long-term debt to
affiliates(a)
Common equity
Member’s equity
Commercial paper and
notes payable
__________
(a)
Exelon
Generation
ComEd
PECO
BGE
PHI
Pepco
DPL
ACE
50%
1%
47%
—%
2%
31%
44%
44%
47%
40%
49%
49%
4%
—%
64%
—%
55%
—%
2%
54%
—%
—%
52%
—%
—%
—
59%
—%
50%
—
—%
49%
—
1%
1
—%
1%
1%
1%
2%
50%
—%
47%
—
3%
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 22 — 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.
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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 15 —
Derivative Financial Instruments of the Combined Notes to Consolidated Financial Statements for additional information on collateral provisions.
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, 2019, are presented in the following tables:
Exelon Intercompany Money Pool
Contributed (borrowed)
Exelon Corporate
Generation
PECO
BSC
PHI Corporate
PCI
PHI Intercompany Money Pool
Contributed (borrowed)
Pepco
DPL
ACE
For the Year Ended December 31, 2019
Maximum
Contributed
Maximum
Borrowed
As of
December 31, 2019
Contributed (Borrowed)
$
$
467 $
212
164
18
—
60
For the Year Ended December 31, 2019
Maximum
Contributed
Maximum
Borrowed
63 $
3
—
127
— $
(235)
(85)
(383)
(12)
—
— $
(45)
(29)
121
—
68
(232)
(12)
55
—
—
—
As of
December 31, 2019
Contributed (Borrowed)
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Shelf Registration Statements. Exelon, Generation, ComEd, PECO, BGE, Pepco, DPL and ACE have a currently effective combined shelf registration
statement unlimited in amount, filed with the SEC, that will expire in August 2022. The ability of each Registrant to sell securities off the shelf registration
statement or to access the private placement markets will depend on a number of factors at the time of the proposed sale, including other required regulatory
approvals, as applicable, the current financial condition of the Registrant, its securities ratings and market conditions.
Regulatory Authorizations. ComEd, PECO, BGE, Pepco, DPL and ACE are required to obtain short-term and long-term financing authority from Federal and
State Commissions as follows:
Short-term Financing Authority(a)(b)
Long-term Financing Authority(a)
Commission
Expiration Date
Amount
Commission
Expiration Date
Amount (c)
ComEd(c)
PECO
BGE
Pepco
DPL
FERC
FERC
FERC
FERC
FERC
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
2021 & 2023
$
December 31, 2021
N/A
MDPSC / DCPSC
December 31, 2022
MDPSC / DPSC
December 31, 2022
1,893
1,575
—
1,200
475
NJBPU
ACE
__________
(a) Generation currently has blanket financing authority it received from FERC in connection with its market-based rate authority.
(b) On October 15, 2019, ComEd, BGE, Pepco and DPL filed applications with FERC and on September 12, 2019, ACE filed an application with NJBPU for renewal of their
short-term financing authority through December 31, 2021. ComEd, BGE, Pepco and DPL received approval on December 13, 2019 and ACE received approval on
December 6, 2019.
December 31, 2020
December 31, 2021
NJBPU
200
(c) As of December 31, 2019, ComEd had $393 million in new money long-term debt financing authority from the ICC with an expiration date of August 1, 2021. On January
22, 2020, ComEd had an additional $1.5 billion available in new money long-term debt financing authority from the ICC with an effective date of February 1, 2020 and an
expiration date of February 1, 2023.
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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, 2019 under existing contractual obligations, including
payments due by period.
Exelon
Long-term debt(a)
Interest payments on long-term debt(b)
Finance leases
Operating leases(c)
Purchase power obligations(d)
Fuel purchase agreements(e)
Electric supply procurement
Long-term renewable energy and REC commitments
Other purchase obligations(f)
DC PLUG obligation
SNF obligation
ZEC commitments
Pension contributions(g)
Total contractual obligations
Total
2020
2021 -
2022
2023 -
2024
2025
and beyond
Payment due within
$
35,910 $
4,704 $
4,594 $
2,442 $
22,608
1,356
2,586
2,357
40
1,361
1,201
6,217
2,049
2,284
8,308
130
1,199
1,313
3,030
6
144
312
1,209
1,310
254
6,189
30
—
164
505
11
267
672
1,852
731
534
1,139
60
—
328
1,010
9
197
198
1,380
8
448
274
40
—
328
1,010
24,170
16,309
14
753
19
1,776
—
1,048
706
—
1,199
493
505
$
85,650 $
16,183
$
13,784
$
8,691
$
46,992
__________
(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, 2019 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, 2019. 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 $143 million, $98 million, $55 million, $44 million,
$44 million and $223 million for 2020, 2021, 2022, 2023, 2024 and thereafter, respectively and $607 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.
(f) Represents the future estimated value at December 31, 2019 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 2025 are not included.
Generation
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Long-term debt
Interest payments on long-term debt(a)
Finance leases
Operating leases(b)
Purchase power obligations(c)
Fuel purchase agreements(d)
Other purchase obligations(e)
SNF obligation
Total contractual obligations
Total
2020
2021 -
2022
2023 -
2024
2025
and beyond
Payment due within
$
7,938 $
3,180 $
1,024 $
792 $
3,575
5
809
1,201
5,056
2,536
1,199
253
2
60
312
999
1,516
—
480
2
122
672
1,536
230
—
424
1
109
198
1,189
126
—
$
22,319 $
6,322
$
4,066
$
2,839
$
2,942
2,418
—
518
19
1,332
664
1,199
9,092
__________
(a)
Interest payments are estimated based on final maturity dates of debt securities outstanding at December 31, 2019 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, 2019.
(b) Capacity payments associated with contracted generation lease agreements are net of sublease and capacity offsets of $143 million, $98 million, $55 million, $44 million,
$44 million and $223 million for 2020, 2021, 2022, 2023, 2024 and thereafter, respectively and $607 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) Primarily represents commitments to purchase fuel supplies for nuclear and fossil generation, including those related to CENG.
(e) Represents the future estimated value at December 31, 2019 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.
ComEd
Long-term debt(a)
Interest payments on long-term debt(b)
Finance leases
Operating leases
Electric supply procurement
Long-term renewable energy and REC commitments
Other purchase obligations(c)
ZEC commitments
Total contractual obligations
Total
2020
2021 -
2022
2023 -
2024
2025
and beyond
Payment due within
$
8,783 $
6,918
500 $
345
350 $
674
250 $
665
8
12
617
1,986
1,262
1,313
—
3
403
222
1,219
164
—
6
214
470
36
328
—
2
—
384
5
328
7,683
5,234
8
1
—
910
2
493
$
20,899 $
2,856
$
2,078
$
1,634
$
14,331
__________
(a)
(b)
Includes amounts from ComEd financing trust.
Interest payments are estimated based on final maturity dates of debt securities outstanding at December 31, 2019 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, 2019. Includes estimated interest payments due to the
ComEd financing trust.
(c) Represents the future estimated value at December 31, 2019 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.
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PECO
Long-term debt(a)
Interest payments on long-term debt(b)
Operating leases
Fuel purchase agreements(c)
Electric supply procurement
Other purchase obligations(d)
Total contractual obligations
Total
2020
2021 -
2022
2023 -
2024
2025
and beyond
Payment due within
$
3,634 $
2,721
1
335
552
834
— $
650 $
141
—
116
441
727
274
1
154
111
107
50 $
254
—
31
—
—
2,934
2,052
—
34
—
—
$
8,077 $
1,425
$
1,297
$
335
$
5,020
__________
(a)
(b)
Includes amounts from PECO financing trusts.
Interest payments are estimated based on final maturity dates of debt securities outstanding at December 31, 2019 and do not reflect anticipated future refinancing, early
redemptions or debt issuances. Includes estimated interest payments due to the PECO financing trust.
(c) Represents commitments to purchase natural gas and related transportation, storage capacity and services.
(d) Represents the future estimated value at December 31, 2019 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.
BGE
Long-term debt
Interest payments on long-term debt(a)
Operating leases
Fuel purchase agreements(b)
Electric supply procurement
Other purchase obligations(c)
Total contractual obligations
Total
2020
2021 -
2022
2023 -
2024
2025
and beyond
Payment due within
$
3,300 $
2,241
100
522
1,050
1,014
— $
550 $
126
34
60
631
868
238
47
94
419
141
300 $
203
1
92
—
3
2,450
1,674
18
276
—
2
$
8,227 $
1,719
$
1,489
$
599
$
4,420
__________
(a)
Interest payments are estimated based on final maturity dates of debt securities outstanding at December 31, 2019 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, 2019 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.
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PHI
Long-term debt
Interest payments on long-term debt(a)
Finance leases
Operating leases
Fuel purchase agreements(b)
Long-term renewable energy and REC commitments
Electric supply procurement
Other purchase obligations(c)
DC PLUG obligation
Total contractual obligations
Total
2020
2021 -
2022
2023 -
2024
2025
and beyond
Payment due within
$
5,967 $
4,150
98 $
269
571 $
512
1,049 $
463
28
346
304
298
1,787
1,181
130
5
42
34
32
1,040
959
30
8
79
68
64
730
184
60
8
72
68
64
17
6
40
4,249
2,906
7
153
134
138
—
32
—
$
14,219 $
2,514 $
2,284 $
1,795 $
7,626
__________
(a)
Interest payments are estimated based on final maturity dates of debt securities outstanding at December 31, 2019 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, 2019 of the cash flows associated with all contracts, both cancellable and non-cancellable, entered into between
PHI 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.
Pepco
Total
2020
2021 -
2022
2023 -
2024
2025
and beyond
Payment due within
Long-term debt
Interest payments on long-term debt(a)
$
2,886 $
2,385
1 $
311 $
138
1
8
445
489
30
271
2
16
341
145
60
399 $
249
3
12
17
4
40
2,175
1,727
5
34
—
25
—
11
70
803
663
130
Finance leases
Operating leases
Electric supply procurement
Other purchase obligations(b)
DC PLUG obligation
Total contractual obligations
$
6,959 $
1,113 $
1,148 $
727 $
3,971
__________
(a)
Interest payments are estimated based on final maturity dates of debt securities outstanding at December 31, 2019 and do not reflect anticipated future refinancing, early
redemptions or debt issuances.
(b) Represents the future estimated value at December 31, 2019 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.
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DPL
Long-term debt
Interest payments on long-term debt(a)
Finance leases
Operating leases
Fuel purchase agreements(b)
Long-term renewable energy and associated REC commitments
Electric supply procurement
Other purchase obligations(c)
Total contractual obligations
Total
2020
2021 -
2022
2023 -
2024
2025
and beyond
Payment due within
$
1,568 $
1,087
10
91
304
298
458
280
78 $
60
2
11
34
32
288
262
— $
120
4
21
68
64
170
18
500 $
99
3
18
68
64
—
—
990
808
1
41
134
138
—
—
$
4,096 $
767 $
465 $
752 $
2,112
__________
(a)
Interest payments are estimated based on final maturity dates of debt securities outstanding at December 31, 2019 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, 2019 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.
ACE
Long-term debt
Interest payments on long-term debt (a)
Finance leases
Operating leases
Electric supply procurement
Other purchase obligations(b)
Total contractual obligations
Total
2020
2021 -
2022
2023 -
2024
2025
and beyond
Payment due within
$
1,327 $
19 $
260 $
150 $
503
8
20
526
200
57
1
5
307
185
93
2
8
219
15
87
2
5
—
—
898
266
3
2
—
—
$
2,584 $
574 $
597 $
244 $
1,169
__________
(a)
Interest payments are estimated based on final maturity dates of debt securities outstanding at December 31, 2019 and do not reflect anticipated future refinancing, early
redemptions or debt issuances.
(b) Represents the future estimated value at December 31, 2019 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.
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See Note 18 — 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
Finance Leases
Operating Leases
DC PLUG obligation
ZEC Commitments
REC Commitments
Long-term debt
Location within Notes to the Consolidated Financial Statements
Note 10 — Leases
Note 10 — Leases
Note 3 — Regulatory Matters
Note 3 — Regulatory Matters
Note 3 — Regulatory Matters & Note 15 — Derivative Financial Instruments
Note 16 — Debt and Credit Agreements
Interest payments on long-term debt
Note 16 — Debt and Credit Agreements
Pension contributions
SNF obligation
Note 14 — Retirement Benefits
Note 18 — Commitments and Contingencies
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.
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 2020 through 2022.
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, 2019, the percentage of expected generation hedged for the Mid-Atlantic, Midwest, New
York and ERCOT reportable segments is 91%-94% and 61%-64% for 2020 and 2021, respectively. 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 and BGE 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,
2019 market conditions and hedged position would be decreases in pre-tax net income of approximately $25 million and $331 million, respectively, for 2020 and
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 15 — 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 2020 through 2024 are supplied by three suppliers. In the event of non-performance by these or other suppliers, Generation believes that replacement
uranium concentrates can be obtained, although at prices that may be unfavorable when compared to the prices under the current supply agreements. Non-
performance by these counterparties could have a material adverse impact on Exelon’s and Generation’s financial statements.
Utility Registrants
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,
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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 15 — 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, 2017 to December 31, 2019. 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
15 — 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, 2019 and 2018.
Total mark-to-market energy contract net assets (liabilities) at December 31, 2017(a)
Total change in fair value during 2018 of contracts recorded in result of operations
Reclassification to realized at settlement of contracts recorded in results of operations
Contracts received at acquisition date(d)
Changes in fair value—recorded through regulatory assets and liabilities(b)
Changes in allocated collateral
Net option premium received
Option premium amortization
Upfront payments and amortizations(c)
Total mark-to-market energy contract net assets (liabilities) at December 31, 2018(a)
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 and liabilities(b)
Changes in allocated collateral
Net option premium paid
Option premium amortization
Upfront payments and amortizations(c)
Exelon
Generation
ComEd
$
667
$
923 $
(256)
270
(570)
(19)
8
(110)
43
(10)
20
299
(427)
226
(52)
572
29
(22)
(58)
270
(570)
(19)
—
(109)
43
(10)
20
548
(427)
226
—
572
29
(22)
(58)
—
—
—
7
—
—
—
—
(249)
—
—
(52)
—
—
—
—
Total mark-to-market energy contract net assets (liabilities) at December 31, 2019(a)
__________
$
567 $
868 $
(301)
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(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 or liabilities. As of December 31, 2018 and 2019, ComEd recorded a regulatory
liability of $249 million and $301 million, respectively, related to its mark-to-market derivative liabilities with Generation and unaffiliated suppliers. ComEd recorded $24
million of decreases in fair value and an increase for realized losses due to settlements of $17 million in purchased power expense associated with floating-to-fixed energy
swap suppliers for the year ended December 31, 2018. ComEd recorded $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.
Includes derivative contracts acquired or sold by Generation through upfront payments or receipts of cash, excluding option premiums, and the associated amortizations.
Includes fair value from contracts received at acquisition of the Everett Marine Terminal.
(c)
(d)
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 17 — 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.
Exelon
2020
2021
2022
2023
2024
2025 and Beyond
Total Fair
Value
Maturities Within
Normal Operations, Commodity derivative contracts(a)(b):
Actively quoted prices (Level 1)
$
(102) $
(33) $
(18) $
5 $
8 $
Prices provided by external sources (Level 2)
161
39
(9)
—
—
Prices based on model or other valuation methods (Level
3)(c)
Total
383
194
85
3
(18)
$
442 $
200 $
58 $
8 $
(10) $
— $
—
(131)
(131) $
(140)
191
516
567
__________
(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 $929 million at December 31,
2019.
Includes ComEd’s net assets (liabilities) associated with the floating-to-fixed energy swap contracts with unaffiliated suppliers.
(c)
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Generation
2020
2021
2022
2023
2024
2025 and Beyond
Total Fair
Value
Maturities Within
Normal Operations, Commodity derivative contracts(a)(b):
Actively quoted prices (Level 1)
$
(102) $
(33) $
(18) $
5 $
8 $
Prices provided by external sources (Level 2)
161
39
(9)
—
—
Prices based on model or other valuation methods (Level
3)
Total
415
223
113
30
10
$
474 $
229 $
86 $
35 $
18 $
— $
—
26
26 $
(140)
191
817
868
__________
(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 $929 million at December 31,
2019.
ComEd
Maturities Within
Commodity derivative contracts (a)
Prices based on model or other valuation methods (Level
3)(a)
__________
(a) Represents ComEd’s net liabilities associated with the floating-to-fixed energy swap contracts with unaffiliated suppliers.
(32) $
(29) $
(28) $
2022
2023
2021
2020
$
(27) $
2024
2025 and Beyond
Fair
Value
(28) $
(157) $
(301)
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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 15—Derivative Financial
Instruments of the Combined Notes to Consolidated Financial Statements for a detailed discussion of credit risk.
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, 2019. 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, 2019
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
877 $
79
218
139
20 $
63
—
23
1,313 $
106 $
857
16
218
116
1,207
— $
—
—
—
— $
—
—
—
—
—
Rating as of December 31, 2019
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
$
$
834 $
78
162
123
1,197 $
40 $
1
30
10
81 $
3 $
—
26
6
35 $
As of December 31, 2019
$
$
877
79
218
139
1,313
9
930
235
33
1,207
__________
(a) As of December 31, 2019, credit collateral held from counterparties where Generation had credit exposure included $25 million of cash and $81 million of letters of credit.
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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 a provision for uncollectible
accounts, based upon historical experience, 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 provision for uncollectible accounts. See Note 1 — Significant Accounting Policies
of the Combined Notes to Consolidated Financial Statements for the allowance for uncollectible accounts policy. The Utility Registrants did not have any
customers representing over 10% of their revenues as of December 31, 2019. See Note 3 — Regulatory Matters of the Combined Notes to Consolidated
Financial Statements for additional information.
As of December 31, 2019, ComEd, PECO, BGE, Pepco, DPL and ACE's net credit exposure to suppliers was immaterial. See Note 15 — 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 15 — Derivative Financial Instruments of the Combined Notes to Consolidated Financial Statements for additional
information regarding collateral requirements. See Note 18 — 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, 2019, 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 15 — 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.
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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.
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 $5 million decrease in Exelon pre-tax income for the year ended
December 31, 2019. 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 15—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, 2019,
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 10% increase in interest rates and decrease in equity prices would result in a $610 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, 2019 Compared to Year Ended December 31, 2018
A discussion of Generation’s results of operations for 2019 compared to 2018 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 16 — 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
other postretirement benefit 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, 2019 Compared to Year Ended December 31, 2018
A discussion of ComEd’s results of operations for 2019 compared to 2018 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, 2019, ComEd had access to a revolving credit facility with aggregate bank commitments of $1 billion.
See EXELON CORPORATION — Liquidity and Capital Resources and Note 16 — 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
other postretirement benefit 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, 2019 Compared to Year Ended December 31, 2018
A discussion of PECO’s results of operations for 2019 compared to 2018 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, 2019, PECO had access to a revolving credit facility with aggregate bank commitments of $600 million.
See EXELON CORPORATION — Liquidity and Capital Resources and Note 16 — 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
other postretirement benefit 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, 2019 Compared to Year Ended December 31, 2018
A discussion of BGE’s results of operations for 2019 compared to 2018 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, 2019, BGE had access to a revolving credit facility with aggregate bank commitments of $600 million.
See EXELON CORPORATION — Liquidity and Capital Resources and Note 16 — 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 other
postretirement benefit 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, 2019 Compared to Year Ended December 31, 2018
A discussion of PHI’s results of operations for 2019 compared to 2018 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 16 — 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 other
postretirement benefit 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, 2019 Compared to Year Ended December 31, 2018
A discussion of Pepco’s results of operations for 2019 compared to 2018 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, 2019, Pepco had access to a revolving credit facility with aggregate bank commitments of $300 million.
See EXELON CORPORATION — Liquidity and Capital Resources and Note 16 — 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
other postretirement benefit 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, 2019 Compared to Year Ended December 31, 2018
A discussion of DPL’s results of operations for 2019 compared to 2018 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, 2019, DPL had access to a revolving credit facility with aggregate bank commitments of $300 million.
See EXELON CORPORATION — Liquidity and Capital Resources and Note 16 — 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 other
postretirement benefit 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, 2019 Compared to Year Ended December 31, 2018
A discussion of ACE’s results of operations for 2019 compared to 2018 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, 2019, ACE had access to a revolving credit facility with aggregate bank commitments of $300 million.
See EXELON CORPORATION — Liquidity and Capital Resources and Note 16 — 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 other
postretirement benefit 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, 2019. 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, 2019, Exelon’s internal control over financial
reporting was effective.
The effectiveness of Exelon’s internal control over financial reporting as of December 31, 2019, 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, 2019. 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, 2019, 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, 2019. 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, 2019, 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, 2019. 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, 2019, 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, 2019. 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, 2019, 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, 2019. 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, 2019, 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, 2019. 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, 2019, 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, 2019. 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, 2019, 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, 2019. 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, 2019, ACE’s internal control over financial reporting
was effective.
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To the Board of Directors and Shareholders of Exelon Corporation
Opinions on the Financial Statements and Internal Control over Financial Reporting
Report of Independent Registered Public Accounting Firm
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, 2019, 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, 2019 and 2018, and the results of its operations and its cash flows for each of the three years in the period ended December 31, 2019 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, 2019, 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,
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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 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 9 to the consolidated financial statements, Exelon Generation 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, 2019, the nuclear decommissioning asset retirement
obligation was approximately $10.5 billion.
The principal considerations for our determination that performing procedures relating to Exelon Generation’s annual ARO assessment is a critical audit matter
are there was a significant amount of judgment by management when estimating its decommissioning obligation. This in turn led to significant auditor judgment,
subjectivity, and effort in performing procedures to evaluate management’s cash flow model and significant assumptions, including the decommissioning cost
studies. In addition, the audit effort involved the use of professionals with specialized skill and knowledge to assist in evaluating the audit evidence obtained from
these procedures.
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, including 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 11 to the consolidated financial statements, Exelon Generation 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
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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 undiscounted
expected future cash flows include significant unobservable inputs including revenue and generation forecasts and projected capital and maintenance
expenditures. As of December 31, 2019, the total carrying value of long-lived generation assets subject to this evaluation was approximately $24.2 billion.
The principal considerations for our determination that performing procedures relating to Exelon Generation’s impairment assessment of long-lived generation
assets is a critical audit matter are there was a significant amount of judgment by management in assessing the recoverability of these assets or asset groups.
This in turn led to significant auditor judgment, subjectivity and effort in performing procedures to evaluate the audit evidence related to the reasonableness of
management’s significant assumptions used in management's estimates, including revenue and generation forecasts. In addition, the audit effort involved the
use of professionals with specialized skills and knowledge to assist in evaluating the audit evidence obtained from these procedures.
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 of Exelon Generation’s long-lived generation assets or asset groups. These procedures also included, among others, testing
management’s process for developing undiscounted expected future cash flows for long-lived generation assets 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, including revenue and generation forecasts. Professionals with specialized skill and knowledge were used to assist in evaluating the
reasonableness of revenue forecasts.
Level 3 Derivatives Significant Assumptions
As described in Notes 1, 15 and 17 to the consolidated financial statements, Exelon Generation has derivative instruments that include both observable and
unobservable inputs. When valuing Level 3 derivatives, management utilizes various inputs and assumptions including forward commodity prices, commodity
price volatility, contractual volumes, delivery location, interest rates, credit quality of counterparties and credit enhancements. Those derivatives with significant
unobservable inputs are classified as Level 3. As of December 31, 2019, the Company had a level 3 fair value derivative asset position of $957 million and a
level 3 fair value derivative liability position of $140 million.
The principal considerations for our determination that performing procedures relating to the significant assumptions used to value Exelon Generation’s Level 3
derivatives is a critical audit matter are there was a significant amount of judgment by management in determining the inputs and assumptions used to estimate
the fair value of the Level 3 derivatives. This in turn led to significant auditor judgment, subjectivity, and effort in performing procedures to evaluate audit
evidence related to the reasonableness of management’s significant assumptions used in management’s estimates, including forward commodity prices. In
addition, the audit effort involved the use of professionals with specialized skill and knowledge to assist in evaluating the audit evidence obtained from these
procedures.
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 fair value of Level 3 derivatives. These procedures also included, among others, testing management’s process for valuing the Level 3
derivatives by evaluating the appropriateness of management’s model, testing the completeness and accuracy of data used by management, and evaluating the
reasonableness of management’s significant assumptions, including forward commodity prices. Professionals with specialized skill and knowledge were used to
assist in evaluating the reasonableness of forward commodity prices.
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
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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, 2019, there were $9.5 billion of regulatory assets and $10.4 billion of regulatory
liabilities.
The principal considerations for our determination that performing procedures relating to accounting for the effects of rate regulation is a critical audit matter are
there was a significant amount of judgment by management when assessing the impact of updates in regulation on accounting for new and existing regulatory
assets and liabilities and the evaluation of whether the regulatory assets and liabilities will be recovered and settled, respectively. This in turn led to significant
auditor judgment and audit effort to perform procedures relating to the accounting for the impact of regulatory and legislative proceedings on new and existing
regulatory assets and liabilities.
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 the implementation of new 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 new and updated regulatory guidance and proceedings and the related accounting implications, and
calculating regulatory assets and liabilities based on provisions and formulas outlined in rate orders and other correspondence with regulators.
/s/ PricewaterhouseCoopers LLP
Chicago, Illinois
February 11, 2020
We have served as the Company’s auditor since 2000.
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To the Board of Directors and Member of Exelon Generation Company, LLC
Opinion on the Financial Statements
Report of Independent Registered Public Accounting Firm
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, 2019 and 2018, and the results of its operations and its cash flows for each of the three years in the period ended
December 31, 2019 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.
/s/ PricewaterhouseCoopers LLP
Baltimore, Maryland
February 11, 2020
We have served as the Company's auditor since 2001.
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To the Board of Directors and Shareholders of Commonwealth Edison Company
Opinion on the Financial Statements
Report of Independent Registered Public Accounting Firm
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, 2019 and 2018, and the results of its operations and its cash flows for each of the three years in the period ended
December 31, 2019 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.
/s/ PricewaterhouseCoopers LLP
Chicago, Illinois
February 11, 2020
We have served as the Company's auditor since 2000.
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To the Board of Directors and Shareholder of PECO Energy Company
Opinion on the Financial Statements
Report of Independent Registered Public Accounting Firm
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, 2019 and 2018, and the results of its operations and its cash flows for each of the three years in the period ended December
31, 2019 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.
/s/ PricewaterhouseCoopers LLP
Philadelphia, Pennsylvania
February 11, 2020
We have served as the Company's auditor since 1932.
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To the Board of Directors and Shareholder of Baltimore Gas and Electric Company
Opinion on the Financial Statements
Report of Independent Registered Public Accounting Firm
We have audited the consolidated 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 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, 2019 and 2018, and the results of its operations and its cash flows for each of the three years in the
period ended December 31, 2019 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.
/s/ PricewaterhouseCoopers LLP
Baltimore, Maryland
February 11, 2020
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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To the Board of Directors and Member of Pepco Holdings LLC
Opinion on the Financial Statements
Report of Independent Registered Public Accounting Firm
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, 2019 and 2018, and the results of its operations and its cash flows for each of the three years in the period ended December 31,
2019 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.
/s/ PricewaterhouseCoopers LLP
Washington, DC
February 11, 2020
We have served as the Company's auditor since 2001.
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To the Board of Directors and Shareholder of Potomac Electric Power Company
Opinion on the Financial Statements
Report of Independent Registered Public Accounting Firm
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, 2019 and
2018, and the results of its operations and its cash flows for each of the three years in the period ended December 31, 2019 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.
/s/ PricewaterhouseCoopers LLP
Washington, DC
February 11, 2020
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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To the Board of Directors and Shareholder of Delmarva Power & Light Company
Opinion on the Financial Statements
Report of Independent Registered Public Accounting Firm
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, 2019 and
2018, and the results of its operations and its cash flows for each of the three years in the period ended December 31, 2019 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.
/s/ PricewaterhouseCoopers LLP
Washington, DC
February 11, 2020
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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To the Board of Directors and Shareholder of Atlantic City Electric Company
Opinion on the Financial Statements
Report of Independent Registered Public Accounting Firm
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, 2019 and 2018, and the results of its operations and its cash flows for each of the three years in the period ended
December 31, 2019 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.
/s/ PricewaterhouseCoopers LLP
Washington, DC
February 11, 2020
We have served as the Company's auditor since 1998.
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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
Bargain purchase gain
Gain on deconsolidation of business
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 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 gain on cash flow hedges
Unrealized gain on marketable securities
Unrealized gain on investments in unconsolidated affiliates
Unrealized gain (loss) on foreign currency translation
Other comprehensive income
Comprehensive income
Comprehensive 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
For the Years Ended December 31,
2019
2018
2017
17,754 $
16,839
(155)
34,438
19,168 $
16,879
(69)
35,978
10,849
4,648
8,615
4,252
1,732
30,096
31
—
1
11,679
4,991
9,337
4,353
1,783
32,143
56
—
—
4,374
3,891
(1,591)
(25)
1,227
(389)
3,985
774
(183)
3,028
92
(1,529)
(25)
(112)
(1,666)
2,225
118
(28)
2,079
74
2,936
$
2,005
$
17,394
15,964
200
33,558
9,668
4,367
10,025
3,828
1,731
29,619
3
233
213
4,388
(1,524)
(36)
947
(613)
3,775
(126)
(32)
3,869
90
3,779
3,028 $
2,079 $
3,869
(65)
149
(289)
—
—
1
6
(198)
2,830
93
2,737 $
973
1
974
(66)
247
(143)
12
—
2
(10)
42
2,121
75
2,046
$
967
2
969
3.02 $
2.07 $
(56)
197
10
3
6
4
7
171
4,040
88
3,952
947
2
949
3.99
$
$
$
$
$
Diluted
$
3.01
$
2.07 $
3.98
__________
(a)
The number of stock options not included in the calculation of diluted common shares outstanding due to their antidilutive effect was immaterial for the year ended December 31, 2019
and approximately 3 million and 8 million for the years ended December 31, 2018 and 2017, respectively.
See the Combined Notes to Consolidated Financial Statements
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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
Bargain purchase gain
Gain on deconsolidation of business
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
Other non-cash operating activities
Changes in assets and liabilities:
Accounts receivable
Inventories
Accounts payable and accrued expenses
Option premiums (paid) received, net
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
Proceeds from NDT fund sales
Investment in NDT funds
Reduction of restricted cash from deconsolidation of business
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
Retirement of long-term debt to financing trust
Common stock issued from treasury stock
Dividends paid on common stock
Proceeds from employee stock plans
Sale of noncontrolling interests
Other financing activities
Net cash flows (used in) provided by financing activities
(Decrease) increase in cash, cash equivalents and restricted cash
Cash, cash equivalents and restricted cash at beginning of period
Cash, cash equivalents and restricted cash at end of period
Supplemental cash flow information
For the Years Ended December 31,
2019
2018
2017
$
3,028 $
2,079 $
3,869
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
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
5,427
573
(3)
(233)
(213)
(362)
151
(616)
728
(470)
(72)
(388)
28
(158)
299
(405)
(675)
7,480
(7,584)
7,845
(8,113)
(87)
(208)
219
(43)
(7,260)
(7,834)
(7,971)
781
—
(125)
1,951
(338)
126
(1)
3,115
(1,287)
(1,786)
—
—
—
—
(1,408)
(1,332)
112
—
(82)
(58)
(659)
1,781
1,122
$
105
—
(108)
(219)
591
1,190
1,781
(261)
621
(700)
3,470
(2,490)
(250)
1,150
(1,236)
150
396
(83)
767
276
914
$
1,190
$
(Decrease) increase in capital expenditures not paid
Increase (decrease) in PPE related to ARO update
$
$
(7)
968
(69)
$
(107)
42
29
See the Combined Notes to Consolidated Financial Statements
179
Table of Contents
Exelon Corporation and Subsidiary Companies
Consolidated Balance Sheets
(In millions)
Current assets
Cash and cash equivalents
Restricted cash and cash equivalents
Accounts receivable, net
ASSETS
Customer (net of allowance for uncollectible accounts of $243 and $283 as of December 31, 2019 and
2018, respectively)
Other (net of allowance for uncollectible accounts of $48 and $36 as of December 31, 2019 and 2018,
respectively)
Mark-to-market derivative assets
Unamortized energy contract assets
Inventories, net
Fossil fuel and emission allowances
Materials and supplies
Regulatory assets
Assets held for sale
Other
Total current assets
Property, plant and equipment (net of accumulated depreciation and amortization of $23,979 and $22,902
as of December 31, 2019 and 2018, 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)
December 31,
2019
2018
$
587 $
358
4,592
1,583
679
47
312
1,456
1,170
—
1,253
12,037
80,233
8,335
13,190
464
6,677
508
336
3,197
32,707
1,349
247
4,607
1,256
804
48
334
1,351
1,190
904
1,238
13,328
76,707
8,237
11,661
625
6,677
452
372
1,575
29,599
119,634
See the Combined Notes to Consolidated Financial Statements
180
$
124,977
$
Table of Contents
Exelon Corporation and Subsidiary Companies
Consolidated Balance Sheets
(In millions)
LIABILITIES AND SHAREHOLDERS’ EQUITY
Current liabilities
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, 973 shares and 968 shares outstanding at
December 31, 2019 and 2018, respectively)
Treasury stock, at cost (2 shares at December 31, 2019 and 2018)
Retained earnings
Accumulated other comprehensive loss, net
Total shareholders’ equity
Noncontrolling interests
Total equity
Total liabilities and shareholders' equity
December 31,
2019
2018
$
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
714
1,349
3,800
2,112
5
644
475
149
344
777
1,035
11,404
34,075
390
11,321
9,679
3,988
1,928
1,171
9,559
479
463
2,130
40,718
86,587
19,116
(123)
14,743
(2,995)
30,741
2,306
33,047
$
124,977
$
119,634
__________
(a)
Exelon’s consolidated assets include $9,532 million and $9,667 million at December 31, 2019 and 2018, respectively, of certain VIEs that can only be used to settle the
liabilities of the VIE. Exelon’s consolidated liabilities include $3,473 million and $3,548 million at December 31, 2019 and 2018, respectively, of certain VIEs for which the
VIE creditors do not have recourse to Exelon. See Note 22–Variable Interest Entities for additional information.
See the Combined Notes to Consolidated Financial Statements
181
Table of Contents
Exelon Corporation and Subsidiary Companies
Consolidated Statements of Changes in Equity
Shareholders' Equity
Retained
Earnings
Accumulated
Other
Comprehensive
Loss
Noncontrolling
Interests
Total
Equity
(In millions, shares in thousands)
Balance, December 31, 2016
Net income
Long-term incentive plan activity
Employee stock purchase plan issuances
Common stock issued from treasury stock
Sale of noncontrolling interests
Changes in equity of noncontrolling interests
Common stock dividends
($1.31/common share)
Other comprehensive income (loss), net of income taxes
Impact of adoption of Reclassification of Certain Tax
Effects from AOCI standard
Issued
Shares
958,778 $
—
5,066
1,324
—
—
—
—
—
—
Common
Stock
18,794 $
—
56
150
—
(36)
—
Treasury
Stock
(2,327) $
—
—
—
2,204
—
—
—
—
—
—
—
—
Balance, December 31, 2017
965,168
$
18,964
$
(123)
$
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
—
3,534
1,318
—
—
—
—
—
—
41
105
6
—
—
—
—
—
—
—
—
—
—
—
—
Balance, December 31, 2018
970,020
$
19,116
$
(123)
$
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
—
3,111
1,285
—
—
—
—
—
40
112
6
—
—
—
—
—
—
—
—
—
—
12,042 $
3,779
—
—
(1,054)
—
—
(1,243)
—
539
$
14,063
2,005
—
—
—
—
(1,339)
—
14
14,743
2,936
—
—
—
—
(1,412)
—
Balance, December 31, 2019
974,416
$
19,274
$
(123)
$
16,267
$
(2,660)
$
—
—
—
—
—
—
—
173
(539)
1,780 $
90
—
—
—
443
(20)
—
(2)
—
(3,026)
$
2,291
$
—
—
—
—
—
—
41
(10)
74
—
—
—
(60)
—
1
—
—
—
—
—
—
—
(199)
(3,194)
$
92
—
—
—
(48)
—
(1)
2,349
$
27,629
3,869
56
150
1,150
407
(20)
(1,243)
171
—
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
$
(2,995)
$
2,306
$
See the Combined Notes to Consolidated Financial Statements
182
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
Bargain purchase gain
Gain on deconsolidation of business
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 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 gain on cash flow hedges
Unrealized gain on marketable securities
Unrealized gain on investments in unconsolidated affiliates
Unrealized gain (loss) on foreign currency translation
Other comprehensive income
Comprehensive income
Comprehensive income attributable to noncontrolling interests
Comprehensive income attributable to membership interest
For the Years Ended December 31,
2019
2018
2017
$
17,752 $
19,169 $
1,172
18,924
1,268
20,437
10,849
11,679
7
4,131
587
1,535
519
14
4,803
661
1,797
556
17,385
1,115
18,500
9,671
19
5,602
697
1,457
555
17,628
19,510
18,001
27
—
—
1,323
(394)
(35)
1,023
594
1,917
516
(184)
1,217
92
48
—
—
975
(396)
(36)
(178)
(610)
365
(108)
(30)
443
73
1,125
$
370
$
2
233
213
947
(401)
(39)
948
508
1,455
(1,376)
(33)
2,798
88
2,710
1,217 $
443 $
2,798
—
—
1
6
7
1,224
$
93
1,131 $
12
—
1
(10)
3
446
$
74
372 $
3
1
4
7
15
2,813
86
2,727
$
$
$
$
See the Combined Notes to Consolidated Financial Statements
183
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
Bargain purchase gain
Gain on deconsolidation of business
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
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) received, net
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
Proceeds from NDT fund sales
Investment in NDT funds
Reduction of restricted cash from deconsolidation of business
Proceeds from sales of assets and businesses
Acquisitions of assets and businesses, net
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
Changes in Exelon intercompany money pool
Distributions to member
Contributions from member
Sale of noncontrolling interests
Other financing activities
Net cash flows used in financing activities
(Decrease) increase in cash, cash equivalents and restricted cash
Cash, cash equivalents and restricted cash at beginning of period
Cash, cash equivalents and restricted cash at end of period
Supplemental cash flow information
For the Years Ended December 31,
2019
2018
2017
$
1,217 $
443 $
2,798
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
449
$
$
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
$
3,056
510
(2)
(233)
(213)
(2,023)
167
(616)
112
(320)
(7)
(29)
4
28
(129)
496
(148)
(152)
3,299
(2,259)
7,845
(8,113)
(87)
218
(208)
(58)
(2,662)
(620)
121
(200)
1,645
(1,261)
(1)
(659)
102
396
(54)
(531)
106
448
554
(Decrease) increase in capital expenditures not paid
Increase (decrease) in PPE related to ARO update
$
$
(34)
959
(199)
$
(130)
73
29
See the Combined Notes to Consolidated Financial Statements
184
Table of Contents
Exelon Generation Company, LLC and Subsidiary Companies
Consolidated Balance Sheets
(In millions)
Current assets
Cash and cash equivalents
Restricted cash and cash equivalents
Accounts receivable, net
ASSETS
Customer (net of allowance for uncollectible accounts of $80 and $103 as of December 31, 2019 and
2018, respectively)
Other (net of allowance for uncollectible accounts of $0 and $1 as of December 31, 2019 and 2018,
respectively)
Mark-to-market derivative assets
Receivables from affiliates
Unamortized energy contract assets
Inventories, net
Fossil fuel and emission allowances
Materials and supplies
Assets held for sale
Other
Total current assets
Property, plant and equipment (net of accumulated depreciation and amortization of $12,017 and $12,206
as of December 31, 2019 and 2018, 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,
2019
2018
$
303 $
146
750
153
2,893
2,941
619
675
190
47
236
1,026
—
941
7,076
24,193
13,190
235
47
508
1,438
336
12
1,960
17,726
562
804
173
49
251
963
904
883
8,433
23,981
11,661
414
47
452
1,421
371
21
755
15,142
47,556
See the Combined Notes to Consolidated Financial Statements
185
$
48,995
$
Table of Contents
Exelon Generation Company, LLC and Subsidiary Companies
Consolidated Balance Sheets
(In millions)
Current liabilities
Short-term borrowings
LIABILITIES AND EQUITY
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,
2019
2018
$
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
$
—
906
—
1,847
898
139
100
449
31
343
777
279
5,769
6,989
898
3,383
9,450
900
1,171
2,606
252
20
610
18,392
32,048
9,518
3,724
(38)
13,204
2,304
15,508
47,556
__________
(a) Generation’s consolidated assets include $9,512 million and $9,634 million at December 31, 2019 and 2018, respectively, of certain VIEs that can only be used to settle
the liabilities of the VIE. Generation’s consolidated liabilities include $3,429 million and $3,480 million at December 31, 2019 and 2018, respectively, of certain VIEs for
which the VIE creditors do not have recourse to Generation. See Note 22–Variable Interest Entities for additional information.
See the Combined Notes to Consolidated Financial Statements
186
Table of Contents
Exelon Generation Company, LLC and Subsidiary Companies
Consolidated Statements of Changes in Equity
Member’s Equity
(In millions)
Membership
Interest
Undistributed
Earnings
Accumulated
Other
Comprehensive
Loss, net
Noncontrolling
Interests
Total
Equity
Balance, December 31, 2016
$
9,261 $
Net income
Sale of noncontrolling interests
Changes in equity of noncontrolling interests
Distribution of net retirement benefit obligation to
member
Distributions to member
Contributions from member
Other comprehensive income (loss), net of
income taxes
—
(36)
—
33
—
99
—
2,298 $
2,710
—
—
—
(659)
—
—
(54)
$
1,779 $
—
—
—
—
—
—
17
88
443
(18)
—
—
—
(2)
13,284
2,798
407
(18)
33
(659)
99
15
Balance, December 31, 2017
$
9,357
$
4,349
$
(37)
$
2,290
$
15,959
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
—
6
—
—
155
—
—
Balance, December 31, 2018
$
9,518
$
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
—
7
—
—
41
—
370
—
—
(1,001)
—
—
6
3,724
$
1,125
—
—
(899)
—
—
—
—
—
—
—
2
(3)
73
—
(60)
—
—
1
—
(38)
$
2,304
$
—
—
—
—
—
6
92
—
(48)
—
—
(2)
443
6
(60)
(1,001)
155
3
3
15,508
1,217
7
(48)
(899)
41
4
Balance, December 31, 2019
$
9,566 $
3,950 $
(32)
$
2,346 $
15,830
See the Combined Notes to Consolidated Financial Statements
187
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,
2019
2018
2017
$
5,850 $
5,884 $
5,478
(29)
27
43
15
5,882
5,536
(133)
30
5,747
1,565
376
1,041
264
1,033
301
4,580
4
1,171
(346)
(13)
39
(320)
851
163
1,626
529
1,068
267
940
311
4,741
5
1,146
(334)
(13)
33
(314)
832
168
1,533
108
1,157
270
850
296
4,214
1
1,323
(348)
(13)
22
(339)
984
417
567
567
$
$
688 $
688 $
664 $
664 $
See the Combined Notes to Consolidated Financial Statements
188
Table of Contents
Commonwealth Edison 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, amortization and accretion
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 collateral received (posted), net and cash deposits
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, cash equivalents and restricted cash
Cash, cash equivalents and restricted cash at beginning of period
Cash, cash equivalents and restricted cash at end of period
Supplemental cash flow information
(Decrease) increase in capital expenditures not paid
Increase in PPE related to ARO update
For the Years Ended December 31,
2019
2018
2017
$
688 $
664 $
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
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
$
$
403 $
330 $
(37) $
7
11 $
7
567
850
659
164
(59)
8
4
(297)
(26)
(308)
(41)
6
1,527
(2,250)
20
(2,230)
—
1,000
(425)
(422)
651
(15)
789
86
58
144
(61)
—
See the Combined Notes to Consolidated Financial Statements
189
Table of Contents
Commonwealth Edison Company and Subsidiary Companies
Consolidated Balance Sheets
(In millions)
Current assets
Cash and cash equivalents
Restricted cash and cash equivalents
Accounts receivable, net
ASSETS
Customer (net of allowance for uncollectible accounts of $59 and $61 as of December 31, 2019 and
December 31, 2018, respectively)
Other (net of allowance for uncollectible accounts of $20 as of both December 31, 2019 and December
31, 2018, respectively)
Receivables from affiliates
Inventories, net
Regulatory assets
Other
Total current assets
Property, plant and equipment (net of accumulated depreciation and amortization of $5,168 and $4,684 as
of December 31, 2019 and December 31, 2018, 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
See the Combined Notes to Consolidated Financial Statements
190
December 31,
2019
2018
$
90 $
150
545
286
28
159
281
44
135
29
539
320
20
148
293
86
1,583
1,570
23,107
22,058
1,480
6
2,625
2,622
995
347
8,075
1,307
6
2,625
2,217
1,035
395
7,585
$
32,765 $
31,213
Table of Contents
Commonwealth Edison Company and Subsidiary Companies
Consolidated Balance Sheets
(In millions)
LIABILITIES AND SHAREHOLDERS’ EQUITY
Current liabilities
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 liability
Other
Total current liabilities
Long-term debt
Long-term debt to financing trust
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 liability
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, 2019
and 2018)
Other paid-in capital
Retained deficit unappropriated
Retained earnings appropriated
Total shareholders’ equity
December 31,
2019
2018
$
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
Total liabilities and shareholders’ equity
$
32,765 $
See the Combined Notes to Consolidated Financial Statements
191
—
300
607
373
119
111
293
26
96
1,925
7,801
205
3,813
118
201
6,050
223
630
11,035
20,966
1,588
7,322
(1,639)
2,976
10,247
31,213
Table of Contents
(In millions)
Common
Stock
Other
Paid-In
Capital
Retained Deficit
Unappropriated
Retained
Earnings
Appropriated
Total
Shareholders’
Equity
Commonwealth Edison Company and Subsidiary Companies
Consolidated Statements of Changes in Shareholders’ Equity
Balance, December 31, 2016
$
1,588 $
6,150 $
(1,639) $
2,626 $
Net income
Appropriation of retained earnings for future dividends
Common stock dividends
Contributions from parent
Parent tax matter indemnification
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
$
$
$
—
—
—
—
—
—
—
—
651
21
567
(567)
—
—
—
—
567
(422)
—
—
1,588 $
6,822 $
(1,639) $
2,771 $
—
—
—
—
—
—
—
500
664
(664)
—
—
—
664
(459)
—
8,725
567
—
(422)
651
21
9,542
664
—
(459)
500
1,588 $
7,322 $
(1,639) $
2,976 $
10,247
—
—
—
—
—
—
—
250
688
(688)
—
—
—
688
(508)
—
688
—
(508)
250
1,588 $
7,572 $
(1,639) $
3,156 $
10,677
See the Combined Notes to Consolidated Financial Statements
192
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,
2019
2018
2017
$
2,505 $
2,469 $
610
(21)
6
568
(7)
8
2,369
494
—
7
3,100
3,038
2,870
610
262
157
707
154
333
165
734
230
126
742
156
301
163
2,388
2,452
1
713
(124)
(12)
16
(120)
593
65
1
587
(115)
(14)
8
(121)
466
6
$
$
528
528
$
$
460
460
$
$
648
186
135
657
149
286
154
2,215
—
655
(115)
(11)
9
(117)
538
104
434
434
See the Combined Notes to Consolidated Financial Statements
193
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, amortization and accretion
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 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
Other financing activities
Net cash flows provided by (used in) financing activities
(Decrease) increase in cash, cash equivalents and restricted cash
Cash, cash equivalents and restricted cash at beginning of period
Cash, cash equivalents and restricted cash at end of period
Supplemental cash flow information
Increase (decrease) in capital expenditures not paid
For the Years Ended December 31,
2019
2018
2017
$
528 $
460 $
434
333
(1)
20
38
(29)
(5)
4
(11)
(34)
(28)
(64)
751
(939)
(68)
(1)
(1,008)
325
—
(358)
188
(6)
149
(108)
135
301
—
(5)
51
(74)
7
(14)
(3)
15
(28)
29
739
(849)
—
9
(840)
700
(500)
(306)
89
(22)
(39)
(140)
275
27
$
135
$
286
—
19
54
(44)
(6)
1
6
34
(24)
(5)
755
(732)
131
4
(597)
325
—
(288)
16
(3)
50
208
67
275
40 $
(12) $
22
$
$
See the Combined Notes to Consolidated Financial Statements
194
Table of Contents
PECO Energy Company and Subsidiary Companies
Consolidated Balance Sheets
(In millions)
Current assets
Cash and cash equivalents
Restricted cash and cash equivalents
Accounts receivable, net
ASSETS
Customer (net of allowance for uncollectible accounts of $55 and $53 as of December 31, 2019 and
2018, respectively)
Other (net of allowance for uncollectible accounts of $7 and $8 as of December 31, 2019 and 2018,
respectively)
Receivables from affiliates
Receivable from Exelon intercompany pool
Inventories, net
Fossil fuel
Materials and supplies
Regulatory assets
Other
Total current assets
December 31,
2019
2018
$
21 $
6
357
138
1
68
36
35
41
19
722
130
5
321
151
—
—
38
37
81
19
782
Property, plant and equipment (net of accumulated depreciation and amortization of $3,718 and $3,561 as
of December 31, 2019 and 2018, respectively)
9,292
8,610
Deferred debits and other assets
Regulatory assets
Investments
Receivables from affiliates
Prepaid pension asset
Other
Total deferred debits and other assets
Total assets
554
27
480
365
29
1,455
$
11,469
$
460
25
389
349
27
1,250
10,642
See the Combined Notes to Consolidated Financial Statements
195
Table of Contents
(In millions)
Current liabilities
Accounts payable
Accrued expenses
Payables to affiliates
Customer deposits
Regulatory liabilities
Other
PECO Energy Company and Subsidiary Companies
Consolidated Balance Sheets
LIABILITIES AND SHAREHOLDER'S EQUITY
December 31,
2019
2018
$
387 $
101
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, 2019 and
2018)
Retained earnings
Total shareholder's equity
Total liabilities and shareholder's equity
See the Combined Notes to Consolidated Financial Statements
196
$
11,469
$
55
69
91
19
722
3,405
184
2,080
28
288
510
74
2,980
7,291
2,766
1,412
4,178
370
113
59
68
175
24
809
3,084
184
1,933
27
288
421
76
2,745
6,822
2,578
1,242
3,820
10,642
Table of Contents
(In millions)
Balance, December 31, 2016
Net income
Common stock dividends
Contributions from parent
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
PECO Energy Company and Subsidiary Companies
Consolidated Statements of Changes in Shareholder's Equity
Common
Stock
Retained
Earnings
2,473 $
—
—
16
941 $
434
(288)
—
2,489
$
1,087
$
—
—
89
—
460
(306)
—
1
2,578
$
1,242
$
—
—
188
528
(358)
—
$
$
$
$
Accumulated
Other
Comprehensive
Income
Total
Shareholder's
Equity
1
$
—
—
—
1
$
—
—
—
(1)
—
—
—
—
$
3,415
434
(288)
16
3,577
460
(306)
89
—
3,820
528
(358)
188
4,178
2,766
$
1,412
$
—
$
See the Combined Notes to Consolidated Financial Statements
197
Table of Contents
Baltimore Gas and Electric 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
Other, net
Total other income and (deductions)
Income before income taxes
Income taxes
Net income
Comprehensive income
For the Years Ended December 31,
2019
2018
2017
$
2,368 $
2,428 $
2,384
700
12
26
738
(26)
29
652
124
16
3,106
3,169
3,176
585
181
286
600
160
502
260
671
254
257
615
162
483
254
2,574
2,696
—
532
(121)
—
28
(93)
439
79
1
474
(106)
—
19
(87)
387
74
360
360
$
313
313
$
$
566
183
384
563
153
473
240
2,562
—
614
(95)
(10)
16
(89)
525
218
307
307
See the Combined Notes to Consolidated Financial Statements
198
Table of Contents
Baltimore Gas and Electric 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
Impairment losses on long-lived assets and regulatory 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
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
Retirement of long-term debt
Retirement of long-term debt to financing trust
Dividends paid on common stock
Contributions from parent
Other financing activities
Net cash flows provided by financing activities
Increase (Decrease) in cash, cash equivalents and restricted cash
Cash, cash equivalents and restricted cash at beginning of period
Cash, cash equivalents and restricted cash at end of period
Supplemental cash flow information
Increase in capital expenditures not paid
$
$
See the Combined Notes to Consolidated Financial Statements
199
For the Years Ended December 31,
2019
2018
2017
$
360 $
313 $
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
483
—
76
58
8
12
2
(1)
4
(20)
(54)
(92)
789
(959)
9
(950)
(42)
300
—
—
(209)
109
(2)
156
(5)
18
25
$
13
$
307
473
7
145
65
(5)
(4)
(9)
(15)
—
60
(53)
(150)
821
(882)
7
(875)
32
300
(41)
(250)
(198)
184
(5)
22
(32)
50
18
6 $
50 $
23
Table of Contents
Baltimore Gas and Electric Company
Balance Sheets
(In millions)
Current assets
Cash and cash equivalents
Restricted cash and cash equivalents
Accounts receivable, net
ASSETS
Customer (net of allowance for uncollectible accounts of $12 and $16 as of December 31, 2019 and
2018, respectively)
Other (net of allowance for uncollectible accounts of $5 and $4 as December 31, 2019 and 2018,
respectively)
Receivables from affiliates
Inventories, net
Gas held in storage
Materials and supplies
Prepaid utility taxes
Regulatory assets
Other
Total current assets
December 31,
2019
2018
$
24 $
1
317
147
1
30
46
78
183
6
833
7
6
353
90
1
36
39
74
177
3
786
Property, plant and equipment (net of accumulated depreciation and amortization of $3,834 and $3,633 as
of December 31, 2019 and 2018, respectively)
8,990
8,243
Deferred debits and other assets
Regulatory assets
Investments
Prepaid pension asset
Other
Total deferred debits and other assets
Total assets
454
7
264
86
811
398
5
279
5
687
$
10,634
$
9,716
See the Combined Notes to Consolidated Financial Statements
200
Table of Contents
(In millions)
Current liabilities
Short-term borrowings
Accounts payable
Accrued expenses
Payables to affiliates
Customer deposits
Regulatory liabilities
Other
Baltimore Gas and Electric Company
Balance Sheets
LIABILITIES AND SHAREHOLDER'S EQUITY
December 31,
2019
2018
$
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
$
35
295
155
65
120
77
27
774
2,876
1,222
24
201
1,192
73
2,712
6,362
1,714
1,640
3,354
9,716
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(a) authorized, 0 shares(a) outstanding at December 31, 2019 and
2018)
Retained earnings
Total shareholder's equity
Total liabilities and shareholder's equity
_____________
(a)
In millions, shares round to zero. Number of shares is 1,500 authorized and 1,000 outstanding at December 31, 2019 and 2018.
See the Combined Notes to Consolidated Financial Statements
201
Table of Contents
(In millions)
Balance, December 31, 2016
Net income
Common stock dividends
Contributions from parent
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
Baltimore Gas and Electric Company and Subsidiary Companies
Consolidated Statements of Changes in Shareholder's Equity
Common
Stock
Retained
Earnings
1,421 $
1,427 $
—
—
184
307
(198)
—
1,605
$
1,536
$
—
—
109
313
(209)
—
1,714
$
1,640
$
—
—
193
360
(224)
—
1,907
$
1,776
$
$
$
$
$
Total
Shareholder's
Equity
2,848
307
(198)
184
3,141
313
(209)
109
3,354
360
(224)
193
3,683
See the Combined Notes to Consolidated Financial Statements
202
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, amortization and accretion
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 affiliates
Net income
Comprehensive income
For the Years Ended December 31,
2019
2018
2017
$
4,639 $
4,609 $
167
(14)
14
4,806
181
(7)
15
4,798
1,371
1,387
75
352
939
143
754
450
4,084
—
722
(263)
55
(208)
514
38
1
477
89
355
978
152
740
455
4,156
1
643
(261)
43
(218)
425
33
1
393
$
477 $
393 $
4,428
161
33
50
4,672
1,182
71
463
918
150
675
452
3,911
1
762
(245)
54
(191)
571
217
1
355
355
See the Combined Notes to Consolidated Financial Statements
203
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 (loss) to net cash from operating activities:
Depreciation and amortization
Impairment losses on intangibles and regulatory 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
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, cash equivalents and restricted cash
Cash, cash equivalents and restricted cash at beginning of period
Cash, cash equivalents and restricted cash at end of period
Supplemental cash flow information
Increase (decrease) in capital expenditures not paid
For the Years Ended
December 31,
2019
2018
2017
$
477 $
393 $
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 $
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
$
355
675
52
252
65
(26)
(2)
(37)
(106)
79
(99)
(258)
950
(1,396)
(1)
(1,397)
328
—
(500)
202
(169)
—
(311)
758
(2)
306
(141)
236
95
$
$
2 $
93 $
(12)
See the Combined Notes to Consolidated Financial Statements
204
Table of Contents
Pepco Holdings LLC and Subsidiary Companies
Consolidated Balance Sheets
(In millions)
Current assets
Cash and cash equivalents
Restricted cash and cash equivalents
Accounts receivable, net
ASSETS
Customer (net of allowance for uncollectible accounts of $37 and $50 as of December 31, 2019 and
2018, respectively)
Other (net of allowance for uncollectible accounts of $16 and $3 as of December 31, 2019 and 2018,
respectively)
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 $1,213 and $841 as
of December 31, 2019 and 2018, 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)
December 31,
2019
2018
$
131 $
36
479
174
1
8
190
412
49
1,480
14,296
2,061
135
4,005
406
13
323
124
43
453
177
—
9
163
457
75
1,501
13,446
2,312
130
4,005
486
12
60
7,005
21,952
$
6,943
22,719 $
See the Combined Notes to Consolidated Financial Statements
205
Table of Contents
Pepco Holdings LLC and Subsidiary Companies
Consolidated Balance Sheets
LIABILITIES AND EQUITY
(In millions)
Current liabilities
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,
2019
2018
$
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 $
179
125
496
256
94
—
116
84
119
123
1,592
6,134
2,137
52
103
1,864
442
369
4,967
12,693
9,220
39
9,259
21,952
_____________
(a)
PHI’s consolidated total assets include $20 million and $33 million at December 31, 2019 and 2018, respectively, of PHI's consolidated VIE that can only be used to
settle the liabilities of the VIE. PHI’s consolidated total liabilities include $44 million and $69 million at December 31, 2019 and 2018, respectively, of PHI's consolidated
VIE for which the VIE creditors do not have recourse to PHI. See Note 22 - Variable Interest Entities for additional information.
See the Combined Notes to Consolidated Financial Statements
206
Table of Contents
(In millions)
Balance, December 31, 2016
Net income
Distribution to member
Contributions from member
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
Pepco Holdings LLC and Subsidiary Companies
Consolidated Statements of Changes in Equity
Membership Interest
Undistributed
(Losses)/Gains
Total
Member's Equity
$
$
$
$
8,077 $
(72)
$
—
—
758
8,835
$
—
—
385
9,220
$
—
—
398
9,618
$
355
(311)
—
(28)
$
393
(326)
—
39
477
(526)
$
—
(10)
$
8,005
355
(311)
758
8,807
393
(326)
385
9,259
477
(526)
398
9,608
See the Combined Notes to Consolidated Financial Statements
207
Table of Contents
(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
Other, net
Total other income and (deductions)
Income before income taxes
Income taxes
Net income
Comprehensive income
Potomac Electric Power Company
Statements of Operations and Comprehensive Income
For the Years Ended December 31,
2019
2018
2017
$
2,258 $
2,233 $
2,126
(3)
5
(7)
6
19
6
2,260
2,232
2,151
401
264
273
209
374
378
1,899
—
361
(133)
31
(102)
259
16
243 $
243 $
448
206
275
226
385
379
1,919
—
313
(128)
31
(97)
216
11
205 $
205 $
359
255
396
58
321
371
1,760
1
392
(121)
32
(89)
303
105
198
198
$
$
See the Combined Notes to Consolidated Financial Statements
208
Table of Contents
Potomac Electric Power Company
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
Impairment losses on regulatory 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
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 (decrease) in cash, cash equivalents and restricted cash
Cash, cash equivalents and restricted cash at beginning of period
Cash, cash equivalents and restricted cash at end of period
Supplemental cash flow information
Increase in capital expenditures not paid
$
$
See the Combined Notes to Consolidated Financial Statements
209
For the Years Ended December 31,
2019
2018
2017
$
243 $
205 $
374
—
1
56
(22)
5
(19)
(39)
9
(14)
(82)
512
(626)
3
(623)
42
260
(125)
(213)
160
(3)
121
10
53
385
—
(20)
67
(5)
(17)
(6)
59
(13)
(17)
(164)
474
(656)
2
(654)
14
200
(14)
(169)
166
(4)
193
13
40
63 $
53 $
198
321
14
113
1
(20)
—
(24)
(63)
81
(72)
(142)
407
(628)
—
(628)
3
202
(13)
(133)
161
(1)
219
(2)
42
40
39 $
20 $
5
Table of Contents
(In millions)
Current assets
Cash and cash equivalents
Restricted cash and cash equivalents
Accounts receivable, net
ASSETS
Potomac Electric Power Company
Balance Sheets
December 31,
2019
2018
Customer (net of allowance for uncollectible accounts of $13 and $20 as of December 31, 2019 and
2018, respectively)
Other (net of allowance for uncollectible accounts of $7 and $1 as of December 31, 2019 and 2018,
respectively)
Receivables from affiliates
Inventories, net
Regulatory assets
Other
Total current assets
Property, plant and equipment (net of accumulated depreciation and amortization of $3,517 and $3,354 as
of December 31, 2019 and 2018, 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
210
$
$
30 $
33
231
91
—
112
188
11
696
6,909
584
110
296
66
1,056
8,661 $
16
37
225
81
1
93
238
37
728
6,460
643
105
316
15
1,079
8,267
Table of Contents
Potomac Electric Power Company
Balance Sheets
(In millions)
LIABILITIES AND SHAREHOLDER'S EQUITY
Current liabilities
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
Common stock ($0.01 par value, 200 shares authorized, 0 shares(a) outstanding at December 31, 2019 and
2018)
Retained earnings
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, 2019 and 2018.
See the Combined Notes to Consolidated Financial Statements
211
December 31,
2019
2018
$
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
$
40
15
214
126
62
54
7
38
30
42
628
2,704
1,055
37
29
822
275
2,218
5,550
1,636
1,081
2,717
8,267
Table of Contents
(In millions)
Balance, December 31, 2016
Net income
Common stock dividends
Contributions from parent
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
Potomac Electric Power Company
Statements of Changes in Shareholder's Equity
Common Stock
Retained Earnings
Total Shareholder's Equity
2,289
980 $
$
$
$
$
1,309 $
—
—
161
198
(133)
—
1,470 $
1,045 $
—
—
166
205
(169)
—
1,636 $
1,081 $
—
—
160
243
(213)
—
1,796 $
1,111 $
198
(133)
161
2,515
205
(169)
166
2,717
243
(213)
160
2,907
See the Combined Notes to Consolidated Financial Statements
212
Table of Contents
(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
Delmarva Power & Light Company
Statements of Operations and Comprehensive Income
For the Years Ended December 31,
2019
2018
2017
$
1,143 $
1,139 $
167
(11)
7
181
4
8
1,125
161
6
8
1,306
1,332
1,300
381
75
70
171
152
184
56
352
89
120
182
162
182
56
1,089
1,143
—
217
(61)
13
(48)
169
22
147
147
$
$
1
190
(58)
10
(48)
142
22
120
120
$
$
282
71
179
283
32
167
57
1,071
—
229
(51)
14
(37)
192
71
121
121
$
$
See the Combined Notes to Consolidated Financial Statements
213
Table of Contents
Delmarva Power & Light Company
Statements of Cash Flows
(In millions)
Cash flows from operating activities
Net income
Adjustments to reconcile net income (loss) to net cash flows provided by operating activities:
Depreciation and amortization
Impairment losses on regulatory 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
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
(Decrease) increase in cash, cash equivalents and restricted cash
Cash, cash equivalents and restricted cash at beginning of period
Cash, cash equivalents and restricted cash at end of period
Supplemental cash flow information
(Decrease) increase in capital expenditures not paid
$
$
See the Combined Notes to Consolidated Financial Statements
214
For the Years Ended December 31,
2019
2018
2017
$
147 $
120 $
184
—
(7)
27
(5)
(5)
(6)
3
12
(1)
(55)
294
(348)
1
(347)
56
75
(12)
(139)
63
(1)
42
(11)
24
182
—
24
24
8
(9)
(3)
11
2
—
(7)
352
(364)
2
(362)
(216)
200
(4)
(96)
150
(2)
32
22
2
13
$
24
$
121
167
6
89
9
(22)
11
(5)
(8)
26
(2)
(71)
321
(428)
(1)
(429)
216
—
(40)
(112)
—
—
64
(44)
46
2
(4) $
22 $
4
Table of Contents
Delmarva Power & Light Company
Balance Sheets
(In millions)
Current assets
Cash and cash equivalents
Restricted cash and cash equivalents
Accounts receivable, net
ASSETS
Customer (net of allowance for uncollectible accounts of $11 and $12 as of December 31, 2019 and
2018, respectively)
Other (net of allowance for uncollectible accounts of $4 and $1 as of December 31, 2019 and 2018,
respectively)
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 $1,425 and $1,329
as of December 31, 2019 and 2018, respectively)
Deferred debits and other assets
Regulatory assets
Goodwill
Prepaid pension asset
Other
Total deferred debits and other assets
Total assets
December 31,
2019
2018
$
13 $
—
141
38
8
44
18
52
11
325
4,035
222
8
171
69
470
23
1
134
46
9
37
17
59
10
336
3,821
231
8
186
6
431
See the Combined Notes to Consolidated Financial Statements
215
$
4,830
$
4,588
Table of Contents
Delmarva Power & Light Company
Balance Sheets
(In millions)
LIABILITIES AND SHAREHOLDER'S EQUITY
December 31,
2019
2018
Current liabilities
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
Commitments and contingencies
Shareholder's equity
Common stock ($2.25 par value, 0 shares(a) authorized, 0 shares(a) outstanding at December 31, 2019 and
2018, respectively)
Retained earnings
Total shareholder's equity
Total liabilities and shareholder's equity
$
$
56 $
80
112
46
32
36
37
15
414
1,487
655
16
574
104
1,349
3,250
977
603
1,580
4,830
$
—
91
111
39
33
35
59
7
375
1,403
628
17
606
50
1,301
3,079
914
595
1,509
4,588
_____________
(a)
In millions, shares round to zero. Number of shares is 1,000 authorized and 1,000 outstanding at December 31, 2019 and 2018.
See the Combined Notes to Consolidated Financial Statements
216
Table of Contents
(In millions)
Balance, December 31, 2016
Net income
Common stock dividends
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
Delmarva Power & Light Company
Statements of Changes in Shareholder's Equity
Common Stock
Retained Earnings
$
$
$
$
764 $
—
—
764 $
—
—
150
914 $
—
—
63
977 $
See the Combined Notes to Consolidated Financial Statements
217
Total Shareholder's Equity
1,326
562 $
121
(112)
571
$
120
(96)
—
595
$
147
(139)
—
603
$
121
(112)
1,335
120
(96)
150
1,509
147
(139)
63
1,580
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 affiliates
Operating and maintenance
Operating and maintenance from affiliates
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
Comprehensive income
For the Years Ended December 31,
2019
2018
2017
$
1,237 $
1,237 $
1,176
—
3
(4)
3
8
2
1,240
1,236
1,186
589
19
187
133
157
4
1,089
151
(58)
6
(52)
99
—
99
99
$
$
587
29
188
142
136
5
1,087
149
(64)
2
(62)
87
12
75
75
$
$
541
29
279
28
146
6
1,029
157
(61)
7
(54)
103
26
77
77
$
$
See the Combined Notes to Consolidated Financial Statements
218
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 (loss) to net cash from operating activities:
Depreciation and amortization
Impairment losses on regulatory 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
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
Decrease in cash, cash equivalents and restricted cash
Cash, cash equivalents and restricted cash at beginning of period
Cash, cash equivalents and restricted cash at end of period
Supplemental cash flow information
(Decrease) increase in capital expenditures not paid
For the Years Ended December 31,
2019
2018
2017
$
99 $
75 $
157
—
3
22
(13)
(6)
(1)
26
2
(1)
(27)
261
(375)
(1)
(376)
56
—
(125)
150
(18)
(124)
175
(1)
113
(2)
30
136
—
25
24
(8)
1
(4)
(7)
(2)
(6)
(6)
228
(335)
1
(334)
(94)
125
—
350
(281)
(59)
67
(3)
105
(1)
31
28
$
30
$
77
146
7
32
17
14
—
(7)
(2)
(11)
(20)
(47)
206
(312)
(1)
(313)
108
—
—
—
(35)
(68)
—
—
5
(102)
133
31
$
$
(29) $
46 $
(13)
See the Combined Notes to Consolidated Financial Statements
219
Table of Contents
Atlantic City Electric Company and Subsidiary Company
Consolidated Balance Sheets
(In millions)
Current assets
Cash and cash equivalents
Restricted cash and cash equivalents
Accounts receivable, net
ASSETS
Customer (net of allowance for uncollectible accounts of $13 and $18 as of December 31, 2019 and
2018, respectively)
Other (net of allowance for uncollectible accounts of $5 and $1 as of December 31, 2019 and 2018,
respectively)
Receivables from affiliates
Inventories, net
Regulatory assets
Other
Total current assets
Property, plant and equipment, (net of accumulated depreciation and amortization of $1,210 and $1,137
as of December 31, 2019 and 2018, respectively)
Deferred debits and other assets
Regulatory assets
Prepaid pension asset
Other
Total deferred debits and other assets
Total assets(a)
December 31,
2019
2018
$
12 $
2
108
48
4
34
57
5
270
3,190
368
52
53
473
7
4
95
55
1
33
40
5
240
2,966
386
67
40
493
3,699
See the Combined Notes to Consolidated Financial Statements
220
$
3,933
$
Table of Contents
Atlantic City Electric Company and Subsidiary Company
Consolidated Balance Sheets
(In millions)
LIABILITIES AND SHAREHOLDER'S EQUITY
Current liabilities
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, 2019 and 2018)
Retained earnings
Total shareholder's equity
Total liabilities and shareholder's equity
December 31,
2019
2018
$
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
$
139
18
154
35
28
26
18
4
422
1,170
535
17
402
27
981
2,573
979
147
1,126
3,699
_____________
(a)
ACE’s consolidated assets include $17 million and $23 million at December 31, 2019 and 2018, respectively, of ACE’s consolidated VIE that can only be used to settle
the liabilities of the VIE. ACE’s consolidated liabilities include $41 million and $59 million at December 31, 2019 and 2018, respectively, of ACE’s consolidated VIE for
which the VIE creditors do not have recourse to ACE. See Note 22 - Variable Interest Entities for additional information.
See the Combined Notes to Consolidated Financial Statements
221
Table of Contents
(In millions)
Balance, December 31, 2016
Net income
Common stock dividends
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
Atlantic City Electric Company and Subsidiary Company
Consolidated Statements of Changes in Shareholder's Equity
Common Stock
Retained Earnings
$
$
$
$
912 $
—
—
912
$
—
—
67
979
$
—
—
175
1,154
$
See the Combined Notes to Consolidated Financial Statements
222
Total Shareholder's Equity
1,034
122 $
77
(68)
131 $
75
(59)
—
147 $
99
(124)
—
122 $
77
(68)
1,043
75
(59)
67
1,126
99
(124)
175
1,276
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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
Transmission and distribution of electricity to retail customers
PECO Energy Company
Purchase and regulated retail sale of electricity and natural gas
Southeastern Pennsylvania, including the City of Philadelphia (electricity)
Transmission and distribution of electricity and distribution of natural gas to retail customers
Pennsylvania counties surrounding the City of Philadelphia (natural gas)
Baltimore Gas and Electric
Company
Purchase and regulated retail sale of electricity and natural gas
Central Maryland, including the City of Baltimore (electricity and natural gas)
Pepco Holdings LLC
Utility services holding company engaged, through its reportable segments Pepco, DPL and
ACE
Service Territories of Pepco, DPL and ACE
Transmission and distribution of electricity and distribution of natural gas to retail customers
Potomac Electric
Power Company
Delmarva Power & Light
Company
Purchase and regulated retail sale of electricity
District of Columbia, and major portions of Montgomery and Prince George’s
Counties, Maryland.
Transmission and distribution of electricity to retail customers
Purchase and regulated retail sale of electricity and natural gas
Portions of Delaware and Maryland (electricity)
Transmission and distribution of electricity and distribution of natural gas to retail customers
Portions of New Castle County, Delaware (natural gas)
Atlantic City Electric Company
Purchase and regulated retail sale of electricity
Transmission and distribution of electricity to retail customers
Portions of Southern New Jersey
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 above in the Index
to Combined Notes to Consolidated Financial Statements and 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.
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(Dollars in millions, except per share data unless otherwise noted)
Note 1 — Significant Accounting Policies
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 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 22 — 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 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, including certain financing trusts of ComEd and
PECO. 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 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 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. 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.
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, the application of purchase accounting, inventory reserves, allowance
for uncollectible accounts, goodwill and asset impairments, derivative instruments, unamortized energy contracts, fixed asset depreciation, environmental costs
and other loss contingencies, taxes and unbilled energy revenues. Actual results could differ from those estimates.
Prior Period Adjustments and Reclassifications (Exelon, PHI and Pepco)
In the fourth quarter 2019, management identified an error related to an overstatement of the regulatory asset associated with Pepco’s decoupling mechanism
for Maryland that originated in 2007 upon the inception of the program. Management has concluded that the error was not material to previously issued
consolidated financial statements and the error was corrected through a revision to Exelon’s, PHI’s and Pepco’s consolidated financial statements contained
herein for the years ended December 31, 2018 and 2017. The impact of the error correction was an $11 million reduction to Exelon’s, PHI’s and Pepco’s
opening Retained earnings as of January 1, 2017 with a corresponding reduction to current Regulatory assets of $18 million and Deferred income taxes and
unamortized investment tax credits of $7 million. In addition, Exelon’s, PHI’s and Pepco’s Total operating revenues decreased by $7 million for the years ended
December 31, 2018 and 2017 and Net income decreased by $5 million and $7 million for the years ended December 31, 2018 and 2017, respectively, from
originally reported amounts. The error did not impact net cash flows provided by operating activities, net cash flows used in investing activities or net cash flows
provided by financing activities for the years ended December 31, 2018 and 2017 for Exelon, PHI and Pepco. Exelon’s diluted earnings per share of common
stock remained unchanged from the originally reported amount for the year ended December 31, 2018. Exelon’s basic earnings per share of common stock for
the year ended December 31, 2018 and basic and diluted earnings per share of common stock for the year ended December 31, 2017 decreased by $0.01 from
the originally reported amount.
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(Dollars in millions, except per share data unless otherwise noted)
Note 1 — Significant Accounting Policies
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 settled 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 an offsetting regulatory asset or liability in its Consolidated Balance Sheets. See Note 3
— Regulatory Matters and Note 15 — 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
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(Dollars in millions, except per share data unless otherwise noted)
Note 1 — Significant Accounting Policies
state or local governments on the sale or distribution of gas and electricity. 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 23 — Supplemental Financial Information for Generation’s, ComEd’s, PECO’s, BGE’s, Pepco's, DPL's and ACE's utility taxes that
are presented on a gross basis.
Leases (All Registrants)
The Registrants recognize a ROU asset and lease liability for operating leases with a term of greater than one year. The ROU asset is included in Other deferred
debits and other assets and the lease liability is included in Other current liabilities and Other deferred credits and other liabilities 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.
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 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 10 — Leases for additional information.
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
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(Dollars in millions, except per share data unless otherwise noted)
Note 1 — Significant Accounting Policies
benefits in Interest expense or Other income and deductions (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, 2019 and 2018, 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, 2019 and 2018, 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 23 — Supplemental Financial Information for additional information.
Allowance for Uncollectible Accounts (All Registrants)
The allowance for uncollectible accounts reflects the Registrants’ best estimates of losses on the customers' accounts receivable balances. For Generation, the
allowance is based on accounts receivable aging historical experience and other currently available information. Utility Registrants estimate the allowance by
applying loss rates developed specifically for each company to the outstanding receivable balance by customer risk segment. Utility Registrants' customer
accounts are written off consistent with approved regulatory requirements. See Note 3 — Regulatory Matters for additional information regarding the regulatory
recovery of uncollectible accounts receivable at ComEd and ACE.
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
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(Dollars in millions, except per share data unless otherwise noted)
Note 1 — Significant Accounting Policies
liabilities of a consolidated VIE for which creditors do not have recourse to the general credit of the primary beneficiary.
See Note 22 — 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. Equity securities held in the NDT funds are classified as equity securities with readily
determinable fair values. 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 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. See Note 3 — Regulatory Matters for additional information regarding ComEd’s and PECO’s
regulatory assets and liabilities and Note 17 — Fair Value of Financial Assets and Liabilities and Note 9 — Asset Retirement Obligations for additional
information regarding marketable securities held by NDT funds.
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
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(Dollars in millions, except per share data unless otherwise noted)
Note 1 — Significant Accounting Policies
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 7 — Property, Plant and Equipment, Note 8 — Jointly Owned Electric Utility Plant and Note 23 — Supplemental Financial Information for additional
information regarding property, plant and equipment.
Nuclear Fuel (Exelon and Generation)
The cost of nuclear fuel is capitalized within Property, plant and equipment and charged to fuel expense using the unit-of-production method. 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 18 — 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. The Utility Registrants' 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. 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 6 — Early Plant Retirements for additional information on the impacts of expected and potential early plant retirements.
See Note 7 — 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.
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(Dollars in millions, except per share data unless otherwise noted)
Note 1 — Significant Accounting Policies
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 23 — 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 9 — Asset Retirement Obligations for
additional information.
Guarantees (All Registrants)
The Registrants recognize, at the inception of a guarantee, a liability for the fair market value of the obligations they have undertaken by issuing the guarantee,
including the ongoing obligation to perform over the term of the guarantee in the event that the specified triggering events or conditions occur.
The liability that is initially recognized at the inception of the guarantee 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 18 — 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 11 — 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 tested 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 12 — 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.
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(Dollars in millions, except per share data unless otherwise noted)
Note 1 — Significant Accounting Policies
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 decline is 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 hedges. See Note 3 — Regulatory Matters and Note 15 — 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 15 —
Derivative Financial Instruments for additional information.
Retirement Benefits (All Registrants)
Exelon sponsors defined benefit pension plans and OPEB plans for essentially all 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 14 — Retirement Benefits for additional information.
New Accounting Standards (All Registrants)
New Accounting Standards Adopted in 2019: In 2019, the Registrants adopted the following new authoritative accounting guidance issued by the FASB.
Cloud Computing Arrangements (Issued August 2018). Aligns the requirements for capitalizing costs incurred to implement a cloud computing arrangement with
the internal-use software guidance. As a result, certain implementation costs incurred in a cloud computing arrangement that are currently expensed as incurred
will be deferred and amortized over the non-cancellable term of the arrangement plus any reasonably certain renewal periods. The standard was effective
January 1, 2020 and can be applied using either a prospective or retrospective transition approach. A retrospective approach requires a cumulative-effect
adjustment to retained earnings as of
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Note 1 — Significant Accounting Policies
the beginning of the period of adoption. The Registrants early adopted this standard using a prospective approach as of January 1, 2019. The new guidance did
not have a material impact on the Registrants' financial statements.
Leases (Issued February 2016). The Registrants applied the new guidance with the following transition practical expedients:
•
•
•
a "package of three" expedients that must be taken together and allow entities to (1) not reassess whether existing contracts contain leases, (2) carry
forward the existing lease classification, and (3) not reassess initial direct costs associated with existing leases,
an implementation expedient which allows the requirements of the standard in the period of adoption with no restatement of prior periods, and
a land easement expedient which allows entities to not evaluate land easements under the new standard at adoption if they were not previously
accounted for as leases.
The standard resulted in the Registrants recording ROU assets and lease liabilities for operating leases in their Consolidated Balance Sheets but did not have a
material impact in the Registrants' Consolidated Statements of Operations and Comprehensive Income, Consolidated Statements of Cash Flows and
Consolidated Statements of Changes in Shareholders' Equity. The operating ROU assets and lease liabilities recognized upon adoption are materially consistent
with the balances presented in the Combined Notes to the Consolidated Financial Statements, excluding 2019 expense and payment activity. See Note 10 —
Leases for additional information.
New Accounting Standards Adopted as of January 1, 2020: The following new authoritative accounting guidance issued by the FASB was adopted as of
January 1, 2020 and will be reflected by the Registrants in their consolidated financial statements beginning in the first quarter of 2020.
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 test, which requires calculation
of a hypothetical purchase price allocation. Under the revised guidance, goodwill impairment will be measured as the amount by which a reporting unit’s carrying
value exceeds its fair value, not to exceed the carrying amount of goodwill (currently Step 1 of the two-step impairment test). Entities will continue to have the
option to perform a qualitative assessment to determine if a quantitative impairment test is necessary. The standard was effective January 1, 2020 and must be
applied on a prospective basis. Exelon, Generation, ComEd, PHI and DPL will apply the new guidance for their goodwill impairment assessments in 2020 and
do not expect the updated guidance to have a material impact to their financial statements.
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 interest in Nine Mile Point Unit 2. CENG is 100% consolidated in Exelon's and Generation's
financial statements. See Note 22 — Variable Interest Entities for additional information.
On April 1, 2014, Generation and EDF entered into various agreements including a Nuclear Operating Services Agreement, an amended LLC Operating
Agreement, an Employee Matters Agreement, and a Put Option Agreement, among others. Under the amended Operating Agreement, CENG made a $400
million special distribution to EDF
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Note 2 — Mergers, Acquisitions and Dispositions
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, 2019, the total unpaid aggregate preferred distributions and related return owed to Generation is $571
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, the FERC and the NRC. The process and regulatory approvals could take one to two years or more to complete.
Acquisition of James A. FitzPatrick Nuclear Generating Station (Exelon and Generation)
On March 31, 2017, Generation acquired the single-unit James A. FitzPatrick (FitzPatrick) nuclear generating station located in Scriba, New York from Entergy
Nuclear FitzPatrick LLC (Entergy) for a total purchase price of $289 million, which consisted of a cash purchase price of $110 million and a net cost
reimbursement to and on behalf of Entergy of $179 million. As part of the transaction, Generation received the FitzPatrick NDT fund assets and assumed the
obligation to decommission FitzPatrick. The NRC license for FitzPatrick expires in 2034. An after-tax bargain purchase gain of $233 million was included within
Exelon's and Generation's Consolidated Statements of Operations and Comprehensive Income which primarily reflects differences in strategies between
Generation and Entergy for the intended use and ultimate decommissioning of the plant.
Exelon and Generation incurred $57 million of merger and integration related costs for FitzPatrick for the year ended December 31, 2017 which are included
within Operating and maintenance expense in Exelon's and Generation's Consolidated Statements of Operations and Comprehensive Income.
Disposition of Oyster Creek (Exelon and Generation)
On July 31, 2018, Generation entered into an agreement with Holtec International (Holtec) and its indirect wholly owned subsidiary, Oyster Creek Environmental
Protection, LLC (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, 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.
As a result of the transaction, in the third quarter of 2018, Exelon and Generation reclassified certain Oyster Creek assets and liabilities in Exelon’s and
Generation’s Consolidated Balance Sheets as held for sale at their respective fair values. Exelon and Generation had $897 million and $777 million of Assets
and Liabilities held for sale, respectively, at December 31, 2018. 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 the third quarter of 2018 and in the second quarter of 2019, respectively. See
Note 9 — Asset Retirement Obligations for additional information.
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(Dollars in millions, except per share data unless otherwise noted)
Note 2 — Mergers, Acquisitions and Dispositions
Disposition of EGTP and Acquisition of Handley Generating Station (Exelon and Generation)
EGTP, a Delaware limited liability company, was formed in 2014 with the purpose of financing a portfolio of assets comprised of two combined-cycle gas
turbines (CCGTs) and three peaking/simple cycle facilities consisting of approximately 3.4 GW of generation capacity in ERCOT North and Houston Zones.
EGTP was an indirect wholly owned subsidiary of Exelon and Generation.
EGTP’s operating cash flows were negatively impacted by certain market conditions and the seasonality of its cash flows. On May 2, 2017, as a result of the
negative impacts of certain market conditions and the seasonality of its cash flows, EGTP entered into a consent agreement with its lenders to permit EGTP to
draw on its revolving credit facility and initiate an orderly sales process to sell the assets of its wholly owned subsidiaries. As a result, Exelon and Generation
classified certain of EGTP assets and liabilities as held for sale at their respective fair values less costs to sell and recorded a $460 million pre-tax impairment
loss. See Note 16 — Debt and Credit Agreements for details regarding the nonrecourse debt associated with EGTP and Note 11 — Asset Impairments for
additional information.
On November 7, 2017, EGTP and all of its wholly owned subsidiaries filed voluntary petitions for relief under Chapter 11 of Title 11 of the United States Code in
the United States Bankruptcy Court for the District of Delaware, which resulted in Exelon and Generation deconsolidating EGTP's assets and liabilities from their
consolidated financial statements in the fourth quarter of 2017 that resulted in a pre-tax gain upon deconsolidation of $213 million. Concurrently with the Chapter
11 filings, Generation entered into an asset purchase agreement to acquire one of EGTP's generating plants, the Handley Generating Station, subject to a
potential adjustment for fuel oil and assumption of certain liabilities. In the Chapter 11 Filings, EGTP requested that the proposed acquisition of the Handley
Generating Station be consummated through a court-approved and supervised sales process. The acquisition closed on April 4, 2018 for a purchase price of
$62 million. The Chapter 11 bankruptcy proceedings were finalized on April 17, 2018, resulting in the ownership of EGTP assets (other than the Handley
Generating Station) being transferred to EGTP's lenders.
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.
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(Dollars in millions, except per share data unless otherwise noted)
Note 3 — Regulatory Matters
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 and the Utility Registrants)
Distribution Base Rate Case Proceedings
The following tables show the completed and pending distribution base rate case proceedings in 2019.
Completed Distribution Base Rate Case Proceedings
Registrant/Jurisdiction
Filing Date
Requested Revenue
Requirement (Decrease)
Increase
Approved Revenue
Requirement (Decrease)
Increase
April 16, 2018
$
(23)
$
ComEd - Illinois
(Electric)(a)
ComEd - Illinois
(Electric)(a)
PECO - Pennsylvania
(Electric)
BGE - Maryland
(Natural Gas)
BGE - Maryland (Electric)
BGE - Maryland (Natural
Gas)
ACE - New Jersey
(Electric)
April 8, 2019
March 29, 2018
June 8, 2018
(amended
October 12,
2018)
May 24, 2019
(amended
December 17,
2019)
May 24, 2019
(amended
December 17,
2019)
August 21, 2018
(amended
November 19,
2018)
Approved ROE
Approval Date
Rate Effective Date
8.69%
December 4, 2018
January 1, 2019
8.91%
December 4, 2019
January 1, 2020
(24)
(17)
25
N/A
(b)
December 20, 2018
January 1, 2019
(6)
82
61
43
9.8%
January 4, 2019
January 4, 2019
74
59
18
9.7% (d)
December 17, 2019
45
9.75% (d)
December 17, 2019
December 17,
2019
December 17,
2019
122 (c)
70 (c)
9.6%
March 13, 2019
April 1, 2019
January 15, 2019
(amended May
16, 2019)
Pepco - Maryland
(Electric)
__________
(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. ComEd is
required to file an annual update to its electric distribution formula rate on or before May 1st, 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).
August 12, 2019
August 13, 2019
9.6%
27
10
ComEd’s 2018 approved revenue requirement above reflects a decrease of $58 million for the initial year revenue requirement for 2018 and an increase of $34 million
related to the annual reconciliation for 2017. The revenue requirement for 2018 and the annual reconciliation for 2017 provides for a weighted average debt and equity
return on distribution rate base of 6.52%
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(Dollars in millions, except per share data unless otherwise noted)
inclusive of an allowed ROE of 8.69%, reflecting the average rate on 30-year treasury notes plus 580 basis points. ComEd’s 2019 approved revenue requirement above
reflects an increase of $51 million for the initial year revenue requirement for 2019 and a decrease of $68 million related to the annual reconciliation for 2018. The revenue
requirement for 2019 and the annual reconciliation for 2018 provides for a weighted average debt and equity return on distribution rate base of 6.51% inclusive of an
allowed ROE of 8.91%, reflecting the average rate on 30-year treasury notes plus 580 basis points. See table below for ComEd's regulatory assets associated with its
electric distribution formula rate.
During the first quarter of 2018, ComEd revised its electric distribution formula rate to implement revenue decoupling provisions provided for under FEJA. As a result of
this revision, ComEd’s electric distribution formula rate revenues are not impacted by abnormal weather, usage per customer or numbers of customers. ComEd began
reflecting the impacts of this change in its Operating revenues and electric distribution formula rate regulatory asset in the first quarter of 2017.
Note 3 — Regulatory Matters
(b) The PECO rate case proceeding was resolved through a settlement agreement, which did not specify an approved ROE.
(c) Requested and approved increases are before New Jersey sales and use tax.
(d) ROEs in approved settlement are for the purpose of calculating AFUDC and carrying charges.
Pending Distribution Base Rate Case Proceedings
Registrant/Jurisdiction
Filing Date
Pepco - District of Columbia
(Electric)(a)
DPL - Maryland (Electric)
May 30, 2019 (amended
September 16, 2019)
$
December 5, 2019
Requested Revenue Requirement
Increase
Requested ROE
Expected Approval Timing
160
19
10.3%
10.3%
Fourth quarter of 2020
Third quarter of 2020
_________
(a) Reflects a three-year cumulative multi-year plan and total requested revenue requirement increases of $84 million, $40 million and $36 million for years 2020, 2021, and
2022, respectively, to recover capital investments made in 2018 and 2019 and planned capital investments from 2020 to 2022.
Transmission Formula Rates
Transmission Formula Rate (Exelon, ComEd, BGE, PHI, Pepco, DPL and ACE). ComEd’s, BGE’s, Pepco's, DPL's and ACE's transmission rates are each
established based on a FERC-approved formula. ComEd, BGE, Pepco, DPL and ACE are required to file an annual update to the FERC-approved formula on or
before May 15, with the resulting rates effective on June 1 of the same year. The annual 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 beginning
June 1 of the prior year and actual costs incurred for that year (annual reconciliation).
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Note 3 — Regulatory Matters
For 2019, the following total increases/(decreases) were included in ComEd’s, BGE’s, Pepco's, DPL's and ACE's electric transmission formula rate filings:
Registrant
$
ComEd(a)
BGE(a)
Pepco
DPL
Initial Revenue
Requirement
Increase/(Decrease)
Annual Reconciliation
(Decrease)/Increase
Total Revenue Requirement
Increase/(Decrease)
Allowed Return on
Rate Base(c)
Allowed ROE(d)
$
21
(10)
15
17
$
(16)
(23)
11
(1)
5
(19)
(b)
26
16
8.21%
7.35%
7.75%
7.14%
11.50%
10.50%
10.50%
10.50%
ACE
__________
(a) The time period for any formal challenges to the annual transmission formula rate update filings expired with no formal challenges submitted
(b) The change in BGE's transmission revenue requirement includes a FERC approved dedicated facilities charge of $14 million to recover the costs of providing transmission
10.50%
7.79%
(2)
11
9
service to specifically designated load by BGE.
(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 transmission rate case, the rate of return on common equity is 11.50%, 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%. 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.
Transmission Formula Rate (Exelon and PECO). On May 1, 2017, PECO filed a request with FERC seeking approval to update its transmission rates and
change the manner in which PECO’s transmission rate is determined from a fixed rate to a formula rate. The formula rate will be updated annually to ensure that
under this rate customers pay the actual costs of providing transmission services. PECO’s initial formula rate filing included a requested increase of $22
million to PECO’s annual transmission revenue requirement, which reflected a ROE of 11%, inclusive of a 50 basis point adder for being a member of a RTO.
On June 27, 2017, FERC issued an Order accepting the filing and suspending the proposed rates until December 1, 2017, subject to refund, and set the matter
for hearing and settlement judge procedures.
On December 5, 2019, FERC issued an Order accepting without modification the settlement agreement filed by PECO and other parties in July 2019. The
settlement results in an increase of approximately $14 million with a return on rate base of 7.62% compared to PECO's initial formula rate filing and allows for an
ROE of 10.35%, inclusive of a 50 basis point adder for being a member of the RTO. The settlement did not have a material impact on PECO's 2017, 2018, or
2019 annual transmission revenue requirements. PECO will update its rates in 2020 and refund estimated overcollections totaling approximately $28 million
related to the amounts billed under the proposed rates in effect since 2017.
Pursuant to the transmission formula rate request discussed above, PECO made its annual formula rate updates in May 2018 and 2019, which included a
decrease of $6 million and an increase of $8 million, respectively, to the annual transmission revenue requirement. The updated transmission formula rates were
effective on June 1, 2018 and 2019, respectively, subject to refund.
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 return on equity 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
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Note 3 — Regulatory Matters
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 1st 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.
During 2019, the ICC approved the following total increases in ComEd's requested energy efficiency revenue requirement:
Filing Date
May 23, 2019
$
Requested Revenue
Requirement Increase
Approved Revenue Requirement
Increase
Approved ROE
Approval Date
51 $
50 (a)
8.91%
November 26, 2019
Rate Effective Date
January 1, 2020
_________
(a) ComEd’s 2020 approved revenue requirement above reflects an increase of $53 million for the initial year revenue requirement for 2020 and a decrease of $3 million
related to the annual reconciliation for 2018. The revenue requirement for 2020 provides for a weighted average debt and equity return on the energy efficiency regulatory
asset and rate base of 6.51% inclusive of an allowed ROE of 8.91%, reflecting the average rate on 30-year treasury notes plus 580 basis points. See table below for
ComEd's regulatory assets associated with its energy efficiency formula rate.
Maryland Regulatory Matters
Maryland Alternative Rate Plans Rulemaking (Exelon, BGE, PHI, Pepco and DPL). On August 9, 2019, the MDPSC issued an order in which the MDPSC
determined that it is now appropriate to move forward to implement alternative rate plans in Maryland. The MDPSC found that a multi-year rate plan, based on a
historic test year and allowing up to three future test years, can produce just and reasonable rates. A working group was convened and submitted a detailed
implementation report related to multi-year rate plans to the MDPSC on December 20, 2019. In response to the working group report, the MDPSC issued an
order on February 4, 2020 establishing a multi-year rate plan pilot and an associated framework for a Maryland utility to use in the pilot multi-year rate plan filing.
The working group was required to continue and discuss how best to integrate performance-based measures into a multi-year rate plan. The working group is
currently discussing performance-based measures which could be combined with future multi-year rate plans and will submit its report to the MDPSC by April 1,
2020. BGE, Pepco and DPL cannot predict the outcome or the potential financial impact, if any, on BGE, Pepco or DPL.
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 Provider of Last Resort service, also known as Standard Offer Service (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. The appeal currently resides with the Maryland Court of Special 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 these appeals.
238
Table of Contents
Combined Notes to Consolidated Financial Statements
(Dollars in millions, except per share data unless otherwise noted)
Note 3 — Regulatory Matters
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 Infrastructure
Investment Program (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.
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 renewable energy portfolio standards. 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. ComEd, Pepco, DPL and ACE had similar transmission-related income tax
regulatory liabilities and assets also requiring FERC approval. 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. As a result of the FERC's order, ComEd, BGE, Pepco, DPL and
ACE took a charge to Income tax expense within their Consolidated Statements of Operations and Comprehensive Income in the fourth quarter of 2017,
reducing their associated transmission-related income tax regulatory assets for the portion of the total transmission-related income tax regulatory assets that
would have been previously amortized and recovered through rates. Similar regulatory assets and liabilities at PECO are not subject to the same FERC
transmission rate recovery formula. See above for additional information regarding PECO's transmission formula rate filing.
On December 18, 2017, BGE filed for clarification and rehearing of FERC’s November 16, 2017 order and 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 BGE’s December 18, 2017 request for rehearing and clarification and ComEd's, Pepco's, DPL's and
ACE's February 23, 2018 (as amended on July 9, 2018) filings, citing the lack of timeliness of the requests to recover amounts that would have been previously
amortized, but indicating that ongoing recovery of certain transmission-related income tax regulatory assets would provide for a more accurate revenue
requirement, consistent with its November 16, 2017 order.
On October 1, 2018, ComEd, BGE, Pepco, DPL, and ACE submitted filings to recover ongoing non-TCJA amortization amounts and refund TCJA transmission-
related income tax regulatory liabilities for the prospective period starting on October 1, 2018. In addition, on October 9, 2018, ComEd, Pepco, DPL, and ACE
sought rehearing of FERC's September 7, 2018 order. On November 2, 2018, BGE filed an appeal of FERC's September 7, 2018 order to the Court of Appeals
for the D.C. Circuit. On 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. ComEd, BGE, Pepco, DPL, and ACE cannot predict the outcome of these
proceedings.
If FERC ultimately rules that the future, ongoing non-TCJA amortization amounts are not recoverable, Exelon, ComEd, BGE, PHI, Pepco, DPL and ACE would
record additional charges to Income tax expense, which could be
239
Table of Contents
Combined Notes to Consolidated Financial Statements
(Dollars in millions, except per share data unless otherwise noted)
Note 3 — Regulatory Matters
up to approximately $79 million, $51 million, $17 million, $11 million, $4 million, $5 million and $2 million, respectively, as of December 31, 2019.
PJM Transmission Rate Design (All Registrants). On June 15, 2016, several parties, including the Utility Registrants, filed a proposed settlement with FERC
to resolve outstanding issues related to cost responsibility for charges to transmission customers for certain transmission facilities that operate at or above 500
kV. The settlement included provisions for monthly credits or charges related to the periods prior to January 1, 2016 that are expected to be refunded or
recovered through PJM wholesale transmission rates through December 2025. On May 31, 2018, FERC issued an order approving the settlement. Pursuant to
the order, similar charges for the period January 1, 2016 through June 30, 2018 would also be refunded or recovered through PJM wholesale transmission rates
over the subsequent 12-month period. PJM commenced billing the refunds and charges associated with this settlement in August 2018.
The Utility Registrants recorded the following payables to/receivables from PJM and related regulatory assets/liabilities in 2018 and have been refunding or
recovering these amounts through electric distribution customer rates. Generation recorded a $41 million net payable to PJM and a pre-tax charge within
Purchased power and fuel expense in Exelon's and Generation's Consolidated Statements of Operations and Comprehensive Income.
PJM Receivable
PJM Payable
Regulatory Asset
Regulatory Liability
$
220 $
176 $
136 $
Exelon
Generation(a)
ComEd
PECO
BGE
PHI
Pepco
DPL
—
122
85
—
13
—
10
41
—
—
51
84
84
—
—
—
—
51
85
84
—
1
221
—
122
85
—
14
—
10
4
ACE
__________
(a) Does not include an offsetting receivable from New Jersey Utilities of $16 million as of December 31, 2018.
—
3
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.
240
Table of Contents
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, 2019 and December 31, 2018:
December 31, 2019
Regulatory assets
Exelon
ComEd
PECO
BGE
PHI
Pepco
DPL
ACE
Pension and other postretirement benefits
$
2,784 $
— $
— $
— $
— $
— $
— $
Pension and other postretirement benefits -
Merger related
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
Securitized stranded costs
Removal costs
DC PLUG charge
Other
Total regulatory assets
Less: current portion
1,138
528
207
276
—
—
—
113
—
518
—
12
34
34
—
—
—
—
—
23
11
—
6
—
—
—
—
—
—
—
66
746
—
—
85
287
301
—
—
—
—
—
—
—
—
129
1,761
281
25
595
41
66
746
650
443
127
302
301
110
11
572
32
37
37
641
126
337
9,505
1,170
—
—
129
45
—
—
—
—
—
16
4
—
36
1
—
10
78
106
—
—
—
523
443
3
—
—
68
10
—
10
43
79
—
—
—
—
—
2
—
—
43
1
303
269
196
2
8
—
67
—
26
637
183
30
29
37
574
126
167
2,473
412
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 $
241
—
—
—
—
—
—
—
—
—
—
1
—
—
20
7
—
7
—
37
324
—
29
425
57
368
Table of Contents
Combined Notes to Consolidated Financial Statements
(Dollars in millions, except per share data unless otherwise noted)
Note 3 — Regulatory Matters
December 31, 2019
Exelon
ComEd
PECO
BGE
PHI
Pepco
DPL
ACE
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
$
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
December 31, 2018
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 other postretirement benefits $
2,553 $
— $
— $
— $
— $
— $
— $
Pension and other postretirement benefits
- Merger related
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
Securitized stranded costs
Removal costs
DC PLUG charge
Deferred storm costs
Other
Total regulatory assets
Less: current portion
1,266
414
234
328
—
—
—
136
—
404
—
24
158
158
—
—
—
—
—
22
17
—
49
—
1
—
—
—
—
—
—
81
472
—
—
79
309
249
—
6
—
—
—
—
—
—
—
110
1,600
293
24
541
81
81
472
702
561
118
326
249
193
41
545
42
27
50
564
159
41
303
9,427
1,190
—
—
145
48
—
—
—
—
—
16
—
—
51
4
—
10
89
120
—
—
—
569
561
1
—
—
93
31
—
10
50
90
—
—
—
—
—
1
—
—
84
10
289
255
188
3
2
—
—
—
—
17
575
177
39
25
50
564
159
41
162
2,769
457
18
25
—
158
159
9
79
881
238
—
—
39
30
—
—
—
—
—
—
—
—
—
14
67
11
—
—
97
—
4
28
290
59
Total noncurrent regulatory assets
$
8,237 $
1,307 $
460 $
398
$
2,312 $
643 $
231 $
243
—
—
—
—
—
—
—
—
—
—
—
—
—
9
7
—
10
—
50
309
—
28
13
426
40
386
Table of Contents
Combined Notes to Consolidated Financial Statements
(Dollars in millions, except per share data unless otherwise noted)
Note 3 — Regulatory Matters
December 31, 2018
Exelon
ComEd
PECO
BGE
PHI
Pepco
DPL
ACE
Regulatory liabilities
Deferred income taxes
Nuclear decommissioning
Removal costs
Electric Energy and Natural Gas Costs
Other
Total regulatory liabilities
Less: current portion
$
5,228 $
2,394 $
—
$
1,132 $
1,702 $
798 $
510 $
394
2,606
1,547
294
528
2,217
1,368
137
227
389
—
132
75
—
52
6
79
10,203
6,343
596 —
1,269
644
293
77
175
421
—
127
19
100
1,948
84
—
20
—
11
829
7
—
107
18
30
665
59
—
—
1
25
420
18
402
Total noncurrent regulatory liabilities
$
9,559 $
6,050 $
$
1,192
$
1,864 $
822 $
606 $
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 Other
Postretirement Benefits
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
other postretirement benefit 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 Other
Postretirement Benefits -
Merger Related
The deferred costs are amortized over the plan participants'
average remaining service periods subject to applicable
pension and other postretirement cost recognition policies. See
Note 14 – Retirement Benefits for additional information. The
capitalized non–service cost components are amortized over
the lives of the underlying assets.
244
The deferred costs are
amortized over the plan
participants' average remaining
service periods subject to
applicable pension and other
postretirement cost recognition
policies. See Note 14 –
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
No
No
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
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.
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.
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
Yes
BGE - 2026
Pepco - 2027
DPL - 2030
ComEd - 2028
PECO - 2020
AMI Programs - Legacy Meters Early retirement costs of legacy meters.
BGE - 2026
Pepco - 2027
DPL - 2030
Electric distribution formula
rate annual reconciliations
Electric distribution formula
rate significant one-time events
Energy Efficiency Costs
Under-recoveries related to electric distribution service costs
recoverable through ComEd's performance-based formula rate,
which is updated annually with rates effective on January 1st.
2021
Under-recoveries of electric 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.
2023
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.
2029
245
ComEd, Pepco (District of
Columbia), DPL (Delaware) -
Yes
PECO, BGE, Pepco
(Maryland), DPL (Maryland) -
No
Yes
Yes
Yes
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
Fair Value of Long-Term Debt
Fair Value of PHI’s
Unamortized Energy Contracts
Represents the difference between the carrying value and fair
value of long-term debt of PHI and BGE of $523 million and
$127 million, respectively, as of December 30, 2019 and $569
million and $133 million, respectively, as of December 30,
2018, as of the PHI and Constellation merger dates.
BGE - 2043
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
Asset Retirement Obligations
Future legally required removal costs associated with existing
asset retirement obligations.
Over the life of the related
assets.
MGP Remediation Costs
Environmental remediation costs for MGP sites.
Over the expected remediation
period. See Note 18 -
Commitments and
Contingencies for additional
information.
No
No
Yes, once the removal
activities have been
performed.
ComEd, PECO - No
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
DPL (Delaware), ACE - Yes
ComEd, PECO, BGE, Pepco,
DPL (Maryland) - No
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
June 1st.
2021
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 - 2024
BGE, Pepco, DPL - Yes
PECO - Yes on capital
investment recovered through
this mechanism
Pepco, DPL - 2034
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
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 $6 million
and $9 million, respectively as of December 31, 2019 and $9
million each as of December 31, 2018.
BGE - 2021
Pepco - 2021
DPL- 2023
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, Pepco and DPL - 2020
BGE, Pepco, DPL- No
Securitized Stranded Costs
Represents certain stranded costs associated with ACE's
former electricity generation business.
2022
Removal Costs
DC PLUG Charge
Deferred Storm Costs
Nuclear Decommissioning
For BGE, PHI, 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, PHI, 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.
BGE, PHI, Pepco, DPL and
ACE - Asset is generally
recovered over the life of the
underlining assets.
ComEd, BGE, PHI, Pepco and
DPL - The liability is reduced
as costs are incurred.
Yes
Yes
Costs associated with the District of Columbia Power Line
Undergrounding (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.
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.
Estimated future decommissioning costs for the Regulatory
Agreement Units that are less than the associated NDT fund
assets. See Note 9 - Asset Retirement Obligations for
additional information.
247
2020 - $30M
$67 million to be determined
based on future biennial plans
filed with the DCPSC.
Portion of asset funded by
Pepco-Yes
Pepco - 2024
DPL - 2023
ACE - 2022
Pepco, DPL - Yes
ACE - No
Not currently being refunded.
No
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, 2019
$
63 $
3 $
— $
53 $
7 $
4 $
3 $
—
Exelon
ComEd(a)
PECO
BGE(b)
PHI
Pepco(c)
DPL(c)
ACE
$
December 31, 2018
__________
(a) Reflects ComEd's unrecognized equity returns earned for ratemaking purposes on its electric distribution formula rate regulatory assets.
(b) BGE's authorized amounts capitalized for ratemaking purposes primarily relate to earnings on shareholders' investment on its AMI programs.
(c) Pepco's and DPL's authorized amounts capitalized for ratemaking purposes relate to earnings on shareholders' investment on their respective AMI Programs and Energy
—
49 $
65 $
— $
5 $
8 $
8 $
3 $
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.
On February 14, 2017, two lawsuits were filed in the Northern District of Illinois against the IPA alleging that the state’s ZEC program violates certain provisions
of the U.S. Constitution. Both lawsuits argued that the Illinois ZEC program would distort PJM's FERC-approved energy and capacity market auction system of
setting wholesale prices and sought a permanent injunction preventing the implementation of the program. The lawsuits were dismissed by the district court on
July 14, 2017. On September 13, 2018, the U.S. Circuit Court of Appeals for the Seventh Circuit affirmed the lower court's dismissal of both lawsuits. On January
7, 2019, plaintiffs filed a petition seeking U.S. Supreme Court review of the case, which was denied on April 15, 2019.
New Jersey Regulatory Matters
New Jersey Clean Energy Legislation. On May 23, 2018, New Jersey enacted legislation that established a ZEC program that will provide 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. Selected nuclear plants will receive annual ZEC payments for
each energy year (12-month period from June 1 through May 31) within 90 days after the completion of such energy year. The quantity of ZECs issued will be
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Note 3 — Regulatory Matters
determined based on the greater of 40% of the total number of MWh of electricity distributed by the public electric distribution utilities in New Jersey in the prior
year, or the total number of MWh of electricity generated in the prior year by the selected nuclear power plants. The ZEC price is approximately $10 per MWh
during the first 3-year eligibility period. For eligibility periods following the first 3-year eligibility period, the NJBPU has discretion to reduce the ZEC price.
On November 19, 2018, NJBPU issued an order providing for the method and application process for determining the eligibility of nuclear power plants, a draft
method and process for ranking and selecting eligible nuclear power plants, and the establishment of a mechanism for each regulated utility to purchase ZECs
from selected nuclear power plants. On December 19, 2018, PSEG filed complete applications seeking NJBPU approval for Salem 1 and Salem 2, of which
Generation owns a 42.59% ownership interest, to participate in the ZEC program. 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 $53
million for the year ended December 31, 2019. On May 15, 2019, New Jersey Rate Counsel appealed the NJBPU’s decision to the New Jersey Superior Court.
The appeal does not prevent implementation of the ZEC program. Exelon and Generation cannot predict the outcome of the appeal. See Note 6 - Early Plant
Retirements for additional information related to Salem.
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. The New York State Energy Research and
Development Authority (NYSERDA) centrally procures the ZECs through a 12-year contract extending from April 1, 2017 through March 31, 2029, administered
in six two-year tranches. ZEC payments are made based upon the number of MWh produced by each facility, subject to specified caps and minimum
performance requirements. The ZEC price for the first tranche was set at $17.48 per MWh of production and is administratively determined using a formula
based on the social cost of carbon as determined in 2016 by the federal government, subject to pricing adjustments designed to lower the ZEC price based on
increases in underlying energy and capacity prices. Following the first tranche, the price will be updated bi-annually. Each Load Serving Entity (LSE) is required
to purchase an amount of ZECs from NYSERDA equivalent to its load ratio share of the total electric energy in the New York Control Area. Cost recovery from
ratepayers is incorporated into the commodity charges on customer bills.
On October 19, 2016, a coalition of fossil-generation companies filed a complaint in federal district court against the NYPSC alleging that the ZEC program
violates certain provisions of the U.S. Constitution; specifically, that the ZEC program interferes with FERC’s jurisdiction over wholesale rates and that it
discriminates against out of state competitors, which was dismissed by the district court on July 25, 2017. On September 27, 2018, the U.S. Court of Appeals for
the Second Circuit affirmed the lower court's dismissal of the complaint against the ZEC program. On January 7, 2019, the fossil-generation companies filed a
petition seeking U.S. Supreme Court review of the case which was denied on April 15, 2019.
In addition, 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. Subsequently, Generation, CENG and the NYPSC filed
motions to dismiss the state court action, which were later opposed by the plaintiffs. 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 have until
May 4, 2020 to file their brief.
See Note 6 — Early Plant Retirements for additional information related to Ginna and Nine Mile Point, and Note 2 — Mergers, Acquisitions and Dispositions for
additional information on Generation's acquisition of FitzPatrick.
Ginna Nuclear Power Plant Reliability Support Services Agreement. In November 2014, in response to a petition filed by Ginna regarding the possible
retirement of Ginna, the NYPSC directed Ginna and Rochester Gas
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Note 3 — Regulatory Matters
& Electric Company (RG&E) to negotiate a RSSA to support the continued operation of Ginna to maintain the reliability of the RG&E transmission grid for a
specified period of time.
On April 8, 2016, FERC accepted Ginna’s compliance filing and on April 20, 2016, the NYPSC accepted the revised RSSA with a term expiring on March 31,
2017. In April 2016, Generation began recognizing revenue based on the final approved pricing contained in the RSSA and also recognized a one-time revenue
adjustment of $101 million representing the net cumulative previously unrecognized amount of revenue retroactive from the April 1, 2015 effective date through
March 31, 2016. A 49.99% portion of the one-time adjustment was removed from Generation’s results of operations as a result of the noncontrolling interests in
CENG.
The RSSA required Ginna to continue operating through the RSSA term. On September 30, 2016, Ginna filed the required notice with the NYPSC of its intent to
continue operating beyond the March 31, 2017 expiry of the RSSA, conditioned upon successful execution of an agreement between Ginna and NYSERDA for
the sale of ZECs under the New York CES. Subject to prevailing over any administrative or legal challenges, it is expected the New York CES will allow Ginna to
continue to operate through the end of its current operating license in 2029. See Note 6 — Early Plant Retirements for additional information regarding the
impacts of a decision to early retire a nuclear plant.
Federal Regulatory Matters
PJM and NYISO MOPR Proceedings. PJM and NYISO capacity markets include a Minimum Offer Price Rule (MOPR). If a resource is subjected to a MOPR,
its offer is adjusted to effectively remove the revenues it receives through a 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
continues to apply to certain new gas-fired resources.
In January 2017 and May 2018, EPSA filed pleadings at FERC that generally allege that the NYISO and PJM MOPRs should be expanded to apply to existing
resources including those receiving ZEC compensation under the New Jersey ZEC (Salem), New York CES (FitzPatrick, Ginna and Nine Mile Point) and Illinois
ZES (Quad Cities) programs. 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. Exelon filed protests at FERC in response to each filing, arguing generally that ZEC payments provide compensation for an environmental
attribute and are no different than other renewable support programs that have generally not been subject to a MOPR.
On December 19, 2019, FERC issued an order in the PJM MOPR proceeding that broadly applies the MOPR to all new and existing resources including
nuclear, renewables, demand response, energy efficiency, storage and all resources owned by vertically-integrated utilities, greatly expanding the breadth and
scope of PJM’s MOPR, effective as of PJM’s next capacity auction, the timing of which cannot be predicted at this time. FERC directed PJM to make a
compliance filing within 90 days. FERC has no deadline for acting on PJM’s compliance filing. While FERC included some limited exemptions (generally
available to existing renewable, energy efficiency, demand response, storage and existing vertically-integrated utility resources) in its order, no exemptions were
available to state-supported nuclear resources. In addition, 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. Unless Illinois and New Jersey can implement an FRR program in their PJM zones, the MOPR will apply 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, resulting in higher offers for those units
that may not clear the capacity market.
On January 21, 2020, Exelon, PJM and a number of other entities submitted individual requests for rehearing of FERC’s December 19, 2019 order on the PJM
MOPR. FERC routinely extends the deadline by which it must address requests for rehearing. FERC has not yet acted, and has no deadline by which it must
act, in the NYISO proceeding.
Exelon is currently working with PJM and other stakeholders to pursue the FRR option prior to the next capacity auction in PJM. If Illinois implements the FRR
option, Generation’s Illinois nuclear plants could be removed from PJM’s capacity auction and instead supply capacity and be compensated under the FRR
program, which has the potential to mitigate the current economic distress being experienced by Generation's nuclear plants in Illinois, as discussed in Note 6 —
Early Plant Retirements. Implementing the FRR program in Illinois will require both legislative
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Note 3 — Regulatory Matters
and regulatory changes. Legislation may be introduced in New Jersey as well. Exelon cannot predict whether such legislative and regulatory changes can be
implemented prior to the next capacity auction in PJM.
If Generation’s state-supported nuclear plants in PJM or NYISO are subjected to the MOPR without compensation under an FRR or similar program, it could
have a material adverse impact on Exelon's and Generation's financial statements.
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, 2019, $42 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.
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. Generation anticipates the second license renewal in the first half of 2020. Peach Bottom Units 2 and 3 are currently licensed to operate through 2033
and 2034, respectively. See Note 7 – Property, Plant and Equipment for additional information regarding the estimated useful life and depreciation provisions for
Peach Bottom.
PJM Transmission Rate Design. Refer to Other Federal Regulatory Matters above for additional information.
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(Dollars in millions, except per share data unless otherwise noted)
Note 4 — Revenue from Contracts with Customers
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 Registrant's 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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(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.
Delivery of electricity and/or natural
gas.
Revenues, and associated
costs, are recognized
throughout the contract term
using an input method to
measure progress towards
completion.(b)
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 30 or 45 days
from the invoice date.
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 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
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(Dollars in millions, except per share data unless otherwise noted)
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, 2019 and 2018. The Utility Registrants
do not incur any material costs to obtain or fulfill contracts with customers.
Note 4 — Revenue from Contracts with Customers
Contract Balances (All Registrants)
Contract Assets and Liabilities
Generation records contract assets for the revenue recognized on the construction and installation of energy efficiency assets and new power generating
facilities before Generation has an unconditional right to bill for and 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 Accounts receivable, net - Customer, respectively, within Exelon’s and Generation’s Consolidated Balance Sheets.
Generation records contract liabilities when consideration is received or due prior to the satisfaction of the performance obligations. These contract liabilities
primarily relate to upfront consideration received or due for equipment service plans, solar panel leases and the Illinois ZEC program that introduces a cap on
the total consideration to be received by Generation. 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. Generation records contract liabilities
within Other current liabilities and Other noncurrent liabilities within Exelon’s and Generation’s Consolidated Balance Sheets.
The following table provides a rollforward of the contract assets and liabilities reflected in Exelon's and Generation's Consolidated Balance Sheets from
January 1, 2018 to December 31, 2019:
Balance as of January 1, 2018
Consideration received or due
Revenues recognized
Balance at December 31, 2018
Consideration received or due
Revenues recognized
Balance at December 31, 2019
Contract Assets
Contract Liabilities
Exelon
Generation
Exelon
Generation
$
283 $
283 $
35 $
(146)
50
187
(143)
130
(146)
50
187
(143)
130
179
(187)
27
94
(88)
$
174 $
174 $
33 $
35
465
(458)
42
287
(258)
71
The Utility Registrants do not have any contract assets. The Utility Registrants also record contract liabilities when consideration is received prior to the
satisfaction of the performance obligations. As of December 31, 2019 and December 31, 2018, the Utility Registrants' contract liabilities were immaterial.
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, 2019. 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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Exelon
Generation
Combined Notes to Consolidated Financial Statements
(Dollars in millions, except per share data unless otherwise noted)
Note 4 — Revenue from Contracts with Customers
2020
2021
2022
2023
2024 and
thereafter
$
400 $
501
141 $
196
65 $
80
45 $
45
199 $
199
Total
850
1,021
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 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, the remaining portions of the SERC not included within MISO or PJM.
• West represents operations in the WECC, including California ISO.
•
Canada represents operations across the entire country of Canada and includes AESO, OIESO and the Canadian portion of MISO.
The CODMs for Exelon and Generation evaluate the performance of Generation’s electric business activities and allocate resources based on RNF. Generation
believes that RNF is a useful measurement of operational performance. RNF is not a presentation defined under GAAP and may not be comparable to other
companies’ presentations or deemed more useful than the GAAP information provided elsewhere in this report. Generation’s operating revenues include all
sales to third parties and affiliated sales to the Utility Registrants. Purchased power costs include all costs associated with the procurement and supply of
electricity including capacity, energy and ancillary services. Fuel expense includes the fuel costs for Generation’s owned generation and fuel costs associated
with tolling agreements. The results of Generation's other business activities are not regularly reviewed by the CODM and are therefore not classified as
operating segments or included in the regional reportable segment
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(Dollars in millions, except per share data unless otherwise noted)
Note 5 — Segment Information
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.
During the first quarter of 2019, due to a change in economics in our New England region, Generation changed the way that information is reviewed by the
CODM. The New England region is no longer regularly reviewed as a separate region by the CODM nor is it presented separately in any external information
presented to third parties. Information for the New England region is reviewed by the CODM as part of Other Power Regions. Exelon and Generation
retrospectively applied this change.
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, 2019, 2018, and 2017 is as follows:
Operating revenues(c):
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
$
Generation (a)
ComEd
PECO
BGE
PHI
Other (b)
Intersegment
Eliminations
Exelon
$
16,285 $
— $
— $
— $
— $
— $
(1,165) $
15,120
2,148
491
—
—
—
—
—
—
—
—
5,747
2,490
2,379
—
610
727
—
—
4,626
167
—
—
—
—
(1)
(4)
(47)
(15)
—
18,924 $
—
5,747 $
—
3,100 $
—
3,106 $
13
4,806 $
1,921
1,921 $
(1,934)
(3,166) $
2,147
487
15,195
1,489
—
34,438
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(Dollars in millions, except per share data unless otherwise noted)
Note 5 — Segment Information
Generation (a)
ComEd
PECO
BGE
PHI
Other (b)
Intersegment
Eliminations
Exelon
$
17,411 $
— $
— $
— $
— $
— $
(1,256) $
16,155
2,718
308
—
—
—
—
—
—
—
—
5,882
2,470
2,428
—
568
741
—
—
4,602
181
—
—
—
—
(8)
(5)
(45)
(20)
—
20,437 $
—
5,882 $
—
3,038 $
—
3,169 $
15
4,798 $
1,948
1,948 $
(1,960)
(3,294) $
2,710
303
15,337
1,470
3
35,978
15,332 $
— $
— $
— $
— $
— $
(1,105) $
14,227
2,575
593
—
—
—
—
—
—
—
—
5,536
2,375
2,489
—
495
687
—
—
4,462
161
—
—
—
—
—
(1)
(29)
(10)
—
18,500 $
—
5,536 $
—
2,870 $
—
3,176 $
49
4,672 $
1,831
1,831 $
(1,880)
(3,025) $
2,575
592
14,833
1,333
—
33,560
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
2017
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
$
Intersegment revenues(d):
2019
2018
2017
Depreciation and
amortization:
2019
2018
2017
$
$
1,172 $
1,269
1,110
30 $
27
15
1,535 $
1,797
1,457
1,033 $
940
850
26 $
29
16
502 $
483
473
6 $
8
7
333 $
301
286
257
14 $
15
50
1,913 $
1,942
1,824
(3,159) $
(3,289)
(3,020)
2
1
2
754 $
740
675
95 $
92
87
— $
—
—
4,252
4,353
3,828
Table of Contents
Combined Notes to Consolidated Financial Statements
(Dollars in millions, except per share data unless otherwise noted)
Note 5 — Segment Information
Generation (a)
ComEd
PECO
BGE
PHI
Other (b)
Intersegment
Eliminations
Exelon
17,628 $
19,510
18,001
4,580 $
4,741
4,214
2,388 $
2,452
2,215
2,574 $
2,696
2,562
4,084 $
4,156
3,911
1,996 $
1,929
1,742
(3,154) $
(3,341)
(3,026)
30,096
32,143
29,619
429 $
432
440
1,917 $
365
1,455
516 $
(108)
(1,376)
1,217 $
443
2,798
1,845 $
2,242
2,259
359 $
347
361
851 $
832
984
163 $
168
417
688 $
664
567
1,915 $
2,126
2,250
136 $
129
126
593 $
466
538
65 $
6
104
528 $
460
434
939 $
849
732
121 $
106
105
439 $
387
525
79 $
74
218
360 $
313
307
263 $
261
245
514 $
425
571
38 $
33
217
477 $
393
355
1,145 $
959
882
1,355 $
1,375
1,396
308 $
279
283
(327) $
(249)
(296)
(87) $
(55)
294
(240) $
(193)
(590)
49 $
43
65
— $
—
—
(2) $
(1)
(2)
— $
—
—
(2) $
(1)
(2)
— $
—
—
1,616
1,554
1,560
3,985
2,225
3,775
774
118
(126)
3,028
2,079
3,869
7,248
7,594
7,584
Operating expenses (c):
2019
2018
2017
Interest expense, net:
2019
2018
2017
Income (loss) before income
taxes:
2019
2018
2017
Income taxes:
2019
2018
2017
Net income (loss):
2019
2018
2017
Capital expenditures:
2019
2018
2017
Total assets:
2019
$
$
$
$
$
$
$
48,995 $
47,556
32,765 $
31,213
11,469 $
10,642
10,634 $
9,716
22,719 $
21,952
8,484 $
8,355
(10,089) $
(9,800)
124,977
119,634
2018
__________
(a) See Note 24 — Related Party Transactions for additional information on intersegment revenues.
(b) Other primarily includes Exelon’s corporate operations, shared service entities and other financing and investment activities.
(c)
(d)
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 23 — 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 authoritative guidance. For
Exelon, these amounts are included in Operating revenues in the Consolidated Statements of Operations and Comprehensive Income.
258
Table of Contents
PHI:
Operating revenues(a):
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
2017
Rate-regulated electric revenues
Rate-regulated natural gas revenues
Shared service and other revenues
Total operating revenues
Intersegment revenues:
2019
2018
2017
Depreciation and amortization:
2019
2018
2017
Operating expenses:
2019
2018
2017
Interest expense, net:
2019
2018
2017
Income (loss) before income taxes:
2019
2018
2017
Income taxes:
2019
2018
2017
Combined Notes to Consolidated Financial Statements
(Dollars in millions, except per share data unless otherwise noted)
Note 5 — Segment Information
Pepco
DPL
ACE
Other(b)
Intersegment
Eliminations
PHI
$
$
$
$
$
$
$
$
$
$
$
$
2,260 $
—
—
2,260 $
2,232 $
—
—
2,232 $
2,151 $
—
—
2,151 $
5 $
6
6
374 $
385
321
1,139 $
167
—
1,306 $
1,151 $
181
—
1,332 $
1,139 $
161
—
1,300 $
7 $
8
8
184 $
182
167
1,240 $
—
—
1,240 $
1,236 $
—
—
1,236 $
1,186 $
—
—
1,186 $
3 $
3
2
157 $
136
146
1,899 $
1,919
1,760
1,089 $
1,143
1,071
1,089 $
1,087
1,029
61 $
58
51
169 $
142
192
22 $
22
71
133 $
128
121
259 $
216
303
16 $
11
105
259
58 $
64
61
99 $
87
103
— $
12
26
— $
—
396
396 $
— $
—
435
435 $
— $
—
52
52 $
396 $
435
53
39 $
37
42
403 $
442
68
10 $
11
13
476 $
388
377
(1) $
(10)
15
$
(13)
—
(383)
4,626
167
13
(396)
$
4,806
$
(17)
—
(420)
4,602
181
15
(437)
$
4,798
$
(14)
—
(3)
4,462
161
49
(17)
$
4,672
(397)
$
(437)
(19)
— $
— $
$
(1)
14
15
50
754
740
675
(396)
(435)
(17)
$
$
$
4,084
4,156
3,911
1 $
— $
$
(1)
(489)
(408)
(404)
$
$
$
1 $
$
(2)
— $
263
261
245
514
425
571
38
33
217
Table of Contents
Combined Notes to Consolidated Financial Statements
(Dollars in millions, except per share data unless otherwise noted)
Net income (loss):
2019
2018
2017
Capital expenditures:
2019
2018
2017
Total assets:
2019
2018
Note 5 — Segment Information
Pepco
DPL
ACE
Other(b)
Intersegment
Eliminations
PHI
$
$
$
243 $
205
198
626 $
656
628
147 $
120
121
348 $
364
428
99 $
75
77
375 $
335
312
(26) $
(22)
(91)
6 $
20
28
14 $
15 $
50 $
— $
— $
—
477
393
355
1,355
1,375
1,396
8,661 $
8,267
4,830 $
4,588
3,933 $
3,699
11,105 $
10,819
(5,810) $
(5,421)
22,719
21,952
__________
(a)
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 23 — Supplemental Financial Information for additional information on total utility taxes.
(b) Other primarily includes PHI’s corporate operations, shared service entities and other financing and investment activities.
260
Table of Contents
Combined Notes to Consolidated Financial Statements
(Dollars in millions, except per share data unless otherwise noted)
Note 5 — Segment Information
The following tables disaggregate the Registrants' revenue recognized from contracts with customers into categories that depict how the nature, amount, timing,
and uncertainty of revenue and cash flows are affected by economic factors. For Generation, the disaggregation of revenues reflects Generation's two primary
products of power sales and natural gas sales, with further disaggregation of power sales provided by geographic region. For the Utility Registrants, the
disaggregation of revenues reflects the two primary utility services of rate-regulated 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):
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)
2019
Contracts with customers
$
5,053
$
4,095
1,571
768
3,687
15,174
1,446
440
17,060
Other(b)
Total
Intersegment Revenues
Total Revenues
17 $
5,070 $
4
$
232
25
229
608
4,327
1,596
997
4,295
1,111
16,285
702
51
2,148
491
(34)
—
16
(49)
(63)
62
1
1,864 $
18,924 $
— $
5,074
4,293
1,596
1,013
4,246
16,222
2,210
492
18,924
Revenues from external customers(a)
2018
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)
Contracts with customers
$
5,241 $
4,527
1,723
572
3,530
15,593
1,524
510
233 $
5,474 $
190
(36)
560
871
1,818
1,194
(202)
4,717
1,687
1,132
4,401
17,411
2,718
308
13
$
(11)
—
1
(66)
(63)
62
1
Total Generation Consolidated Operating Revenues
$
17,627 $
2,810 $
20,437 $
— $
261
5,487
4,706
1,687
1,133
4,335
17,348
2,780
309
20,437
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 external customers(a)
2017
Contracts with customers
$
5,523 $
Other(b)
Total
Intersegment Revenues
Total Revenues
(8) $
5,515 $
25
$
Mid-Atlantic
Midwest
New York
ERCOT
Other Power Regions
Total Competitive Businesses Electric Revenues
Competitive Businesses Natural Gas Revenues
Competitive Businesses Other Revenues(c)
3,923
1,605
641
2,658
14,350
1,658
744
283
(38)
317
428
982
917
(151)
4,206
1,567
958
3,086
15,332
2,575
593
(25)
(17)
4
(35)
(48)
53
(5)
5,540
4,181
1,550
962
3,051
15,284
2,628
588
18,500
Total Generation Consolidated Operating Revenues
$
16,752 $
1,748 $
18,500 $
— $
Includes all wholesale and retail electric sales to third parties and affiliated sales to the Utility Registrants.
Includes revenues from derivatives and leases.
__________
(a)
(b)
(c) Other represents activities not allocated to a region. See text above for a description of included activities. Includes a $38 million decrease to revenues for the amortization
of intangible assets and liabilities related to commodity contracts recorded at fair value in 2017, unrealized mark-to-market losses of $4 million, $262 million, and $131
million in 2019, 2018, and 2017, respectively, and elimination of intersegment revenues.
Revenues net of purchased power and fuel expense (Generation):
RNF from
external
customers(a)
2019
Intersegment
RNF
Mid-Atlantic
$
2,637
$
Midwest
New York
ERCOT
Other Power Regions
Total Revenues net of
purchased power and
fuel for Reportable
Segments
2,994
1,081
338
694
$
7,744
$
Total
RNF
2,655 $
2,962
1,094
308
620
18 $
(32)
13
(30)
(74)
RNF from
external
customers(a)
3,022
$
3,112
1,112
501
883
8,630
$
2018
Intersegment
RNF
51 $
23
10
(243)
(154)
Total
RNF
3,073 $
3,135
1,122
258
729
RNF from
external
customers(a)
3,105
$
2,810
1,007
575
1,014
8,511
$
2017
Intersegment
RNF
Total
RNF
109 $
10
1
(243)
(195)
$
(318)
318
3,214
2,820
1,008
332
819
8,193
$
(105)
105
7,639 $
429
$
(313)
313
8,317 $
427
324
Other (b)
Total Generation
Revenues net of
purchased power and
fuel expense
__________
(a)
(b) Other represents activities not allocated to a region. See text above for a description of included activities. Includes a $54 million decrease in RNF for the amortization of
intangible assets and liabilities related to commodity contracts in 2017, unrealized mark-to-market losses of $215 million, $319 million, and $175 million in 2019, 2018, and
2017, respectively, accelerated nuclear fuel amortization associated with the announced early plant retirements as discussed in Note 6 - Early Plant Retirements of $13
million, $57 million and $12 million in 2019, 2018, and 2017, respectively, and the elimination of intersegment RNF.
Includes purchases and sales from/to third parties and affiliated sales to the Utility Registrants.
8,068 $
8,744 $
— $
— $
— $
8,810
8,810
8,068
8,744
617
299
114
$
$
$
$
262
Table of Contents
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):
2019
Revenues from contracts with customers
ComEd
PECO
BGE
PHI
Pepco
DPL
ACE
Rate-regulated electric revenues
Residential
$
Small commercial & industrial
Large commercial & industrial
Public authorities & electric railroads
Other(a)
Total rate-regulated electric revenues(b)
Rate-regulated natural gas revenues
Residential
Small commercial & industrial
Large commercial & industrial
Transportation
Other(c)
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(e)
Other rate-regulated natural gas revenues(e)
Total other revenues
Total rate-regulated revenues for reportable
segments
2,916 $
1,463
540
47
888
5,854
—
—
—
—
—
—
1,596 $
404
219
29
249
2,497
409
169
1
25
6
610
1,326 $
254
436
27
321
2,364
474
77
132
—
31
714
2,316 $
505
1,112
61
650
4,644
96
44
5
14
7
166
1,012 $
149
833
34
227
2,255
—
—
—
—
—
—
645 $
186
99
14
204
1,148
96
45
5
14
7
167
659
170
180
13
218
1,240
—
—
—
—
—
—
5,854
3,107
3,078
4,810
2,255
1,315
1,240
(133)
26
—
(107)
(21)
13
1
(7)
12
12
4
28
(14)
10
—
(4)
(3)
8
—
5
(11)
2
—
(9)
—
—
—
—
$
5,747 $
3,100 $
3,106 $
4,806 $
2,260 $
1,306 $
1,240
263
Table of Contents
Combined Notes to Consolidated Financial Statements
(Dollars in millions, except per share data unless otherwise noted)
Note 5 — Segment Information
2018
Revenues from contracts with customers
ComEd
PECO
BGE
PHI
Pepco
DPL
ACE
Rate-regulated electric revenues
Residential
$
Small commercial & industrial
Large commercial & industrial
Public authorities & electric railroads
Other(a)
Total rate-regulated electric revenues(b)
Rate-regulated natural gas revenues
Residential
Small commercial & industrial
Large commercial & industrial
Transportation
Other(c)
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(e)
Other rate-regulated natural gas revenues(e)
Total other revenues
Total rate-regulated revenues for reportable
segments
2,942 $
1,487
538
47
867
5,881
—
—
—
—
—
—
1,566 $
404
223
28
243
2,464
395
143
1
23
6
568
1,382 $
257
429
28
327
2,423
491
77
124
—
63
755
2,351 $
488
1,124
58
593
4,614
99
44
8
16
13
180
1,021 $
140
846
32
193
2,232
—
—
—
—
—
—
669 $
186
100
14
175
1,144
99
44
8
16
13
180
661
162
178
12
227
1,240
—
—
—
—
—
—
5,881
3,032
3,178
4,794
2,232
1,324
1,240
(29)
30
—
1
(7)
12
1
6
(26)
13
4
(9)
(7)
10
1
4
(7)
7
—
—
4
3
1
8
(4)
—
—
(4)
$
5,882 $
3,038 $
3,169 $
4,798 $
2,232 $
1,332 $
1,236
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
ComEd
PECO
BGE
2017
PHI
Pepco
DPL
ACE
Rate-regulated electric revenues
Residential
$
Small commercial & industrial
Large commercial & industrial
Public authorities & electric railroads
Other(a)
Total rate-regulated electric revenues(b)
Rate-regulated natural gas revenues
Residential
Small commercial & industrial
Large commercial & industrial
Transportation
Other(c)
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(e)
Other rate-regulated natural gas revenues(e)
Other revenues(f)
Total other revenues
Total rate-regulated revenues for reportable
segments
__________
(a)
(b)
2,715 $
1,363
455
44
886
5,463
1,505 $
401
223
30
204
2,363
1,365 $
254
427
31
299
2,376
2,246 $
490
1,086
60
541
4,423
964 $
137
794
33
199
2,127
663 $
187
103
14
163
1,130
—
—
—
—
—
—
331
131
1
23
8
494
437
75
119
—
28
659
90
38
8
15
9
160
—
—
—
—
—
—
90
38
8
15
9
160
619
166
189
13
191
1,178
—
—
—
—
—
—
5,463
2,857
3,035
4,583
2,127
1,290
1,178
43
30
—
—
73
—
12
1
—
13
124
13
4
—
141
33
8
1
47
89
19
5
—
—
24
6
3
1
—
10
8
—
—
—
8
$
5,536 $
2,870 $
3,176 $
4,672 $
2,151 $
1,300 $
1,186
Includes revenues from transmission revenue from PJM, wholesale electric revenue and mutual assistance revenue.
Includes operating revenues from affiliates of $30 million, $5 million, $8 million, $14 million, $5 million, $7 million and $3 million at ComEd, PECO, BGE, PHI, Pepco, DPL
and ACE, respectively, in 2019, $27 million, $7 million, $8 million, $15 million, $6 million, $8 million and $3 million at ComEd, PECO, BGE, PHI, Pepco, DPL and ACE, in
2018, and $15 million, $6 million, $5 million, $3 million, $6 million, $8 million and $2 million at ComEd, PECO, BGE, PHI, Pepco, DPL and ACE, respectively, in 2017.
Includes revenues from off-system natural gas sales.
Includes operating revenues from affiliates of $1 million and $18 million at PECO and BGE, respectively, in 2019, $1 million and $21 million at PECO and BGE,
respectively, in 2018, and $1 million and $11 million at PECO and BGE, respectively, in 2017.
Includes late payment charge revenues.
Includes operating revenues from affiliates of $47 million at PHI in 2017.
(c)
(d)
(e)
(f)
6. 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,
265
Table of Contents
Combined Notes to Consolidated Financial Statements
(Dollars in millions, except per share data unless otherwise noted)
Note 6 — Early Plant Retirements
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 Three
Mile Island nuclear plant in Pennsylvania as having the greatest risk of early retirement based on economic valuation and other factors. In 2017, PSEG made
public similar financial challenges facing its New Jersey nuclear plants, including Salem, of which Generation owns a 42.59% ownership interest. PSEG is the
operator of Salem and also has the decision-making authority to retire Salem.
Assuming the continued effectiveness of the Illinois ZES, New Jersey ZEC program and the New York CES, Generation and CENG, through its ownership of
Ginna and Nine Mile Point, no longer consider Clinton, Quad Cities, Salem, Ginna or Nine Mile Point to be at heightened risk for early retirement. However, to
the extent the Illinois ZES, New Jersey ZEC program or the New York CES do not operate as expected over their full terms, each of these plants could again 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.
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.
On February 2, 2018, Generation announced that it would permanently cease generation operations at the Oyster Creek nuclear plant at the end of its current
operating cycle and permanently ceased generation operations on September 17, 2018.
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Combined Notes to Consolidated Financial Statements
(Dollars in millions, except per share data unless otherwise noted)
Note 6 — Early Plant Retirements
As a result of these early nuclear plant retirement decisions, Exelon and Generation recognized incremental non-cash charges to earnings stemming from
shortening the expected economic useful lives primarily related to accelerated depreciation of plant assets (including any ARC) and accelerated amortization of
nuclear fuel, as well as operating and maintenance expenses. The total annual impact of these charges by year are summarized in the table below.
Income statement expense (pre-tax)
Depreciation and Amortization
Accelerated depreciation
Accelerated nuclear fuel amortization
Operating and Maintenance(d)
Total
2019(a)
2018(b)
2017(c)
$
$
216 $
539 $
13
(53)
57
32
176 $
628 $
250
12
77
339
_________
(a) Reflects incremental charges for TMI from January 1, 2019 through September 20, 2019.
(b) Reflects incremental charges for TMI in 2018 and Oyster Creek from February 2, 2018 through September 17, 2018.
(c) Reflects incremental charges for TMI from May 30, 2017 through December 31, 2017.
(d)
In 2019, primarily reflects the net impacts associated with the remeasurements of the TMI ARO in the first and third quarters. In 2018 and 2017, primarily reflects materials
and supplies inventory reserve adjustments, employee related costs and CWIP impairments associated with the early retirement decisions for TMI and Oyster Creek.
Excludes the charges in the third quarter of 2018 and second quarter of 2019 for the ARO remeasurement due to the sale of Oyster Creek. See Note 2 — Mergers,
Acquisitions and Dispositions and Note 9 — Asset Retirement Obligations for additional information.
Generation’s Dresden, Byron, and Braidwood nuclear plants in Illinois are also showing increased signs of economic distress, which could lead to an early
retirement, in a market that does not currently compensate them for their unique contribution to grid resiliency and their ability to produce large amounts of
energy without carbon and air pollution. The May 2018 PJM capacity auction for the 2021-2022 planning year resulted in the largest volume of nuclear capacity
ever not selected in the auction, including all of Dresden, and portions of Byron and Braidwood. Exelon continues to work with stakeholders on state policy
solutions, while also advocating for broader market reforms at the regional and federal level.
Other 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, at the
end of the then-current capacity commitment for Mystic Units 7 and 8. Mystic Unit 9 was then committed through May 2021.
On May 16, 2018, Generation made a filing with FERC to establish cost-of-service compensation and terms and conditions of service for Mystic Units 8 and 9 for
the period between June 1, 2022 - May 31, 2024. On December 20, 2018, FERC issued an order accepting the cost of service 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 Everett Marine
Terminal. Those adjustments were reflected in a compliance filing filed 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 March 25, 2019, ISO-NE filed the Inventoried Energy Program, which is intended to provide an interim fuel security program pending conclusion of the
stakeholder process to develop a long-term, market-based solution to address fuel security. The Inventoried Energy Program went into effect on August 5, 2019.
On October 7, 2019, requests for rehearing were denied and several parties have appealed to the D.C. Circuit Court. FERC ordered ISO-NE to file long-term,
market-based fuel security rules by October 15, 2019; FERC has granted an extension to April 15, 2020.
The following table provides the balance sheet amounts as of December 31, 2019 for Exelon's and Generation’s significant assets and liabilities associated with
the Mystic Units 8 and 9 and Everett Marine Terminal assets that would potentially be impacted by the failure to adopt long-term solutions for reliability and fuel
security.
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Combined Notes to Consolidated Financial Statements
(Dollars in millions, except per share data unless otherwise noted)
Asset Balances
Materials and supplies inventory
Fuel inventory
Property, plant and equipment, net
Liability Balances
Asset retirement obligation
Note 6 — Early Plant Retirements
December 31, 2019
$
31
11
902
(3)
To ensure the continued reliable supply of fuel to Mystic Units 8 and 9 while they remain operating, on October 1, 2018, Generation acquired the Everett Marine
Terminal in Massachusetts for a purchase price of $81 million, with the majority of the fair value allocated to Property, plant and equipment and no goodwill
recorded. Generation also settled its existing long-term gas supply agreement, resulting in a pre-tax gain of $75 million, which is included within Purchased
power and fuel expense in Exelon’s and Generation’s Consolidated Statements of Operations and Comprehensive Income.
See Note 11 — Asset Impairments for impairment assessment considerations on the New England Asset Group.
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Combined Notes to Consolidated Financial Statements
(Dollars in millions, except per share data unless otherwise noted)
Note 7 — Property, Plant and Equipment
7. Property, Plant and Equipment (All Registrants)
The following tables present a summary of property, plant and equipment by asset category as of December 31, 2019 and 2018:
Asset Category
Exelon
Generation
ComEd
PECO
BGE
PHI
Pepco
DPL
ACE
December 31, 2019
Electric—transmission and
distribution
Electric—generation
Gas—transportation and
distribution
Common—electric and gas
Nuclear fuel(a)
Construction work in progress
Other property, plant and
equipment(b)
Total property, plant and
equipment
Less: accumulated
depreciation(c)
Property, plant and equipment,
net
December 31, 2018
Electric—transmission and
distribution
Electric—generation
Gas—transportation and
distribution
Common—electric and gas
Nuclear fuel(a)
Construction work in progress
Other property, plant and
equipment(b)
Total property, plant and
equipment
Less: accumulated
depreciation(c)
$
56,809 $
29,839
— $
29,839
27,566 $
—
8,957 $
—
8,326 $
—
13,809 $
—
9,734 $
—
4,464 $
—
6,147
1,907
5,656
3,055
799
—
—
5,656
702
13
—
—
—
662
47
2,899
877
—
250
2,999
991
—
483
27
25
525
146
—
921
108
—
—
—
628
64
690
160
—
125
21
104,212
36,210
28,275
13,010
12,824
15,509
10,426
5,460
23,979
12,017
5,168
3,718
3,834
1,213
3,517
1,425
4,207
—
—
—
—
166
27
4,400
1,210
$
$
80,233 $
24,193 $
23,107 $
9,292 $
8,990 $
14,296 $
6,909 $
4,035 $
3,190
53,090 $
29,170
— $
29,170
25,991 $
—
8,359 $
—
7,951 $
—
12,664 $
—
9,217 $
—
4,195 $
—
5,530
1,627
5,957
3,377
858
99,609
22,902
—
—
5,957
997
63
—
—
—
705
46
2,694
756
—
343
2,630
860
—
410
19
25
486
126
—
912
99
—
—
—
536
61
651
136
—
151
17
36,187
26,742
12,171
11,876
14,287
9,814
5,150
12,206
4,684
3,561
3,633
841
3,354
1,329
3,866
—
—
—
—
209
28
4,103
1,137
Property, plant and equipment,
net
__________
(a)
(b) Primarily composed of land and non-utility property.
(c)
76,707 $
$
Includes nuclear fuel that is in the fabrication and installation phase of $1,025 million and $1,004 million at December 31, 2019 and 2018, respectively.
Includes accumulated amortization of nuclear fuel in the reactor core at Generation of $2,867 million and $2,969 million as of December 31, 2019 and 2018, respectively.
23,981 $
22,058 $
8,610 $
8,243 $
13,446 $
6,460 $
3,821 $
2,966
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Combined Notes to Consolidated Financial Statements
(Dollars in millions, except per share data unless otherwise noted)
Note 7 — Property, Plant and Equipment
The following table presents the average service life for each asset category in number of years:
Average Service Life (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
1-56
5-80
4-75
1-8
1-50
N/A
1-56
N/A
N/A
1-8
1-10
5-80
N/A
N/A
N/A
N/A
34-50
5-65
N/A
5-70
5-50
N/A
50
BGE
5-75
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
33-50
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
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 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 anticipated second renewal of its operating licenses. Beginning in 2017, TMI and Oyster Creek depreciation provisions were
based on their 2019 expected shutdown dates. Beginning February 2018, Oyster Creek depreciation provisions were based on its announced shutdown date of
September 2018. See Note 3 — Regulatory Matters for additional information regarding license renewals and the Illinois ZECs and Note 6 — 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.
Exelon
Generation
ComEd
PECO
BGE
PHI
Pepco
DPL
ACE
Annual Depreciation Rates
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
December 31, 2017
Electric—transmission and
distribution
Electric—generation
Gas—transportation and
distribution
Common—electric and gas
2.80%
4.35%
2.04%
7.37%
2.73%
5.37%
2.07%
6.98%
2.75%
4.36%
2.10%
7.05%
N/A
4.35%
N/A
N/A
N/A
5.37%
N/A
N/A
N/A
4.36%
N/A
N/A
2.99%
N/A
N/A
N/A
2.95%
N/A
N/A
N/A
2.99%
N/A
N/A
N/A
270
2.36%
N/A
1.89%
6.06%
2.35%
N/A
1.90%
5.44%
2.37%
N/A
1.89%
5.47%
2.60%
N/A
2.30%
8.30%
2.61%
N/A
2.36%
8.50%
2.58%
N/A
2.33%
8.64%
2.77%
N/A
1.55%
8.25%
2.61%
N/A
1.59%
6.30%
2.63%
N/A
2.07%
6.50%
2.47%
N/A
N/A
N/A
2.40%
N/A
N/A
N/A
2.35%
N/A
N/A
N/A
2.86%
N/A
1.55%
6.24%
2.77%
N/A
1.59%
3.70%
2.75%
N/A
2.07%
4.14%
2.94%
N/A
N/A
N/A
2.45%
N/A
N/A
N/A
2.46%
N/A
N/A
N/A
Table of Contents
Combined Notes to Consolidated Financial Statements
(Dollars in millions, except per share data unless otherwise noted)
Note 7 — Property, Plant and Equipment
Capitalized Interest and AFUDC (All Registrants)
The following table summarizes capitalized interest and credits to AFUDC by year:
Exelon
Generation
ComEd
PECO
BGE
PHI
Pepco
DPL
ACE
December 31, 2019
Capitalized interest
AFUDC debt and equity
$
24 $
132
24 $
—
— $
32
— $
17
— $
29
— $
54
— $
39
— $
6
December 31, 2018
Capitalized interest
AFUDC debt and equity
$
31 $
109
31 $
—
— $
30
— $
12
— $
24
— $
44
— $
34
— $
4
December 31, 2017
Capitalized interest
AFUDC debt and equity
$
63 $
108
63 $
—
— $
20
— $
12
— $
22
— $
54
— $
34
— $
10
—
9
—
4
—
9
See Note 1 — Significant Accounting Policies for additional information regarding property, plant and equipment policies. See Note 16 — Debt and Credit
Agreements for additional information regarding Exelon’s, ComEd’s and PECO’s property, plant and equipment subject to mortgage liens.
8. 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, 2019 and 2018 were as follows:
Operator
Ownership interest
Exelon’s share at December 31, 2019:
Plant in service
Accumulated depreciation
Construction work in progress
Exelon’s share at December 31, 2018:
Plant in service
Accumulated depreciation
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
$
$
1,161
$
1,466
$
627
13
571
21
1,131
$
1,451
$
587
523
$
$
663
249
53
648
227
$
$
951
156
27
910
126
102
53
—
103
53
Construction work in progress
__________
(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.
13
44
15
56
—
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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Combined Notes to Consolidated Financial Statements
(Dollars in millions, except per share data unless otherwise noted)
Note 9 — Asset Retirement Obligations
9. 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, 2018 to December 31, 2019:
Nuclear decommissioning ARO at January 1, 2018
Accretion expense
Net decrease due to changes in, and timing of, estimated future cash flows
Costs incurred related to decommissioning plants
Nuclear decommissioning ARO at December 31, 2018 (a) (b)
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)
$
9,662
478
(77)
(58)
10,005
864
(755)
479
(89)
$
10,504
__________
(a)
Includes $112 million and $22 million as the current portion of the ARO at December 31, 2019 and 2018, respectively, which is included in Other current liabilities in
Exelon’s and Generation’s Consolidated Balance Sheets.
Includes $772 million of ARO related to Oyster Creek which is classified as Liabilities held for sale in Exelon's and Generation's Consolidated Balance Sheets at
December 31, 2018. See Note 2 — Mergers, Acquisitions and Dispositions for additional information.
(b)
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; and
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; partially offset by
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.
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Combined Notes to Consolidated Financial Statements
(Dollars in millions, except per share data unless otherwise noted)
Note 9 — Asset Retirement Obligations
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 6—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.
The net $77 million decrease in the ARO during 2018 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:
•
•
•
A decrease of approximately $205 million primarily due to lower estimated costs for the construction of interim spent fuel storage at TMI and a net
decrease in estimated costs to decommission Calvert Cliffs, FitzPatrick, Limerick, and Salem nuclear units resulting from the completion of updated
cost studies. There was also a decrease due to changes in decommissioning scenarios and their probabilities. These decreases were partially offset by
An increase of approximately $115 million for the impact of the early retirement and the announced pending sale of Oyster Creek which closed on July
1, 2019; and
An increase of approximately $120 million for estimated cost escalation rates, primarily for labor, energy and waste burial costs.
See Note 2 — Mergers, Acquisitions and Dispositions and Note 6—Early Plant Retirements for additional information regarding Oyster Creek.
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
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(Dollars in millions, except per share data unless otherwise noted)
Note 9 — Asset Retirement Obligations
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 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, 2019 and 2018, Exelon and Generation had NDT funds totaling $13,353 million and $12,695 million, respectively. The NDT funds included
$890 million at December 31, 2018, related to Oyster Creek NDT funds which were classified as Assets held for sale in Exelon's and Generation's Consolidated
Balance Sheets. See Note 2 — Mergers, Acquisitions and Dispositions for additional information. The NDT funds include $163 million and $144 million for the
current portion of the NDT at December 31, 2019 and 2018, respectively, which are included in Other current assets in Exelon's and Generation's Consolidated
Balance Sheets. See Note 23 — 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 and accretion of the decommissioning obligation, are generally offset within Exelon’s and
Generation’s Consolidated Statements of Operations and Comprehensive Income. For the former ComEd units, decommissioning-related activities are generally
offset within Exelon’s and Generation’s Consolidated Statements of Operations and Comprehensive Income as long as the NDT funds are expected to exceed
the total estimated decommissioning obligation. For the former PECO 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 to affiliates at Generation. ComEd and PECO have recorded an equal
noncurrent affiliate receivable from Generation and corresponding regulatory liability.
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. As of December 31, 2019, the NDT funds of each of the former ComEd
units, except for Zion (see Zion Station Decommissioning below), are expected to exceed the related decommissioning obligation for each of the units. 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.
Any changes to the 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.
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 24 — 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.
274
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Combined Notes to Consolidated Financial Statements
(Dollars in millions, except per share data unless otherwise noted)
Note 9 — Asset Retirement Obligations
Zion Station Decommissioning
In 2010, Generation completed an Asset Sale Agreement (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. To reduce the risk of default by
ZionSolutions, EnergySolutions has provided a $25 million letter of credit to be used to fund decommissioning costs in the event the NDT assets are insufficient.
EnergySolutions and its parent company have also provided a performance guarantee.
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. Any Zion Station NDT funds remaining after the completion of all
decommissioning activities will be returned to ComEd customers in accordance with the applicable orders.
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, 2019 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,
2019 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 low-level radioactive waste); (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 5% 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 5.4% to 6.5% (as compared to a historical 5-year annual average pre-tax
return of approximately 6.7%).
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.
275
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Combined Notes to Consolidated Financial Statements
(Dollars in millions, except per share data unless otherwise noted)
Note 9 — Asset Retirement Obligations
Generation filed its biennial decommissioning funding status report with the NRC on April 1, 2019 for all 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. As a former PECO plant, financial
assurance for decommissioning Peach Bottom Unit 1 is provided by the NDT fund, collections from PECO ratepayers and the ability to adjust those collections in
accordance with the approved PAPUC tariff. No additional actions are required aside from the PAPUC filing in accordance with the tariff. See NDT Funds
section above for additional information.
Generation will file its next annual decommissioning funding status report with the NRC by March 31, 2020 for shutdown reactors, reactors within five years of
shutdown except for Zion Station which is included in a separate report to the NRC submitted by EnergySolutions (see Zion Station Decommissioning above).
This report will reflect the status of decommissioning funding assurance as of December 31, 2019 and will include an update for the retirement of TMI in 2019. A
shortfall at any unit could necessitate that Exelon post a 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, 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.
The following table provides a rollforward of the non-nuclear AROs reflected in the Registrants’ Consolidated Balance Sheets from January 1, 2018 to
December 31, 2019:
Exelon
Generation
ComEd
PECO
BGE
PHI
Pepco
DPL
ACE
Non-nuclear AROs at January 1, 2018
$
384 $
197
$
113
$
27
$
24 $
16 $
3 $
10 $
Net increase due to changes in, and timing of,
estimated future cash flows(a)
Accretion expense(b)
Asset divestitures
Payments
Non-nuclear AROs at December 31, 2018
Net (decrease) increase due to changes in, and
timing of, estimated future cash flows
Development projects
Accretion expense(b)
Asset divestitures
Payments
80
16
(3)
(6)
471
17
2
16
(42)
(4)
35
10
(3)
(1)
238
7
2
12
(42)
(1)
7
4
—
(3)
121
8
—
1
—
1
—
—
28
—
—
1
—
(1)
—
(1)
2
1
—
(2)
25
(2)
—
1
—
(1)
36
—
—
—
52
4
—
1
—
—
34
—
—
—
37
3
—
1
—
—
1
—
—
—
11
1
—
—
—
—
Non-nuclear AROs at December 31, 2019
$
460 $
216
$
129
$
28
$
23 $
57 $
41
$
12
$
3
1
—
—
—
4
—
—
—
—
—
4
276
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Combined Notes to Consolidated Financial Statements
(Dollars in millions, except per share data unless otherwise noted)
__________
(a)
In 2018, Pepco recorded an increase of $22 million in Operating and maintenance expense primarily related to asbestos identified at its Buzzard Point property as part of
an annual ARO study. Buzzard Point is a waterfront property in the District of Columbia occupied by an active substation and former Pepco operated steam plant building,
which Pepco retired and closed in 1981.
(b) For ComEd and PECO, the majority of the accretion is recorded as an increase to a regulatory asset due to the associated regulatory treatment.
Note 9 — Asset Retirement Obligations
10. Leases (All Registrants)
Lessee
The Registrants have operating leases for which they are the lessees. The following tables outline the significant types of operating lease at each registrant and
other terms and conditions of the lease agreements. The Registrants do not have material finance leases.
Exelon
Generation
ComEd
PECO
BGE
PHI
Pepco
DPL
ACE
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
1-86
3-30
1-13
1-36
3-30
1
1-5
5
3
1-14
N/A
N/A
1-86
N/A
2
1-12
3-30
N/A
1-12
5
N/A
1-12
3-30
N/A
The components of lease costs for the year ended December 31, 2019 were as follows:
Exelon
Generation
ComEd
PECO
BGE
PHI
Pepco
DPL
ACE
Operating lease costs
Variable lease costs
Short-term lease costs
Total lease costs (a)
$
$
320 $
300
19
639 $
222 $
282
19
523 $
3 $
2
—
5 $
1 $
—
—
1 $
33 $
2
—
35 $
48 $
6
—
54 $
12 $
2
—
14 $
14 $
2
—
16 $
__________
(a) Excludes $51 million, $44 million, $7 million and $7 million of sublease income recorded at Exelon, Generation, PHI and DPL.
The following table presents the Registrants' rental expense under the prior lease accounting guidance for the years ended December 31, 2018 and 2017:
Exelon
Generation(a)
ComEd
PECO
BGE
PHI
Pepco
DPL
ACE
2018
2017
$
670 $
709
558 $
578
7 $
9
10 $
9
35 $
32
48 $
63
10 $
11
13 $
16
1-6
N/A
N/A
7
1
—
8
8
14
__________
(a)
Includes contingent operating lease payments associated with contracted generation agreements that are not included in the minimum future operating lease payments
above. Payments made under Generation's contracted generation lease agreements totaled $493 million and $508 million during 2018 and 2017, respectively.
277
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Combined Notes to Consolidated Financial Statements
(Dollars in millions, except per share data unless otherwise noted)
Note 10 — Leases
The following table provides additional information regarding the presentation of operating ROU assets and lease liabilities within the Registrants’ Consolidated
Balance Sheets as of December 31, 2019:
Operating lease ROU assets
Other deferred debits and other assets
$
1,305 $
895 $
9 $
2 $
77 $
273 $
56 $
63 $
18
Exelon(a)
Generation(a)
ComEd
PECO
BGE
PHI
Pepco
DPL
ACE
Operating lease liabilities
Other current liabilities
Other deferred credits and other liabilities
225
1,307
157
925
3
8
—
1
32
50
31
254
6
51
9
65
Total operating lease liabilities
$
1,532 $
1,082 $
11 $
1 $
82 $
285 $
57 $
74 $
__________
(a) Exelon's and Generation's operating ROU assets and lease liabilities include $515 million and $664 million, respectively, related to contracted generation.
4
14
18
The weighted average remaining lease terms, in years, and discount rates for operating leases as of December 31, 2019 were as follows:
Exelon
Generation
ComEd
PECO
BGE
PHI
Pepco
DPL
ACE
Remaining lease term
Discount rate
10.1
4.6%
10.6
4.8%
4.6
3.0%
4.4
3.2%
5.4
3.6%
9.0
4.2%
9.8
4.0%
9.7
4.0%
4.7
3.6%
Future minimum lease payments for operating leases as of December 31, 2019 were as follows:
Year
2020
2021
2022
2023
2024
Remaining years
Total
Interest
Total operating lease
liabilities
Exelon
Generation
ComEd
PECO
BGE
PHI
Pepco
DPL
ACE
$
287 $
243
177
145
140
976
1,968
436
203 $
162
113
100
97
741
1,416
334
$
1,532 $
1,082 $
3 $
4
2
1
1
1
12
1
11 $
— $
1
—
—
—
—
1
—
34 $
31
16
1
—
18
100
18
42 $
41
38
37
35
153
346
61
1 $
82 $
285 $
8 $
8
8
7
5
34
70
13
57 $
11 $
11
10
9
9
41
91
17
74 $
5
4
4
3
2
2
20
2
18
278
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Combined Notes to Consolidated Financial Statements
(Dollars in millions, except per share data unless otherwise noted)
Future minimum lease payments for operating leases under the prior lease accounting guidance as of December 31, 2018 were as follows:
Note 10 — Leases
Exelon(a)(b)
Generation(a)(b)
ComEd(a)(c)
PECO(a)(c)
BGE(a)(c)(d)(e)
PHI(a)
Pepco(a)
DPL(a)(c)
ACE(a)
$
2019
2020
2021
2022
2023
140 $
149
143
126
97
723
33 $
46
46
47
46
545
7 $
5
4
4
3
—
5 $
5
5
5
5
—
35 $
35
33
18
3
19
48 $
46
43
42
39
159
11 $
10
9
8
8
40
14 $
13
12
12
10
35
7
6
5
5
4
$
1,378 $
Includes amounts related to shared use land arrangements.
Remaining years
Total minimum
future lease
payments
__________
(a)
(b) Excludes Generation’s contingent operating lease payments associated with contracted generation.
(c) Amounts related to certain real estate leases and railroad licenses effectively have indefinite payment periods. As a result, ComEd, PECO, BGE and DPL have excluded
these payments from the remaining years as such amounts would not be meaningful. ComEd's, PECO’s, BGE’s and DPL's average annual obligation for these
arrangements, included in each of the years 2019 - 2023, was $3 million, $5 million, $1 million and $1 million respectively. Also includes amounts related to shared use
land arrangements.
Includes all future lease payments on a 99-year real estate lease that expires in 2106.
(d)
(e) The BGE column above includes minimum future lease payments associated with a 6-year lease for the Baltimore City conduit system that became effective during the
763 $
143 $
377 $
25 $
23 $
96 $
86 $
32
5
fourth quarter of 2016. BGE's total commitments under the lease agreement are $26 million, $28 million, $28 million and $14 million related to years 2019 - 2022,
respectively.
Cash paid for amounts included in the measurement of lease liabilities for the year ended December 31, 2019 were as follows:
Operating cash flows from
operating leases
$
287 $
206 $
3 $
— $
33 $
37 $
9 $
6 $
5
Exelon
Generation
ComEd
PECO
BGE
PHI
Pepco
DPL
ACE
ROU assets obtained in exchange for lease obligations for the year ended December 31, 2019 were as follows:
Operating leases
$
52 $
14 $
6 $
— $
2 $
(3) $
(1)
$
(2) $
(1)
Exelon
Generation
ComEd
PECO
BGE
PHI
Pepco
DPL
ACE
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.
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
1-83
1-79
1-32
1-5
1-17
5-79
1-83
5-50
23
N/A
1-13
5
1-6
N/A
12-13
N/A
1-2
N/A
279
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Combined Notes to Consolidated Financial Statements
(Dollars in millions, except per share data unless otherwise noted)
Note 10 — Leases
The components of lease income for the year ended December 31, 2019 were as follows:
Exelon
Generation
ComEd
PECO
BGE
PHI
Pepco
DPL
ACE
Operating lease income
Variable lease income
$
$
54 $
261 $
47 $
258 $
— $
— $
— $
— $
— $
— $
5 $
3 $
— $
— $
4 $
3 $
Future minimum lease payments to be recovered under operating leases as of December 31, 2019 were as follows:
Year
2020
2021
2022
2023
2024
Remaining years
Total
Exelon
Generation
ComEd
PECO
BGE
PHI
Pepco
DPL
ACE
$
$
51 $
51
50
49
48
265
514 $
46 $
45
45
44
44
226
450 $
— $
—
—
—
—
1
1 $
— $
—
—
—
—
3
3 $
— $
—
—
—
—
1
1 $
4 $
4
4
5
4
34
55 $
— $
1
—
—
—
—
1 $
3 $
3
3
4
4
34
51 $
—
—
—
—
—
—
—
—
—
11. Asset Impairments (Exelon, Generation and PHI)
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.
Equity Method Investments in Certain Distributed Energy Companies (Exelon and Generation)
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. 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 22 — Variable Interest Entities for additional information.
Antelope Valley Solar Facility (Exelon and Generation)
Generation’s Antelope Valley, a 242 MW solar facility in Lancaster, CA, sells all of its output to PG&E through a PPA. As of December 31, 2019, Generation had
approximately $725 million of net long-lived assets related to Antelope Valley. As a result of the PG&E bankruptcy filing in the first quarter of 2019, Generation
completed a comprehensive review of Antelope Valley's estimated undiscounted future cash flows and no impairment charge was recorded. Significant changes
in assumptions such as the likelihood of the PPA being rejected as part of the bankruptcy proceedings could potentially result in future impairments of Antelope
Valley’s net long-lived assets, which could be material.
Antelope Valley is a wholly owned indirect subsidiary of EGR IV, which had approximately $1,893 million of additional net long-lived assets as of December 31,
2019. EGR IV is a wholly owned indirect subsidiary of Exelon and Generation and includes Generation's interest in EGRP and other projects with non-controlling
interests. To date, there have been no indicators to suggest that the carrying amount of other net long-lived assets of EGR IV may not be recoverable.
Generation will continue to monitor the bankruptcy proceedings for any changes in circumstances that may indicate the carrying amount of the net long-lived
assets of Antelope Valley or other long-lived assets of EGR IV may not be recoverable.
See Note 16 — Debt and Credit Agreements for additional information on the PG&E bankruptcy.
New England Asset Group (Exelon and Generation)
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 ISO-NE of the early retirement of its Mystic Generating Station's Units 7, 8, 9 and the Mystic Jet Unit (Mystic Generating Station assets) absent
regulatory reforms. These events suggested that the carrying value of its New England asset group may be impaired. Generation completed a comprehensive
review of the estimated undiscounted future cash flows of the New England asset group and no impairment charge was required. Further developments such as
the failure of ISO-NE to adopt long-term solutions for reliability and fuel security could potentially result in material future impairments of the New England asset
group. See Note 6 — Early Plant Retirements for additional information.
District of Columbia Sponsorship (Exelon and PHI)
In the third quarter of 2015, PHI entered into a sponsorship agreement with the District of Columbia for future sponsorship rights associated with public property
within the District of Columbia, which Exelon and PHI had recorded as a finite-lived intangible asset as of December 31, 2016. The specific sponsorship rights
were to be determined through future negotiations. In the fourth quarter of 2017, based upon the lack of available sponsorship opportunities at that time, the
asset was written off and a pre-tax impairment charge of $25 million was recorded within Operating and maintenance expense in Exelon’s and PHI's
Consolidated Statements of Operations and Comprehensive Income.
ExGen Texas Power (Exelon and Generation)
On May 2, 2017, EGTP entered into a consent agreement with its lenders to initiate the sale of the assets of its wholly owned subsidiaries. As a result, Exelon
and Generation classified certain of EGTP's assets and liabilities as held for sale at their respective fair values less costs to sell and recorded a pre-tax
impairment charge in 2017 of $460 million within Operating and maintenance expense in their Consolidated Statements of Operations and Comprehensive
Income. On November 7, 2017, EGTP and its wholly owned subsidiaries filed voluntary petitions for relief under Chapter 11 of Title 11 of the United States Code
in the United States Bankruptcy Court for the District of Delaware and, as a result, Exelon and Generation deconsolidated EGTP's assets and liabilities from their
consolidated financial statements. See Note 2 — Mergers, Acquisitions and Dispositions for additional information.
12. Intangible Assets (Exelon, Generation, ComEd, PHI, Pepco, DPL and ACE)
Goodwill
The following table presents the gross amount of goodwill, accumulated impairment loss and carrying amount of goodwill of Exelon, ComEd and PHI as of
December 31, 2019 and 2018. There were no additions, impairments or measurement period adjustments during the years ended December 31, 2019 and
2018.
Exelon
ComEd(a)
PHI(b)
Gross amount
Accumulated impairment
loss
Carrying amount
$
8,660 $
4,608
4,005
1,983 $
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 tested 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 testing 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
280
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Combined Notes to Consolidated Financial Statements
(Dollars in millions, except per share data unless otherwise noted)
Note 12 — Intangible Assets
performed. If an entity bypasses the qualitative assessment, a quantitative two-step, fair value-based test is performed. The first step 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 second step is performed. The
second step requires an allocation of fair value to the individual assets and liabilities using purchase price allocation authoritative guidance in order to determine
the implied fair value of goodwill.
Application of the goodwill impairment test 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. In applying the second step, if needed, management must
estimate the fair value of specific assets and liabilities of the reporting unit.
2019 and 2018 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, 2019 and 2018 for ComEd and as of
November 1, 2019 for PHI. The last quantitative assessments performed were as of November 1, 2016 for ComEd and November 1, 2018 for PHI.
PHI performed a quantitative test for its 2018 annual goodwill impairment assessment as of November 1, 2018. The first step of the test comparing the estimated
fair values of the Pepco, DPL and ACE reporting units to their carrying values, including goodwill, indicated no impairments of goodwill; therefore, no second
step was required.
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. Based on the results of the last quantitative goodwill test performed, the estimated fair values of the ComEd, Pepco, DPL and ACE reporting
units would have needed to decrease by more than 30%, 30%, 20% and 30%, respectively, for ComEd and PHI to fail the first step of their respective
impairment tests.
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, 2019 and 2018. 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:
December 31, 2019
Accumulated
Amortization
Gross
Net
Gross
December 31, 2018
Accumulated
Amortization
Net
Generation
Unamortized Energy Contracts
Customer Relationships
Trade Name
ComEd
1,967
343
243
(1,612)
(190)
(193)
355
153
50
1,957
325
243
(1,588)
(162)
(171)
Chicago Settlement Agreements
162
(155)
7
162
(148)
PHI
369
163
72
14
Unamortized Energy Contracts
(1,515)
1,073
(442)
(1,515)
954
(561)
Exelon Corporate
Software License
Exelon
95
(44)
51
95
(34)
$
1,295 $
(1,121) $
174 $
1,267 $
(1,149) $
61
118
281
Table of Contents
Combined Notes to Consolidated Financial Statements
(Dollars in millions, except per share data unless otherwise noted)
The following table summarizes the amortization expense related to intangible assets and liabilities for each of the years ended December 31, 2019, 2018 and
2017:
For the Years Ended December 31,
Exelon (a)(b)
Generation (a)
ComEd
PHI(b)
Note 12 — Intangible Assets
2019 $
2018
2017
(28) $
(109)
(237)
74 $
63
83
7 $
7
7
(119)
(188)
(336)
__________
(a) At Exelon and Generation, amortization of unamortized energy contracts totaling $21 million, $14 million and $35 million for the years ended December 31, 2019, 2018
and 2017, 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, 2019:
For the Years Ending December 31,
Exelon
Generation
ComEd
PHI
2020
2021
2022
2023
2024
$
(13) $
85 $
7 $
(115)
2
(21)
(18)
22
84
58
53
50
—
—
—
—
(92)
(89)
(81)
(38)
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 Renewable Energy Credits as of December 31, 2019 and 2018:
Current REC's
Noncurrent REC's
As of December 31, 2019
As of December 31, 2018
Exelon
Generation
Exelon
Generation
345
86
336
86
279
52
270
52
282
Table of Contents
Combined Notes to Consolidated Financial Statements
(Dollars in millions, except per share data unless otherwise noted)
Note 13 — Income Taxes
13. Income Taxes (All Registrants)
Components of Income Tax Expense or Benefit
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
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, 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
—
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
Exelon
Generation
ComEd
PECO
BGE
PHI
Pepco
DPL
ACE
For the Year Ended December 31, 2017
$
194 $
584 $
(191) $
71 $
74 $
(60) $
(20) $
(24) $
(12)
(470)
(25)
14
161
(2,005)
(21)
65
1
523
(2)
(49)
136
28
—
14
(9)
101
(1)
(5)
49
251
(1)
115
—
(4)
31
(2)
12
82
—
—
13
$
(126) $
(1,376) $
417 $
104 $
218 $
217 $
105 $
71 $
34
—
—
4
26
283
Table of Contents
Rate Reconciliation
Combined Notes to Consolidated Financial Statements
(Dollars in millions, except per share data unless otherwise noted)
Note 13 — Income Taxes
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:
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
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
5.4
5.9
(1.5)
(1.4)
(3.1)
(0.6)
(5.5)
3.8
12.3
(3.0)
—
(4.8)
(1.2)
—
Other
Effective income tax rate
(0.8)
19.4 %
(1.2)
26.9 %
8.5
—
(0.2)
—
(1.2)
—
(9.7)
0.8
19.2 %
—
—
—
(7.2)
—
—
(2.8)
—
11.0 %
6.4
—
(0.1)
(1.2)
(1.3)
—
(6.8)
—
18.0 %
4.7
—
2.0
—
6.8
—
(0.2)
(1.2)
(0.2)
(0.1)
(1.8)
(0.1)
—
—
(0.2)
(0.4)
—
—
7.0
—
(0.3)
(0.7)
(0.1)
—
(17.5)
(15.1)
(14.2)
(27.0)
0.8
7.4 %
0.3
6.2 %
—
13.0 %
0.1
— %
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
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, 2018
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 %
284
(2.6)
—
6.6
—
(0.1)
(14.1)
—
—
(0.1)
(1.3)
—
—
(3.2)
(8.0)
—
0.3
1.3 %
—
0.9
19.1 %
2.9
—
(0.2)
(1.6)
—
—
(14.8)
0.1
0.4
7.8 %
2.0
—
6.7
—
(0.1)
(2.8)
—
—
(0.3)
(0.3)
—
—
7.4
—
(0.4)
(0.5)
—
—
(15.3)
(12.0)
(14.9)
—
0.3
5.1 %
—
0.4
15.5 %
—
1.2
13.8 %
Table of Contents
Combined Notes to Consolidated Financial Statements
(Dollars in millions, except per share data unless otherwise noted)
Exelon
Generation
ComEd
PECO
35.0 %
35.0 %
35.0 %
35.0 %
BGE
35.0 %
PHI
35.0 %
Pepco
35.0 %
DPL
35.0 %
ACE
35.0 %
For the Year Ended December 31, 2017
Note 13 — Income Taxes
2.2
3.8
(0.9)
(1.7)
(1.8)
(1.2)
(3.6)
(2.2)
(33.1)
0.2
2.9
9.9
(2.1)
—
(4.7)
—
(1.2)
(5.6)
(128.3)
(0.5)
5.7
—
(0.2)
0.3
—
1.3
—
—
0.1
0.2
0.6
—
5.4
—
4.8
—
(0.1)
(0.2)
(0.1)
(13.8)
—
—
—
—
(2.3)
(0.1)
0.1
—
—
—
—
0.9
0.2
1.1
—
—
(9.6)
—
6.4
0.5
38.0 %
3.1
—
(0.1)
(0.4)
—
—
(6.4)
—
2.8
0.7
5.4
—
(0.2)
2.0
—
—
5.6
—
(0.4)
3.6
—
—
(7.8)
(19.8)
—
2.5
0.1
—
1.6
(0.4)
34.7 %
37.0 %
25.2 %
(3.3)%
(94.6)%
42.4 %
19.3 %
41.5 %
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(a)
Production tax credits and other credits
Like-kind exchange
Merger expenses
FitzPatrick bargain purchase gain
Tax Cuts and Jobs Act of 2017(b)
Other
Effective income tax rate
__________
(a)
Includes the charges related to the transmission-related income tax regulatory asset for Exelon, ComEd, BGE, PHI, Pepco, DPL and ACE of $35 million, $3 million, $5
million, $27 million, $14 million, $6 million and $7 million, respectively. See Note 3 - Regulatory Matters for additional information.
(b) As a result of TCJA, Generation recorded a net decrease to income tax expense, while the Utility Registrants recorded 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.
285
Table of Contents
Combined Notes to Consolidated Financial Statements
(Dollars in millions, except per share data unless otherwise noted)
Note 13 — 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, 2019
and 2018 are presented below:
As of December 31, 2019
Plant basis differences
$
(13,413)
$
(2,814)
$
(4,197)
$
(1,978)
$
(1,578)
$
(2,681)
$
(1,204)
$
(753)
$
(687)
Exelon
Generation
ComEd
PECO
BGE
PHI
Pepco
DPL
ACE
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
$
$
61
165
1,504
(503)
183
(884)
240
892
(830)
926
(43)
88
(220)
(503)
20
—
55
897
(808)
236
—
84
—
—
(270)
(28)
—
(7)
183
—
—
—
196
—
—
(169)
25
—
—
70
—
—
(28)
—
(3)
157
49
—
—
10
104
2
(89)
—
142
(10)
93
—
—
181
—
—
—
—
(75)
(42)
—
(3)
55
13
—
—
85
—
(2)
88
44
—
—
12
(11,659)
$
(3,092)
$
(4,011)
$
(2,080)
$
(1,393)
$
(2,258)
$
(1,129)
$
(653)
$
(668)
(648)
(10)
(1)
(3)
(7)
(2)
(2)
—
—
(10)
—
(1)
77
31
—
—
16
(574)
(3)
(12,327)
$
(3,740)
$
(4,021)
$
(2,081)
$
(1,396)
$
(2,265)
$
(1,131)
$
(655)
$
(577)
286
Table of Contents
Combined Notes to Consolidated Financial Statements
(Dollars in millions, except per share data unless otherwise noted)
Note 13 — Income Taxes
As of December 31, 2018
Plant basis differences
$
(12,533)
$
(2,495)
$
(4,059)
$
(1,862)
$
(1,399)
$
(2,577)
$
(1,148)
$
(743)
$
(645)
Exelon
Generation
ComEd
PECO
BGE
PHI
Pepco
DPL
ACE
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
$
$
117
89
1,435
(351)
234
(740)
237
811
(797)
934
(44)
35
(188)
(351)
23
—
78
816
(775)
239
—
69
(255)
—
(7)
300
—
—
—
151
—
—
(26)
—
—
(129)
18
—
—
67
—
—
(26)
—
(3)
172
25
—
—
12
161
3
(102)
—
187
(81)
96
—
—
196
—
—
(78)
—
(4)
67
12
—
—
98
—
—
(46)
—
(2)
96
52
—
—
17
—
—
(14)
—
(1)
83
26
—
—
19
(10,564)
$
(2,662)
$
(3,801)
$
(1,932)
$
(1,219)
$
(2,117)
$
(1,053)
$
(626)
$
(532)
(724)
(700)
(12)
(1)
(3)
(8)
(2)
(2)
(3)
(11,288)
$
(3,362)
$
(3,813)
$
(1,933)
$
(1,222)
$
(2,125)
$
(1,055)
$
(628)
$
(535)
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, 2019. ComEd does not have net operating losses or credit carryforwards for
the year ended December 31, 2019.
Federal
Federal general business credits carryforwards(a)
$
891 $
897
$
— $
— $
— $
— $
— $
—
Exelon
Generation
PECO
BGE
PHI
Pepco
DPL
ACE
State
State net operating losses
Deferred taxes on state tax attributes (net)
Valuation allowance on state tax attributes
3,986
264
26
1,142
312
762
1,360
202
654
78
24
25
—
50
1
93
—
13
—
44
—
438
31
—
Year in which net operating loss or credit carryforwards will
begin to expire
__________
(a) Exelon's and Generation's federal general business credit carryforwards will begin expiring in 2034.
2025
2029
2031
2026
2028
2028
2030
2031
Tabular Reconciliation of Unrecognized Tax Benefits
The following table presents changes in unrecognized tax benefits, by Registrant.
287
Table of Contents
Combined Notes to Consolidated Financial Statements
(Dollars in millions, except per share data unless otherwise noted)
Note 13 — Income Taxes
Balance at January 1, 2017
$
916 $
490 $
(12) $
— $
120
$
172
$
80
$
37
$
Exelon
Generation
ComEd
PECO
BGE
PHI
Pepco
DPL
ACE
28
—
14
—
(196)
(17)
—
—
14
—
—
(61)
(21)
(16)
(22)
Increases based on tax positions prior to
2017
Decreases based on tax positions prior to
2017(a)
Decrease from settlements with taxing
authorities
Balance at December 31, 2017
Change to positions that only affect timing
Increases based on tax positions prior to
2018
Decreases based on tax positions prior to
2018(b)
Decrease from settlements with taxing
authorities
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
—
—
—
120
—
(5)
743
15
30
(5)
468
15
—
2
—
—
—
—
—
125
—
—
59
—
—
21
—
21
—
—
—
8
7
1
(251)
(36)
—
—
(120)
(88)
(66)
(22)
(53)
(7)
477
26
2
34
(3)
(29)
(53)
—
—
(7)
408
12
—
2
3
—
—
1
1
—
—
19
3
2
(3)
—
—
4
(2)
—
—
—
—
4
—
3
—
—
—
—
—
—
45
3
—
—
2
—
—
1
—
—
—
—
—
—
—
—
—
—
—
—
Balance at December 31, 2019
$
507 $
441 $
6 $
3 $
7 $
48 $
2 $
1 $
__________
(a) Exelon established a liability for an uncertain tax position associated with the tax deductibility of certain merger commitments incurred by Exelon in connection with the
acquisitions of Constellation and PHI. In 2017, as a part of its examination of Exelon's return, the IRS National Office issued guidance concurring with Exelon's position
that the merger commitments were deductible. As a result, Exelon, Generation, PHI, Pepco, DPL, and ACE decreased their liability for unrecognized tax benefits by $146
million, $19 million, $59 million, $21 million, $16 million and $22 million, respectively, resulting in a benefit to Income taxes on Exelon's, Generation's, PHI's, Pepco's,
DPL's, and ACE's Consolidated Statements of Operations and Comprehensive Income and corresponding decreases in their effective tax rates.
(b) 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.
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 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
288
22
14
—
14
—
—
—
—
—
14
—
—
—
—
—
14
Table of Contents
Combined Notes to Consolidated Financial Statements
(Dollars in millions, except per share data unless otherwise noted)
Note 13 — Income Taxes
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, 2019
December 31, 2018
Exelon
Generation
PHI(a)
$
462 $
463
429 $
408
32
31
December 31, 2017
__________
(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
32
523
461
require a full valuation allowance based on present circumstances.
The following table presents Exelon's, BGE's, PHI's, Pepco's, DPL's and ACE’s unrecognized tax benefits that, if recognized, may be included in future base
rates and that portion would have no impact to the effective tax rate. ComEd's and PECO's amounts are not material.
Exelon
BGE
PHI
Pepco
DPL
ACE
December 31, 2019
$
December 31, 2018
December 31, 2017
19 $
14
214
1 $
—
120
14 $
14
94
— $
—
59
— $
—
21
14
14
14
Reasonably possible the total amount of unrecognized tax benefits could significantly increase or decrease within 12 months after the reporting date
Settlement of Income Tax Audits, Refund Claims, and Litigation
The following table represents Exelon's, Generation's and ACE's unrecognized federal and state tax benefits that could significantly decrease within the 12
months after the reporting date as a result of completing audits, potential settlements, refund claims, and the outcomes of pending court cases as of
December 31, 2019. ComEd's, PECO's, BGE's, PHI's, Pepco's and DPL's amounts are not material.
Exelon(a)
Generation(a)
ACE(b)
$
__________
(a) Exelon and Generation have $411 million that, if recognized, would decrease the effective tax rate.
(b) The unrecognized tax benefit related to ACE, if recognized, may be included in future base rates and that portion would have no impact to the effective tax rate.
425 $
411 $
14
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, 2019
December 31, 2018
$
Exelon
318
219
289
Table of Contents
Combined Notes to Consolidated Financial Statements
(Dollars in millions, except per share data unless otherwise noted)
Note 13 — 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
PHI Holdings and subsidiaries consolidated federal income tax returns
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
Pennsylvania separate corporate income tax returns
Other Tax Matters
Federal Income Tax Law Changes
Open Years
2002-2018
Registrants Impacted
All Registrants
Exelon, Generation, PHI, Pepco, DPL,
ACE
2016
Same as federal
DPL
2016-2018
2010-2018
Exelon, PHI, Pepco
Exelon, Generation, ComEd
Same as federal
2013-2018
2014-2018
2010-March 2012
2011-2018
2011-2018
2016-2018
BGE, Pepco, DPL
Exelon, Generation
ACE
Exelon, Generation
Exelon, Generation
Exelon, Generation
PECO
On December 22, 2017, President Trump signed the TCJA into law. Pursuant to the enactment of the TCJA, the Registrants remeasured their existing deferred
income tax balances as of December 31, 2017 to reflect the decrease in the corporate income tax rate from 35% to 21%, which resulted in a material decrease
to their net deferred income tax liability balances as shown in the table below. Generation recorded a corresponding net decrease to income tax expense, while
the Utility Registrants recorded 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 one-time impacts recorded by the Registrants to remeasure their deferred income tax balances at the 21% corporate federal income tax rate as of
December 31, 2017 are presented below:
Net Decrease to Deferred
Income Tax Liability Balances
$8,624
$1,895
$2,819
$1,407
$1,120
$1,944
$968
$540
$456
Exelon(b)
Generation
ComEd
PECO(c)
BGE
PHI
Pepco
DPL
ACE
Net Increase to Regulatory
Liabilities Recorded(a)
Net Deferred Income Tax
Benefit/(Expense) Recorded
__________
(a) Reflects the net regulatory liabilities recorded on a pre-tax basis before taking into consideration the income tax benefits associated with the ultimate settlement with
$1,309
$1,895
7,315
1,394
2,818
1,979
1,124
$(35)
$(8)
$(4)
$(5)
$(2)
545
458
$13
976
N/A
$1
customers.
(b) Amounts do not sum across due to deferred tax adjustments recorded at the Exelon Corporation parent company, primarily related to certain employee compensation
plans.
(c) Given the regulatory treatment of income tax benefits related to electric and gas distribution repairs, PECO remained in an overall net regulatory asset position as of
December 31, 2017 after recording the impacts related to the TCJA.
290
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Combined Notes to Consolidated Financial Statements
(Dollars in millions, except per share data unless otherwise noted)
Note 13 — Income Taxes
State Income Tax Law Changes
Illinois - On June 5, 2019, the Governor of Illinois signed a tax bill which would increase the Illinois corporate income tax rate from 9.50% to 10.49% effective for
tax years beginning on or after January 1, 2021. The tax rate is contingent upon ratification of state constitutional amendments in November 2020. The effect of
the rate change will be recognized in the period in which the new legislation is enacted. Exelon, Generation and ComEd do not expect a material impact to their
financial statements as a result of the rate change.
In 2017, Exelon reviewed and updated its marginal state income tax rates based on 2016 state apportionment rates. In addition, Exelon, Generation and ComEd
recorded the impacts of Illinois’ statutory rate change, which increased the total corporate income tax rate from 7.75% to 9.50% effective July 1, 2017. The
following table provides the one-time impact of the rate changes in 2017 for Exelon, Generation and ComEd:
Increase to Deferred Income Taxes
Increase in Regulatory Assets
(Decrease)/Increase to Income Tax Expense
Exelon
Generation
ComEd
$
250 $
270
(20)
20 $
—
20
270
270
—
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 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.
December 31, 2019
Increase to Deferred Income Tax Liability
Increase to Income Tax Expense, Net of Federal Taxes
December 31, 2018
Decrease to Deferred Income Tax Liability
Decrease to Income Tax Expense, Net of Federal Taxes
Exelon
Generation
PHI
DPL
$
$
23 $
23
50 $
50
9 $
9
53 $
53
— $
—
4 $
3
—
—
2
—
There were no material adjustments to income tax expense in 2017 as a result of changes in state apportionment.
Allocation of Tax Benefits (All Registrants)
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 benefit 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 federal tax benefits from Exelon under the Tax Sharing Agreement.
December 31, 2019(a)
December 31, 2018(b)
$
41 $
155
— $
1
14 $
48
3 $
26
7 $
2
6 $
—
Generation
ComEd
PECO
BGE
PHI
Pepco
DPL
December 31, 2017(c)
__________
(a) 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.
(b) 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.
102
10
16
—
—
7
1
—
—
291
Table of Contents
Combined Notes to Consolidated Financial Statements
(Dollars in millions, except per share data unless otherwise noted)
(c) ComEd, 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.
Research and Development Activities
In the fourth quarter 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.
Note 13 — Income Taxes
14. 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, most newly-hired Generation and BSC non-represented, non-
craft, 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, 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 14 — Retirement Benefits
The table below shows the pension and OPEB plans in which employees of each operating company participated at December 31, 2019:
Name of Plan:
Qualified Pension Plans:
Exelon Corporation Retirement Program(a)
Exelon Corporation Pension Plan for Bargaining Unit
Employees(a)
Exelon New England Union Employees Pension Plan(a)
Exelon Employee Pension Plan for Clinton, TMI and Oyster
Creek(a)
Pension Plan of Constellation Energy Group, Inc.(b)
Pension Plan of Constellation Energy Nuclear Group, LLC(c)
Nine Mile Point Pension Plan(c)
Constellation Mystic Power, LLC Union Employees Pension Plan
Including Plan A and Plan B(b)
Pepco Holdings LLC Retirement Plan(d)
Non-Qualified Pension Plans:
Exelon Corporation Supplemental Pension Benefit Plan and 2000
Excess Benefit Plan(a)
Exelon Corporation Supplemental Management Retirement
Plan(a)
Constellation Energy Group, Inc. Senior Executive Supplemental
Plan(b)
Constellation Energy Group, Inc. Supplemental Pension Plan(b)
Constellation Energy Group, Inc. Benefits Restoration Plan(b)
Constellation Energy Nuclear Plan, LLC Executive Retirement
Plan(c)
Constellation Energy Nuclear Plan, LLC Benefits Restoration
Plan(c)
Baltimore Gas & Electric Company Executive Benefit Plan(b)
Baltimore Gas & Electric Company Manager Benefit Plan(b)
Pepco Holdings LLC 2011 Supplemental Executive Retirement
Plan(d)
Conectiv Supplemental Executive Retirement Plan (d)
Pepco Holdings LLC Combined Executive Retirement Plan (d)
Atlantic City Electric Director Retirement Plan (d)
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
293
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
Table of Contents
Combined Notes to Consolidated Financial Statements
(Dollars in millions, except per share data unless otherwise noted)
Generation
ComEd
PECO
BGE
PHI
Pepco
DPL
ACE
Operating Company(e)
Note 14 — Retirement Benefits
Name of Plan:
OPEB Plans:
PECO Energy Company Retiree Medical Plan(a)
Exelon Corporation Health Care Program(a)
Exelon Corporation Employees’ Life Insurance Plan(a)
Exelon Corporation Health Reimbursement Arrangement
Plan(a)
Constellation Energy Group, Inc. Retiree Medical Plan(b)
Constellation Energy Group, Inc. Retiree Dental Plan(b)
Constellation Energy Group, Inc. Employee Life Insurance
Plan and Family Life Insurance Plan(b)
Constellation Mystic Power, LLC
Post-Employment Medical Account Savings Plan(b)
Exelon New England Union Post-Employment Medical
Savings Account Plan(a)
Retiree Medical Plan of Constellation Energy Nuclear
Group LLC(c)
Retiree Dental Plan of Constellation Energy Nuclear
Group LLC(c)
Nine Mile Point Nuclear Station, LLC Medical Care and
Prescription Drug Plan for Retired Employees(c)
X
X
X
X
X
X
X
X
X
X
X
X
X
X
X
X
X
X
X
X
X
X
X
X
Pepco Holdings LLC Welfare Plan for Retirees(d)
__________
(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.
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
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 2019, Exelon received an updated valuation of its pension and OPEB to reflect actual census data as of January 1, 2019. This
valuation resulted in an increase to the pension and OPEB obligations of $75 million and $36 million, respectively. Additionally, accumulated other
comprehensive loss increased by $39 million (after-tax) and regulatory assets and liabilities increased by $53 million and decreased by $5 million, respectively.
294
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Combined Notes to Consolidated Financial Statements
(Dollars in millions, except per share data unless otherwise noted)
Note 14 — 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
$
20,692 $
22,337 $
4,369 $
Pension Benefits
OPEB
2019
2018
2019
2018
Service cost
Interest cost
Plan participants’ contributions
Actuarial (gain) loss(a)
Plan amendments
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
357
883
—
2,322
68
(3)
(35)
1
405
802
—
(1,561)
(4)
—
(48)
—
(1,417)
22,868 $
(1,239)
20,692 $
Pension Benefits
93
188
44
250
—
—
(4)
—
(282)
4,658 $
OPEB
2019
2018
2019
2018
16,678 $
18,573 $
2,408 $
3,008
356
—
(1,417)
(35)
(945)
337
—
(1,239)
(48)
324
51
44
(282)
(4)
18,590 $
16,678 $
2,541 $
$
$
$
4,856
112
175
45
(540)
—
—
(4)
—
(275)
4,369
2,732
(136)
46
45
(275)
(4)
2,408
__________
(a) The pension actuarial loss in 2019 primarily reflects a decrease in the discount rate. The OPEB actuarial loss in 2019 primarily reflects a decrease in the discount rate.
The pension actuarial gain in 2018 primarily reflects an increase in the discount rate. The OPEB actuarial gain in 2018 primarily reflects an increase in the discount rate
and favorable health care claims experience.
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
OPEB
$
$
2019
2018
2019
2018
31 $
4,247
—
4,278
$
26 $
3,988
—
4,014
$
41 $
—
2,076
2,117
$
33
—
1,928
1,961
295
Table of Contents
Combined Notes to Consolidated Financial Statements
(Dollars in millions, except per share data unless otherwise noted)
Note 14 — Retirement Benefits
The following table provides the accumulated benefit obligation (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
Accumulated benefit obligation
Fair value of net plan assets
Components of Net Periodic Benefit Costs
Exelon
2019
2018
21,727
18,590
19,656
16,678
The majority of the 2019 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 4.31%. The majority of the 2019 OPEB cost is calculated using an expected long-term rate of return on plan assets of 6.67% for funded
plans and a discount rate of 4.30%.
A portion of the net periodic benefit cost for all plans is capitalized within the Consolidated Balance Sheets. The following tables present the components of
Exelon’s net periodic benefit costs, prior to capitalization, for the years ended December 31, 2019, 2018 and 2017.
Pension Benefits
2019
2018
2017(a)
2019
OPEB
2018
2017(a)
Components of net periodic
benefit cost:
Service cost
Interest cost
$
$
357
883
$
405
802
$
387
842
Expected return on assets
(1,225)
(1,252)
(1,196)
Amortization of:
Prior service cost (credit)
Actuarial loss
Settlement and other charges
Contractual termination benefits
—
414
17
1
2
629
3
—
1
607
3
—
93
$
188
(153)
(179)
45
1
—
$
112
175
(173)
(186)
66
1
—
Net periodic benefit cost
$
447 $
589 $
644 $
(5) $
(5) $
106
182
(162)
(188)
61
—
—
(1)
__________
(a) FitzPatrick net benefit costs are included for the period after acquisition.
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. As a result of new pension guidance effective on January 1, 2018, certain
balances have been reclassified on Exelon’s Consolidated Statements of Operations and Comprehensive Income for the year ended December 31, 2017. 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 the years ended December 31, 2019 and December 31, 2018 and in Other, net and Property,
plant and equipment, net, for the year ended December 31, 2017. For Generation and the Utility Registrants, the service cost and non–service cost components
are included
296
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Combined Notes to Consolidated Financial Statements
(Dollars in millions, except per share data unless otherwise noted)
Note 14 — Retirement Benefits
in Operating and maintenance expense and Property, plant and equipment, net on their consolidated financial statements.
For the Years Ended
December 31,
2019
2018
2017
Exelon
Generation(a)
ComEd
PECO
BGE
PHI
Pepco
DPL
ACE
$
442 $
135 $
96 $
12 $
61 $
95 $
25 $
15 $
583
643
204
227
177
176
18
29
60
64
67
94
15
25
6
13
16
12
13
__________
(a) FitzPatrick net benefit costs are included for the period after acquisition.
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 and losses and prior service costs (credits) is capitalized within
Exelon’s Consolidated Balance Sheets to reflect the expected regulatory recovery of these amounts, which 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, 2019, 2018 and 2017 for all plans
combined.
Pension Benefits
2019
2018
2017
2019
OPEB
2018
2017
Changes in plan assets and
benefit obligations recognized in
AOCI and regulatory assets
(liabilities):
Current year actuarial (gain) loss
$
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)
$
$
$
538 $
(414)
635 $
(629)
(222) $
(607)
80 $
(45)
(232) $
(66)
68
—
(3)
(17)
(4)
(2)
—
(3)
9
(1)
—
(3)
—
179
—
(1)
—
186
—
—
172
$
(3) $
(824) $
213
$
(112) $
169 $
3 $
3 $
(6) $
297
(401) $
107 $
(423) $
106 $
(55) $
(57) $
166
(61)
—
188
—
—
293
168
125
Table of Contents
Combined Notes to Consolidated Financial Statements
(Dollars in millions, except per share data unless otherwise noted)
Note 14 — Retirement Benefits
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, 2019 and 2018, respectively, for all plans combined:
Prior service (credit) cost
Actuarial loss
Total
Total included in AOCI
Total included in regulatory assets (liabilities)
Average Remaining Service Period
Pension Benefits
OPEB
2019
2018
2019
2018
$
$
$
$
39
$
7,662
7,701 $
4,068 $
3,633 $
(29) $
7,558
7,529 $
3,899 $
3,630 $
(158) $
565
407 $
177 $
230 $
(337)
531
194
70
124
For pension benefits, Exelon amortizes its unrecognized prior service costs and certain actuarial gains and losses, as applicable, based on participants’ average
remaining service periods.
For OPEB, Exelon amortizes its unrecognized prior service costs over participants’ average remaining service period to benefit eligibility age and amortizes
certain actuarial gains and 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
Assumptions
2019
2018
2017
11.7
8.7
9.3
12.0
8.8
9.5
11.8
8.8
9.6
The measurement of the plan obligations and costs of providing benefits under Exelon’s defined benefit and other postretirement 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 selecting 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, 2018, Exelon’s mortality assumption
was supported by an actuarial experience study of Exelon's plan participants and utilized the IRS's RP–2000 base table projected to 2012 with improvement
scale AA and projected thereafter with generational improvement scale BB two-dimensional adjusted to a 0.75% long-term rate reached in 2027. For the year
ended December 31, 2019, Exelon's mortality assumption utilizes the Society of Actuaries' 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, 2019 and 2018. Assumptions used to
determine year-end benefit obligations are the assumptions used to estimate the subsequent year’s net periodic benefit costs.
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Combined Notes to Consolidated Financial Statements
(Dollars in millions, except per share data unless otherwise noted)
Discount rate
Investment Crediting Rate
Rate of compensation increase
Mortality table
Note 14 — Retirement Benefits
Pension Benefits
OPEB
2019
2018
2019
2018
3.34% (a)
3.82% (b)
(c)
4.31% (a)
4.46% (b)
(c)
3.31% (a)
4.30% (a)
N/A
(c)
N/A
(c)
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)
Pri-2012 table with MP-
2019 improvement scale
(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
Health care cost trend on covered charges
N/A
N/A
__________
(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 3.02% - 3.44% and 3.27% - 3.4% for pension and OPEB plans, respectively, as of December 31, 2019 and 4.13% - 4.36% and 4.27% - 4.38% for
pension and OPEB plans, respectively, as of December 31, 2018.
(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, 2019, 2018 and 2017:
Exelon
Discount rate
Investment
Crediting Rate
Expected return on
plan assets
Rate of
compensation
increase
2019
Pension Benefits
2018
2017
2019
2018
2017
Other Postretirement Benefits
4.31% (a)
3.62% (a)
4.04% (a)
4.30% (a)
3.61% (a)
4.04% (a)
4.46% (b)
4.00% (b)
4.46% (b)
N/A
N/A
N/A
7.00% (c)
7.00% (c)
7.00% (c)
6.67% (c)
6.60% (c)
6.58% (c)
(d)
(d)
(e)
(d)
(d)
(e)
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)
Mortality table
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)
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)
5.00%
with
ultimate
trend of
5.00% in
2017
5.00%
with
ultimate
trend of
5.00% in
2017
5.50%
decreasing
to
ultimate
trend of
5.00% in
2017
N/A
Health care cost
trend on covered
charges
__________
(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 4.13%-4.36% and 4.27%-4.38% for pension and OPEB plans, respectively, for the year ended December 31, 2019; 3.49%-3.65% and 3.57%-3.68% for
pension and OPEB plans; respectively, for the year ended December 31, 2018; and 3.66%-4.11% and 4.00%-4.17% for pension and OPEB plans, respectively, for the
year ended December 31, 2017.
N/A
N/A
(b) The investment crediting rate above represents a weighted average rate.
(c) Not applicable to pension and other postretirement benefit plans that do not have plan assets.
(d) 3.25% through 2019 and 3.75% thereafter.
(e) The legacy Exelon, CEG and CENG pension and other postretirement plans used a rate of compensation increase of 3.25% through 2019 and 3.75% thereafter, while the
legacy PHI pension and OPEB plans used a weighted-average rate of compensation increase of 5% for all periods.
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Contributions
Combined Notes to Consolidated Financial Statements
(Dollars in millions, except per share data unless otherwise noted)
Note 14 — Retirement Benefits
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
Pension Benefits
2019(a)
2018(a)
2017(a)
2019
$
356
$
160
337
$
128
341
$
137
72
27
34
10
2
1
38
28
40
62
6
—
36
24
39
67
62
—
OPEB
2018
2017
51 $
46 $
15
5
1
14
15
12
—
11
4
—
14
12
11
—
64
11
5
—
14
32
10
2
ACE
__________
(a) Exelon's and Generation's pension contributions include $21 million related to the legacy CENG plans that was funded by CENG as provided in an Employee Matters
Agreement (EMA) between Exelon and CENG for the year ended December 31, 2017. There were no pension contributions for the years ended December 31, 2019 and
2018.
—
—
—
1
6
20
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 beginning in 2020.
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 other postretirement 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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Combined Notes to Consolidated Financial Statements
(Dollars in millions, except per share data unless otherwise noted)
Note 14 — Retirement Benefits
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 other postretirement plans in 2020:
Exelon
Generation
ComEd
PECO
BGE
PHI
Pepco
DPL
ACE
Qualified Pension Plans
Non-Qualified Pension Plans
OPEB
$
$
505
227
141
17
56
22
—
—
2
$
36
14
2
1
2
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, 2019 were:
2020
2021
2022
2023
2024
2025 through 2029
Total estimated future benefit payments through 2029
Plan Assets
Pension
Benefits
OPEB
$
$
1,227 $
1,252
1,295
1,310
1,324
6,770
13,178
$
42
16
3
—
16
7
7
—
—
258
263
267
270
275
1,402
2,735
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 other postretirement 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, 2019 were 18.80% and 14.40%, respectively, compared to an expected long-term return assumption of
7.00% and 6.67%, respectively. Exelon used an EROA of 7.00% and 6.69% to estimate its 2020 pension and OPEB costs, respectively.
Exelon’s pension and OPEB plan target asset allocations at December 31, 2019 and 2018 were as follows:
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Combined Notes to Consolidated Financial Statements
(Dollars in millions, except per share data unless otherwise noted)
Note 14 — Retirement Benefits
Asset Category
Equity securities
Fixed income securities
Alternative investments(a)
Total
December 31, 2019
December 31, 2018
Pension Benefits
OPEB
Pension Benefits
OPEB
33%
44%
23%
100%
46%
32%
22%
100%
35%
37%
28%
100%
47%
28%
25%
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, 2019. 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, 2019, there were no significant concentrations (defined as greater than 10% of plan assets) of risk in
Exelon’s pension and OPEB plan assets.
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, 2019 and 2018:
December 31, 2019(a)
Pension plan assets
Cash equivalents
Equities(b)
Fixed income:
U.S. Treasury and agencies
State and municipal debt
Corporate debt
Other(b)
Fixed income subtotal
Private equity
Hedge funds
Real estate
Private credit
Level 1
Level 2
Level 3
Not subject to leveling
Total
— $
—
— $
5
— $
2,589
$
258 $
3,616
1,294
—
—
—
1,294
—
—
—
—
280
56
4,342
461
5,139
—
—
—
—
—
—
245
—
245
—
—
—
237
487 $
258
6,210
1,574
56
4,587
1,312
7,529
1,391
1,126
1,030
1,166
—
—
—
851
851
1,391
1,126
1,030
929
Pension plan assets subtotal
$
5,168
$
5,139
$
302
7,916 $
18,710
Table of Contents
Combined Notes to Consolidated Financial Statements
(Dollars in millions, except per share data unless otherwise noted)
$
$
$
$
December 31, 2019(a)
OPEB plan assets
Cash equivalents
Equities
Fixed income:
U.S. Treasury and agencies
State and municipal debt
Corporate debt
Other
Fixed income subtotal
Hedge funds
Real estate
Private credit
OPEB plan assets subtotal
Total pension and OPEB plan assets(c)
December 31, 2018(a)
Pension plan assets
Cash equivalents
Equities(b)
Fixed income:
U.S. Treasury and agencies
State and municipal debt
Corporate debt
Other(b)
Fixed income subtotal
Private equity
Hedge funds
Real estate
Private credit
Note 14 — Retirement Benefits
Level 1
Level 2
Level 3
Not subject to leveling
Total
39 $
473
— $
3
— $
—
— $
719
39
1,195
17
—
—
258
275
—
—
—
64
107
49
78
298
—
—
—
—
—
—
—
—
—
—
—
—
—
—
201
201
293
109
131
81
107
49
537
774
293
109
131
787
$
301
$
5,955 $
5,440 $
— $
487 $
1,453
$
2,541
9,369 $
21,251
Level 1
Level 2
Level 3
Not subject to leveling
Total
350 $
3,364
— $
—
— $
2
— $
1,980
996
—
—
—
996
—
—
—
—
173
59
3,716
329
4,277
—
—
—
—
—
—
216
—
216
—
—
—
268
486 $
350
5,346
1,169
59
3,932
942
6,102
1,219
1,608
1,029
1,066
—
—
—
613
613
1,219
1,608
1,029
798
Pension plan assets subtotal
$
4,710
$
4,277
$
303
7,247
$
16,720
Table of Contents
December 31, 2018(a)
OPEB plan assets
Cash equivalents
Equities
Fixed income:
U.S. Treasury and agencies
State and municipal debt
Corporate debt
Other
Fixed income subtotal
Hedge funds
Real estate
Private credit
Combined Notes to Consolidated Financial Statements
(Dollars in millions, except per share data unless otherwise noted)
Note 14 — Retirement Benefits
Level 1
Level 2
Level 3
Not subject to leveling
Total
$
22 $
537
— $
2
— $
—
— $
508
22
1,047
11
—
—
183
194
—
—
—
56
126
48
72
302
—
—
—
—
—
—
—
—
—
—
—
—
—
—
170
170
411
132
132
67
126
48
425
666
411
132
132
— $
486 $
1,353 $
2,410
8,600 $
19,130
OPEB plan assets subtotal
$
753
$
304
$
Total pension and OPEB plan assets(c)
__________
(a) See Note 17—Fair Value of Financial Assets and Liabilities for a description of levels within the fair value hierarchy.
(b)
5,463 $
4,581 $
$
Includes derivative instruments of $2 million and less than $1 million, which have a total notional amount of $6,668 million and $5,991 million at December 31, 2019 and
2018, respectively. The notional principal amounts for these instruments provide one measure of the transaction volume outstanding as of the fiscal years ended and do
not represent the amount of the company’s exposure to credit or market loss.
(c) Excludes net liabilities of $120 million and $44 million at December 31, 2019 and 2018, respectively, which are required to reconcile to the fair value of net plan assets.
These items consist primarily of receivables or payables related to pending securities sales and purchases, 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, 2019 and 2018:
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
$
216
$
2 $
268 $
486
28
(7)
26
(4)
(2)
(12)
3
—
—
—
—
—
28
—
41
—
(100)
—
$
245
$
5 $
237 $
304
59
(7)
67
(4)
(102)
(12)
487
Table of Contents
Combined Notes to Consolidated Financial Statements
(Dollars in millions, except per share data unless otherwise noted)
Pension Assets
Balance as of January 1, 2018
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)
Balance as of December 31, 2018
__________
(a) Represents cash settlements only.
Note 14 — Retirement Benefits
Fixed income
Equities
Private
Credit
Total
$
232
$
2 $
224 $
458
(14)
(1)
19
(8)
(12)
—
—
—
—
—
9
—
35
—
—
$
216
$
2
$
268 $
(5)
(1)
54
(8)
(12)
486
There were no significant transfers between Level 1 and Level 2 during the year ended December 31, 2019 for the pension and OPEB plan assets.
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 17 - 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 seeking to maximize absolute returns using a broad
range of strategies to enhance returns and provide additional diversification. The fair value of 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, 2019, 2018 and 2017:
For the Year Ended
December 31,
2019
2018
2017
Exelon
Generation
ComEd
PECO BGE
PHI
Pepco
DPL
ACE
$
161 $
179
128
$
73
86
55
$
35
37
31
$
11
9
10
12
12
10
13 $
13
13
3 $
3 $
3
3
2
2
2
2
2
15. 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
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Combined Notes to Consolidated Financial Statements
(Dollars in millions, except per share data unless otherwise noted)
Note 15 — Derivative Financial Instruments
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 referencing 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 that 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.
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.
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Table of Contents
Combined Notes to Consolidated Financial Statements
(Dollars in millions, except per share data unless otherwise noted)
Note 15 — Derivative Financial Instruments
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
Electricity
NPNS
Changes in fair value of economic hedge
recorded to an offsetting regulatory asset or
liability(a)
Gas
NPNS
Electricity
NPNS
Gas
NPNS
Electricity
NPNS
ComEd
PECO(b)
BGE
Pepco
Electricity
DPL
Gas
NPNS
NPNS
Changes in fair value of economic hedge
recorded to an offsetting regulatory asset or
liability(c)
Fixed price contracts based on all requirements in the IPA procurement plans.
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 20% 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.
Fixed price contracts through full requirements contracts.
Exchange traded future contracts for 50% of estimated monthly purchase
requirements each month, including purchases for storage injections.
Fixed price contracts for all BGS requirements through full requirements
contracts.
Electricity
ACE
_________
(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, 2019 and 2018 and is not presented in the fair value tables below.
NPNS
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(Dollars in millions, except per share data unless otherwise noted)
Note 15 — 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, 2019 and 2018:
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)
December 31, 2018
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
$
675 $
3,506 $
72 $
287 $
(3,190) $
675 $
508
1,183
1,238
4,744
(236)
(3,713)
(380)
(616)
(1,140)
(4,853)
25
97
(38)
(11)
(49)
122
409
(877)
(4,067)
508
1,183
357
3,190
(204)
163
520
877
4,067
(111)
(315)
—
—
—
(32)
(269)
(301)
$
$
567 $
(109)
$
48
$
929 $
— $
868 $
(301)
801 $
3,505 $
105 $
121 $
(2,930) $
801 $
445
1,246
1,266
4,771
(473)
(3,429)
(474)
(947)
(1,203)
(4,632)
41
146
(74)
(20)
(94)
51
172
(913)
(3,843)
445
1,246
125
2,931
(447)
60
185
912
3,843
(251)
(698)
—
—
—
(26)
(223)
(249)
$
299 $
139 $
52 $
357 $
— $
548 $
(249)
_________
(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 immaterial and not reflected in the table above.
(b) Of the collateral posted/(received), $511 million and $(94) million represents variation margin on the exchanges at December 31, 2019 and 2018, respectively.
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(Dollars in millions, except per share data unless otherwise noted)
Note 15 — Derivative Financial Instruments
Economic Hedges (Commodity Price Risk)
Generation. For the years ended December 31, 2019, 2018 and 2017, 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.
Income Statement Location
Operating revenues
Purchased power and fuel
Total Exelon and Generation
2019
2018
Gain (Loss)
2017
$
$
— $
(204)
(204) $
(270) $
(47)
(317) $
(126)
(43)
(169)
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, 2019,
the percentage of expected generation hedged for the Mid-Atlantic, Midwest, New York and ERCOT reportable segments is 91%-94% and 61%-64% for 2020
and 2021, respectively.
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, 2019, 2018 and 2017,
net pre-tax commodity mark-to-market gains (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 $1,269 million and $1,420 million at December 31, 2019 and 2018, respectively, for Exelon and $569 million and $620 million at December 31, 2019 and
2018, 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 $231 million and $268 million at December 31, 2019 and 2018,
respectively.
The mark-to-market derivative assets and liabilities as of December 31, 2019 and 2018 and the mark-to-market gains (losses) for the years ended December 31,
2019, 2018 and 2017 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
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Combined Notes to Consolidated Financial Statements
(Dollars in millions, except per share data unless otherwise noted)
Note 15 — Derivative Financial Instruments
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.
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, 2019. 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, 2019
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
877
$
79
218
139
20 $
63
—
23
857
16
218
116
Number of
Counterparties
Greater than 10%
of Net Exposure
Net Exposure of
Counterparties
Greater than 10%
of Net Exposure
— $
1,313
$
106 $
1,207
— $
Net Credit Exposure by Type of Counterparty
Financial institutions
Investor-owned utilities, marketers, power producers
Energy cooperatives and municipalities
Other
Total
As of
December 31, 2019
$
$
—
—
9
930
235
33
1,207
__________
(a) As of December 31, 2019, credit collateral held from counterparties where Generation had credit exposure included $25 million of cash and $81 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, 2019, the Utility Registrants’ counterparty credit
risk with suppliers was immaterial.
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
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(Dollars in millions, except per share data unless otherwise noted)
Note 15 — Derivative Financial Instruments
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.
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,
2019
2018
$
$
(956) $
649
(307) $
(1,723)
1,105
(618)
__________
(a) Amount represents the gross fair value of out-of-the-money derivative contracts containing credit-risk-related contingent features ignoring the effects of master netting
agreements.
(b) Amount represents the offsetting fair value of in-the-money derivative contracts under legally enforceable master netting agreements with the same counterparty, which
reduces the amount of any liability for which a Registrant could potentially be required to post collateral.
(c) Amount represents the net fair value of out-of-the-money derivative contracts containing credit-risk related contingent features after considering the mitigating effects of
offsetting positions under master netting arrangements and reflects the actual net liability upon which any potential contingent collateral obligations would be based.
As of December 31, 2019 and 2018, 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,
2019
2018
$
982 $
264
103
112
1,509
418
367
47
44
2,104
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, and DPL’s credit rating. As of December 31, 2019,
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, 2019, they could have been required to post incremental collateral to its counterparties of $44 million, $50 million, and $11 million, respectively.
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Combined Notes to Consolidated Financial Statements
(Dollars in millions, except per share data unless otherwise noted)
Note 16 — Debt and Credit Agreements
16. Debt and Credit Agreements (All Registrants)
Short-Term Borrowings
Exelon Corporate, ComEd and BGE meet their short-term liquidity requirements primarily through the issuance of commercial paper. Generation and PECO
meet their short-term liquidity requirements primarily through the issuance of commercial paper and borrowings from the Exelon intercompany money pool.
Pepco, DPL, and ACE meet their short-term liquidity requirements primarily through the issuance of commercial paper and borrowings from the PHI
intercompany money pool. PHI Corporate meets its short-term liquidity requirements primarily through the issuance of short-term notes and the Exelon
intercompany money pool. The Registrants may use their respective credit facilities for general corporate purposes, including meeting short-term funding
requirements and the issuance of letters of credit.
Commercial Paper
The following table reflects the Registrants' commercial paper programs supported by the revolving credit agreements and bilateral credit agreements at
December 31, 2019 and 2018:
Commercial Paper Issuer
Exelon(d)
Generation
ComEd
PECO
BGE
PHI
Pepco
DPL
Maximum
Program Size at
December 31,
Outstanding
Commercial
Paper at
December 31,
Average Interest Rate on
Commercial Paper Borrowings for
the Year Ended December 31,
2019(a)(b)(c)
2018(a)(b)(c)
2019
2018
2019
2018
$
9,000 $
9,000 $
870 $
5,300
1,000
600
600
900
300
300
5,300
1,000
600
600
900
300
300
320
130
—
76
208
82
56
89
—
—
—
35
54
40
—
2.25%
1.84%
2.38%
2.39%
2.46%
N/A
2.56%
2.02%
2.15%
1.96%
2.14%
2.24%
2.18%
N/A
2.24%
2.07%
ACE
__________
(a) Excludes $1,400 million and $545 million in bilateral credit facilities at December 31, 2019 and 2018, respectively, and $159 million in credit facilities for project finance at
2.43%
300
300
2.21%
70
14
December 31, 2019 and 2018, respectively. These credit facilities do not back Generation's commercial paper program.
(b) 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. These facilities expire on
October 9, 2020. These facilities are solely utilized to issue letters of credit. At December 31, 2018, 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 $49 million, $33 million, $34 million, $5 million, $5
million, $5 million, and $5 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, 2019 and 2018, respectively. Exelon
Corporate had $136 million of outstanding commercial paper at December 31, 2019 and no outstanding commercial paper at the end of 2018.
(d)
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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Combined Notes to Consolidated Financial Statements
(Dollars in millions, except per share data unless otherwise noted)
Note 16 — Debt and Credit Agreements
At December 31, 2019, the Registrants had the following aggregate bank commitments, credit facility borrowings and available capacity under their respective
credit facilities:
Available Capacity at December 31, 2019
Borrower
Exelon(b)
Generation
Generation
Generation
ComEd
PECO
BGE
PHI
Pepco
DPL
Facility Type
Syndicated Revolver /
Bilaterals / Project Finance $
Aggregate Bank
Commitment(a)
Facility Draws
Outstanding
Letters of Credit
Actual
10,559 $
— $
1,443 $
9,116 $
Syndicated Revolver
Bilaterals
Project Finance
Syndicated Revolver
Syndicated Revolver
Syndicated Revolver
Syndicated Revolver
Syndicated Revolver
Syndicated Revolver
5,300
1,400
159
1,000
600
600
900
300
300
—
—
—
—
—
—
—
—
—
769
545
120
2
—
—
—
—
—
4,531
855
39
998
600
600
900
300
300
To Support
Additional
Commercial
Paper(b)
7,353
4,211
—
—
868
600
524
692
218
244
ACE
__________
(a) Excludes $142 million of credit facility agreements arranged at minority and community banks at Generation, ComEd, PECO, BGE, Pepco, DPL and ACE with aggregate
Syndicated Revolver
300
300
—
—
230
commitments of $44 million, $33 million, $33 million, $8 million, $8 million, $8 million and $8 million, respectively. These facilities expire on October 9, 2020. These
facilities are solely utilized to issue letters of credit. As of December 31, 2019, letters of credit issued under these facilities totaled $5 million, $5 million, $2 million for
Generation, ComEd, and BGE, respectively.
Includes $600 million aggregate bank commitment related to Exelon Corporate. Exelon Corporate had $6 million and $9 million outstanding letters of credit at
December 31, 2019 and 2018, respectively. Exelon Corporate had $458 million in available capacity to support additional commercial paper at December 31, 2019.
(b)
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Combined Notes to Consolidated Financial Statements
(Dollars in millions, except per share data unless otherwise noted)
Note 16 — Debt and Credit Agreements
The following tables present the short-term borrowings activity for Exelon, Generation, ComEd, PECO, BGE, PHI, Pepco, DPL and ACE during 2019 and 2018.
December 31, 2019
Average borrowings
Maximum borrowings outstanding
Average interest rates, computed on a daily
basis
Average interest rates, at December 31
December 31, 2018
Average borrowings
$
$
Maximum borrowings outstanding
Average interest rates, computed on a daily
basis
Average interest rates, at December 31
__________
(a)
Exelon(a)
Generation
ComEd
PECO
BGE
PHI
Pepco
DPL
ACE
$
472
890
2.25%
2.25%
$
13
357
$
236
465
— $
21
103
298
N/A $
N/A
$
45
144
$
21
125
51
180
1.84%
1.84%
2.38%
2.38%
2.39%
2.39%
2.46%
2.46%
N/A
N/A
2.56%
2.56%
2.02%
2.02%
2.43%
2.43%
Exelon(a)
Generation
ComEd
PECO
BGE
PHI
Pepco
DPL
ACE
$
531
1,237
2.21%
2.15%
$
37
583
$
154
520
$
68
350
65
239
1.96%
1.96%
2.14%
2.14%
2.24%
2.24%
2.18%
2.18%
N/A $
N/A
N/A
N/A
$
22
90
$
87
245
95
210
2.24%
2.24%
2.07%
2.07%
2.21%
2.21%
Includes $3 million and $4 million average borrowings related to Exelon Corporate at December 31, 2019 and 2018, respectively. Exelon Corporate had $144 million and
$95 million maximum borrowings outstanding at December 31, 2019 and 2018, with 1.92% and 1.93% average interest rates computed on a daily basis for 2019 and
2018, and 1.92% and 1.93% average interest rates at December 31, 2019 and 2018, respectively.
Short-Term Loan Agreements
On March 23, 2017, Exelon Corporate entered into a term loan agreement for $500 million, which was renewed on March 22, 2018 with an expiration of March
21, 2019. The loan agreement was renewed on March 20, 2019 and will expire on March 19, 2020. Pursuant to the loan agreement, loans made thereunder
bear interest at a variable rate equal to LIBOR plus 0.95% and all indebtedness thereunder is unsecured. The loan agreement is reflected in Exelon's
Consolidated Balance Sheet within Short-Term borrowings.
Revolving Credit Agreements
On May 26, 2016, Exelon Corporate, Generation, ComEd, PECO and BGE entered into amendments to each of their respective syndicated revolving credit
facilities, which extended the maturity of each of the facilities to May 26, 2021. Exelon Corporate also increased the size of its facility from $500 million to $600
million. On May 26, 2016, PHI, Pepco, DPL and ACE entered into an amendment to their Second Amended and Restated Credit Agreement dated as of August
1, 2011, which (i) extended the maturity date of the facility to May 26, 2021, (ii) removed PHI as a borrower under the facility, (iii) decreased the size of the
facility from $1.5 billion to $900 million and (iv) aligned its financial covenant from debt to capitalization leverage ratio to interest coverage ratio. On May 26,
2018, each of the Registrants' respective syndicated revolving credit facilities had their maturity dates extended to May 26, 2023.
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(Dollars in millions, except per share data unless otherwise noted)
Note 16 — Debt and Credit Agreements
Bilateral Credit Agreements
The following table reflects the bilateral credit agreements at December 31, 2019:
Registrant
Date Initiated
Generation(b)
Generation(c)
Generation(c)
Generation(c)
Generation(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
Latest Amendment Date
October 24, 2019
January 4, 2019
January 4, 2019
N/A
N/A
N/A
N/A
N/A
Maturity Date(a)
Amount
October 24, 2020
$
March 1, 2021
April 5, 2021
March 31, 2021
N/A
N/A
N/A
November 21, 2020
200
100
150
100
200
100
300
150
Generation(c)
__________
(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
November 21, 2019
November 21, 2021
100
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.
(c) Bilateral credit agreements solely support the issuance of letters of credit and do not back Generation's commercial paper program.
Borrowings under Exelon Corporate’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
27.5
127.5
27.5
127.5
7.5
107.5
—
90.0
—
100.0
7.5
107.5
7.5
107.5
7.5
107.5
Exelon
Generation
ComEd
PECO
BGE
Pepco
DPL
ACE
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. 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, 2019 and December 31, 2018, $79 million in variable 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.
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Long-Term Debt
Combined Notes to Consolidated Financial Statements
(Dollars in millions, except per share data unless otherwise noted)
Note 16 — Debt and Credit Agreements
The following tables present the outstanding long-term debt at the Registrants as of December 31, 2019 and 2018:
Exelon
Long-term debt
First mortgage bonds(a)
Senior unsecured notes
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(b)
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(c)
Rates
Maturity
Date
December 31,
2019
2018
2020 - 2049 $
17,486 $
1.70% -
2.45% -
2.40% -
2.50% -
2.53% -
1.63% -
7.61% -
2.29% -
3.18% -
7.90%
7.60%
6.35%
2.70%
3.15%
7.99%
3.50%
3.95%
5.40%
7.72%
5.55%
2.00%
6.00%
4.91%
2020 - 2046
2021 - 2049
2025 - 2036
2020
2020 - 2053
2022
2024
2022 - 2031
2027
2023
2023
2031 - 2037
2020 - 2024
1,150
1,150
10,685
3,300
412
3
154
55
222
10
40
50
1,182
811
35,560
(72)
(214)
765
(4,710)
16,496
11,285
2,900
435
39
188
73
112
22
59
50
1,253
849
34,911
(66)
(216)
795
(1,349)
34,075
206
81
103
390
—
390
$
31,329 $
2033 $
206 $
2028
2033
81
103
390
—
$
390 $
Subordinated debentures to ComEd Financing III
Subordinated debentures to PECO Trust III
Subordinated debentures to PECO Trust IV
6.75% -
6.35%
7.38%
5.75%
Total long-term debt to financing trusts
Unamortized debt issuance costs
Long-term debt to financing trusts
__________
(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) Bond amount totaling $110 million was previously disclosed within the first mortgage bonds line item, as it was classified as a secured tax-exempt bond. In 2019, the
callable bond was reissued as an unsecured tax-exempt bond, and is presented as such within this section.
(c) 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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Generation
Combined Notes to Consolidated Financial Statements
(Dollars in millions, except per share data unless otherwise noted)
Note 16 — Debt and Credit Agreements
Rates
Maturity
Date
December 31,
2019
2018
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(a)
Notes payable and 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
Long-term debt to financing trust(b)
Subordinated debentures to ComEd Financing III
Total long-term debt to financing trusts
Unamortized debt issuance costs
Long-term debt to financing trusts
2.95% -
2.50% -
2.53% -
2.29% -
3.18% -
7.60%
2.70%
3.15%
4.26%
6.00%
4.91%
Rates
2.55% -
6.45%
7.49%
2020 - 2042 $
5,420 $
6,019
2025 - 2036
2020
2020 - 2028
2031 - 2037
2020 - 2024
412
3
115
1,182
811
7,943
(5)
(42)
78
(3,182)
$
4,792 $
435
39
164
1,253
849
8,759
(6)
(51)
91
(906)
7,887
Maturity
Date
December 31,
2019
2018
2020 - 2049 $
8,578 $
8,179
2053
8
8,586
(27)
(68)
(500)
$
7,991 $
8
8,187
(23)
(63)
(300)
7,801
206
206
(1)
205
6.35%
2033 $
206 $
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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Table of Contents
PECO
Long-term debt
First mortgage bonds(a)
Loan Agreement
Total long-term debt
Unamortized debt discount and premium, net
Unamortized debt issuance costs
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
Combined Notes to Consolidated Financial Statements
(Dollars in millions, except per share data unless otherwise noted)
Rates
1.70% -
5.95%
2.00%
Note 16 — Debt and Credit Agreements
Maturity
Date
December 31,
2019
2018
2021 - 2049 $
3,400 $
3,075
2023
50
3,450
(21)
(24)
50
3,125
(18)
(23)
$
3,405 $
3,084
6.75% -
7.38%
5.75%
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
Rates
Maturity
Date
December 31,
2019
2018
2.40% -
6.35%
2021 - 2049 $
3,300 $
3,300
(9)
(21)
2,900
2,900
(6)
(18)
$
3,270 $
2,876
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PHI
Combined Notes to Consolidated Financial Statements
(Dollars in millions, except per share data unless otherwise noted)
Note 16 — Debt and Credit Agreements
Long-term debt
First mortgage bonds(a)
Senior unsecured notes
Unsecured Tax-Exempt Bonds(b)
Medium-terms notes (unsecured)
Transition bonds(c)
Notes payable and 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
Rates
Maturity
Date
December 31,
2019
2018
1.76% -
1.63% -
7.61% -
3.54% -
7.90%
7.45%
5.40%
7.72%
5.55%
7.99%
2021 - 2049 $
5,508 $
5,242
2032
2022 - 2031
2027
2023
2021 - 2027
185
222
10
40
30
185
112
22
59
16
5,995
5,636
4
(19)
583
(103)
4
(14)
633
(125)
$
6,460
$
6,134
_________
(a) Substantially all of Pepco's, DPL's, and ACE's assets are subject to the lien of its respective mortgage indenture.
(b) Bond amount totaling $110 million was previously disclosed within the first mortgage bonds line item, as it was classified as a secured tax-exempt bond. In 2019, the
callable bond was reissued as an unsecured tax-exempt bond, and is presented as such within this section.
(c) Transition bonds are recorded as part of Long-term debt within ACE's Consolidated Balance Sheets.
Pepco
Long-term debt
First mortgage bonds(a)
Unsecured Tax-Exempt Bonds(b)
Notes payable and 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
Maturity
Date
December 31,
2019
2018
3.05% -
3.54% -
7.90%
1.70%
7.99%
2022 - 2048 $
2,775 $
2,735
2022
2021 - 2027
110
12
—
16
2,897
2,751
2
(35)
(2)
2
(34)
(15)
$
2,862
$
2,704
__________
(a) Substantially all of Pepco's assets are subject to the lien of its respective mortgage indenture.
(b) Bond amount totaling $110 million was previously disclosed within the first mortgage bonds line item, as it was classified as a secured tax-exempt bond. In 2019, the
callable bond was reissued as an unsecured tax-exempt bond, and is presented as such within this section.
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DPL
Combined Notes to Consolidated Financial Statements
(Dollars in millions, except per share data unless otherwise noted)
Note 16 — Debt and Credit Agreements
Long-term debt
First mortgage bonds(a)
Unsecured Tax-Exempt Bonds
Medium-terms notes (unsecured)
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
1.76% -
1.63% -
7.61% -
Maturity
Date
December 31,
2019
2018
4.27%
5.40%
7.72%
3.54%
2023 - 2049 $
1,446 $
2024 - 2031
2027
2027
112
10
10
1,370
112
22
—
1,578
1,504
1
(12)
(80)
2
(12)
(91)
$
1,487
$
1,403
__________
(a) Substantially all of DPL's assets are subject to the lien of its respective mortgage indenture.
ACE
Long-term debt
First mortgage bonds(a)
Transition bonds(b)
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
3.38% -
Maturity
Date
December 31,
2019
2018
6.80%
5.55%
3.54%
2021 - 2049 $
1,287 $
1,137
2023
2027
40
8
59
—
$
1,335
$
1,196
(1)
(7)
(20)
(1)
(7)
(18)
$
1,307
$
1,170
__________
(a) Substantially all of ACE's assets are subject to the lien of its respective mortgage indenture.
(b) Maturities of ACE's Transition Bonds outstanding at December 31, 2019 are $19 million in 2020 and $21 million in 2021.
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Combined Notes to Consolidated Financial Statements
(Dollars in millions, except per share data unless otherwise noted)
Note 16 — Debt and Credit Agreements
Long-term debt maturities at Exelon, Generation, ComEd, PECO, BGE, PHI, Pepco, DPL and ACE in the periods 2020 through 2024 and thereafter are as
follows:
Year
2020
2021
2022
2023
2024
Exelon
Generation
ComEd
PECO
BGE
PHI
Pepco
DPL
ACE
$
4,710
$
3,182 $
1,517
3,088
855
1,596
2
1,024
1
792
500
350
—
—
250
$
—
$
— $
103 $
300
350
50
—
300
250
300
—
265
314
504
553
2 $
2
311
1
401
80 $
2
2
502
1
991
20
261
1
1
151
901
2,450
4,256
2,180
$
3,300
$
5,995
$
2,897
$
1,578
$
1,335
Thereafter
Total
$
24,184 (a)
35,950
$
2,942
7,943 $
7,691 (b)
8,791
$
2,934 (c)
3,634
__________
(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, 2019, the Registrants are in compliance with debt covenants, except for Antelope Valley's nonrecourse debt event of default as discussed
below.
Nonrecourse Debt
Exelon and Generation have issued nonrecourse debt financing, in which approximately $2.8 billion of generating assets have been pledged as collateral at
December 31, 2019. 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, 2019, approximately $485 million was outstanding. In addition, Generation has issued letters of credit to support its equity
investment in the project. As of December 31, 2019, Generation had $38 million in letters of credit outstanding related to the project. In 2017, Generation’s
interests in Antelope Valley were also contributed to and are pledged as collateral for the EGR IV financing structure referenced below.
Antelope Valley sells all of its output to PG&E through a PPA. On January 29, 2019, PG&E filed for protection under Chapter 11 of the U.S. Bankruptcy Code,
which created an event of default for Antelope Valley’s nonrecourse debt that provides 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 ongoing event of default and 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 and
continues to be classified as current as of December 31, 2019. Further, distributions from Antelope Valley to EGR IV are currently suspended.
Continental Wind. In September 2013, Continental Wind, LLC (Continental Wind), an indirect subsidiary of Exelon and Generation, completed the issuance
and sale of $613 million senior secured notes. Continental Wind owns
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Combined Notes to Consolidated Financial Statements
(Dollars in millions, except per share data unless otherwise noted)
Note 16 — Debt and Credit Agreements
and operates a portfolio of wind farms in Idaho, Kansas, Michigan, Oregon, New Mexico and Texas with a total net capacity of 667MW. The net proceeds were
distributed to Generation for 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, 2019, $447 million was outstanding.
In addition, Continental Wind entered into a $131 million letter of credit facility and $10 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, 2019, the Continental Wind letter of credit facility had $115
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 22 - 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 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, 2019, $106 million was outstanding.
In 2017, Generation’s interests in Renewable Power Generation were contributed to EGRP. Refer to Note 22 - Variable Interest Entities for additional information
on EGRP.
SolGen. In September 2016, SolGen, LLC (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, 2019, $131 million was outstanding. In
2017, Generation’s interests in SolGen were also contributed to and are pledged as collateral for the EGR IV financing structure referenced below.
ExGen Renewables IV. In November 2017, EGR IV, an indirect subsidiary of Exelon and Generation, entered into an $850 million nonrecourse senior
secured term loan credit facility agreement. Generation’s interests in EGRP, Antelope Valley, SolGen, and Albany Green Energy were all contributed to and are
pledged as collateral for this financing. The net proceeds of $785 million, after the initial funding of $50 million for debt service and liquidity reserves as well as
deductions for original discount and estimated costs, fees and expenses incurred in connection with the execution and delivery of the credit facility agreement,
were distributed to Generation for general corporate purposes. The $50 million of debt service and liquidity reserves was treated as restricted cash in Exelon’s
and Generation’s Consolidated Balance Sheets and Consolidated Statements of Cash Flows. The loan is scheduled to mature on November 28, 2024. The term
loan bears interest at a variable rate equal to LIBOR + 3%, subject to a 1% LIBOR floor with interest payable quarterly. As of December 31, 2019, $796 million
was outstanding. 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.
Although Antelope Valley’s debt is in default, it is nonrecourse to EGR IV. However, if in the future Antelope Valley were to file for bankruptcy protection as a
result of events culminating from PG&E’s bankruptcy proceedings this would represent an event of default for EGR IV’s debt that would provide the lender with
an opportunity to accelerate EGR IV’s debt. See Note 22 - Variable Interest Entities for additional information on EGRP.
17. Fair Value of Financial Assets and Liabilities (All Registrants)
Exelon measure and records 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.
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Combined Notes to Consolidated Financial Statements
(Dollars in millions, except per share data unless otherwise noted)
Note 17 — Fair Value of Financial Assets and Liabilities
•
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.
Fair Value of Financial Liabilities Recorded at the Carrying Amount
The following tables present the carrying amounts and fair values of the Registrants’ short-term liabilities, long-term debt, SNF obligation, and trust preferred
securities (long-term debt to financing trusts or junior subordinated debentures) as of December 31, 2019 and 2018. 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, 2019
Fair Value
December 31, 2018
Fair Value
Carrying Amount
Carrying Amount
Level 2
Level 3
Total
Level 2
Level 3
Total
Long-Term Debt, including amounts due within one year(a)
$
BGE
PECO
Exelon
ComEd
Generation
36,039 $
7,974
8,491
3,405
3,270
6,563
2,864
1,567
1,327
Long-Term Debt to Financing Trusts(a)
Pepco
ACE
DPL
PHI
37,453 $
7,304
9,848
3,868
3,649
5,902
3,198
1,408
1,026
Exelon
ComEd
PECO
SNF Obligation
Exelon
$
$
390 $
205
184
— $
—
—
2,580 $
1,366
—
50
—
1,164
388
311
464
428 $
227
201
40,033 $
8,670
9,848
3,918
3,649
7,066
3,586
1,719
1,490
35,424 $
8,793
8,101
3,084
2,876
6,259
2,719
1,494
1,188
33,711 $
7,467
8,390
3,157
2,950
5,436
2,901
1,303
987
428 $
227
201
390 $
205
184
— $
—
—
2,158 $
1,443
—
50
—
665
196
193
275
400 $
209
191
35,869
8,910
8,390
3,207
2,950
6,101
3,097
1,496
1,262
400
209
191
949
1,199 $
1,199
1,055 $
1,055
— $
—
1,055 $
1,055
1,171 $
1,171
949 $
949
Generation
________
(a) Includes unamortized debt issuance costs which are not fair valued. Refer to Note 16 — Debt and Credit Agreements for each Registrants’ unamortized debt issuance
costs.
Exelon uses the following methods and assumptions to estimate fair value of financial liabilities recorded at carrying cost:
949
— $
—
323
Table of Contents
Combined Notes to Consolidated Financial Statements
(Dollars in millions, except per share data unless otherwise noted)
Type
Long-term debt, including amounts due within one year
Registrants
Level
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
2
2
3
3
3
All
Exelon, Generation,
DPL
Exelon, Pepco, DPL,
ACE
Exelon, Generation
Exelon, Generation,
Pepco
Long Term Debt to Financing
Trusts
3
Exelon, ComEd, PECO
SNF Obligation
2
Exelon, Generation
Note 17 — Fair Value of Financial Assets and Liabilities
Valuation
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.
Debt rates are reset on a regular basis and the carrying value approximates fair value.
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
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.
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 2030.
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Combined Notes to Consolidated Financial Statements
(Dollars in millions, except per share data unless otherwise noted)
Note 17 — Fair Value of Financial Assets and Liabilities
Recurring Fair Value Measurements
The following tables present assets and liabilities measured and recorded at fair value in the Registrants' Consolidated Balance Sheets on a recurring basis and
their level within the fair value hierarchy as of December 31, 2019 and 2018:
As of 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
Exelon
Generation
$
639 $
— $
— $
— $
639 $
214 $
— $
— $
— $
214
365
87
3,353
1,753
—
—
—
452
365
87
1,388
6,494
3,353
1,753
Assets
Cash equivalents(a)
NDT fund investments
Cash equivalents(b)
Equities
Fixed income
Corporate debt
U.S. Treasury and
agencies
Foreign governments
State and municipal
debt
Other(c)
—
—
—
—
257
254
—
—
511
—
—
—
41
41
—
1,469
257
1,808
—
—
—
131
42
90
33
Fixed income subtotal
1,808
1,765
Private credit
Private equity
Real estate
—
—
—
—
—
—
NDT fund investments
subtotal(d)
5,526
3,605
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(e)(f)
Commodity derivative
assets subtotal
50
81
—
—
131
768
—
(908)
(140)
—
—
12
78
90
2,491
1,485
37
60
(2,162)
(588)
366
Total assets
6,156
4,061
—
—
—
—
953
953
508
402
607
1,726
1,939
42
90
986
—
1,469
1,808
—
—
—
131
42
90
33
4,783
1,808
1,765
762
402
607
—
—
—
—
—
—
—
—
257
—
—
—
—
257
254
—
—
—
1,388
—
—
—
—
953
953
508
402
607
452
6,494
1,726
1,939
42
90
986
4,783
762
402
607
3,858
13,500
5,526
3,605
511
3,858
13,500
—
—
—
—
—
—
—
—
50
81
12
119
262
4,744
97
(3,658)
1,183
15,584
4
25
—
—
29
768
—
(908)
(140)
—
—
—
25
25
—
—
—
—
—
2,491
1,485
37
60
(2,162)
(588)
—
—
—
—
—
—
—
—
5,629
3,996
366
957
1,468
—
3,858
4
25
—
25
54
4,744
97
(3,658)
1,183
14,951
957
1,509
—
3,858
325
Table of Contents
Combined Notes to Consolidated Financial Statements
(Dollars in millions, except per share data unless otherwise noted)
Note 17 — Fair Value of Financial Assets and Liabilities
As of 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
Exelon
Generation
Liabilities
Commodity derivative liabilities
Economic hedges
(1,071)
(2,855)
(1,228)
Proprietary trading
Effect of netting and
allocation of
collateral(e)(f)
Commodity derivative
liabilities subtotal
Deferred compensation obligation
Total liabilities
Total net assets
—
(34)
(15)
1,071
2,714
—
—
—
(175)
(147)
(322)
802
(441)
—
(441)
—
—
—
—
—
—
(5,154)
(1,071)
(2,855)
(49)
—
(34)
4,587
1,071
2,714
(616)
(147)
(763)
—
—
—
(175)
(41)
(216)
(927)
(15)
802
(140)
—
(140)
—
—
—
—
—
—
(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
As of December 31, 2018
Level 1
Level 2
Level 3
Not subject to
leveling
Total
Level 1
Level 2
Level 3
Not subject to
leveling
Total
Exelon
Generation
Assets
Cash equivalents(a)
NDT fund investments
$
1,243
$
— $
— $
— $
1,243
$
581 $
— $
— $
— $
581
Cash equivalents(b)
252
86
Equities
Fixed income
Corporate debt
U.S. Treasury and
agencies
Foreign governments
State and municipal
debt
Other(c)
2,918
1,591
—
1,593
2,081
—
—
—
99
50
149
30
Fixed income subtotal
2,081
1,921
Private credit
Private equity
Real estate
NDT fund investments
subtotal(d)
—
—
—
—
—
—
—
—
230
—
—
—
—
230
313
—
—
—
338
252
86
1,381
5,890
2,918
1,591
—
—
—
—
846
846
367
329
510
1,823
2,180
50
149
876
—
1,593
2,081
—
—
—
99
50
149
30
5,078
2,081
1,921
680
329
510
—
—
—
—
—
—
—
—
230
—
—
—
—
230
313
—
—
—
1,381
—
—
—
—
846
846
367
329
510
338
5,890
1,823
2,180
50
149
876
5,078
680
329
510
5,251
3,598
543
3,433
12,825
5,251
3,598
543
3,433
12,825
326
Table of Contents
Combined Notes to Consolidated Financial Statements
(Dollars in millions, except per share data unless otherwise noted)
Note 17 — Fair Value of Financial Assets and Liabilities
As of December 31, 2018
Level 1
Level 2
Level 3
Not subject to
leveling
Total
Level 1
Level 2
Level 3
Not subject to
leveling
Total
Exelon
Generation
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(e)(f)
Commodity derivative
assets subtotal
Total assets
Liabilities
Commodity derivative liabilities
48
72
—
—
120
541
—
—
—
15
70
85
—
—
—
38
38
2,760
69
1,470
77
(582)
(2,357)
(732)
—
—
—
—
—
—
—
—
48
72
15
108
243
4,771
146
5
24
—
—
29
541
—
—
—
—
22
22
—
—
—
—
—
2,760
1,470
69
77
(3,671)
(582)
(2,357)
(732)
—
—
—
—
—
—
—
—
(41)
6,573
472
4,155
815
1,396
—
3,433
1,246
15,557
(41)
5,820
472
4,092
815
1,358
—
3,433
Economic hedges
(642)
(2,963)
(1,276)
Proprietary trading
Effect of netting and
allocation of
collateral(e)(f)
Commodity derivative
liabilities subtotal
Deferred compensation obligation
Total liabilities
—
(73)
(21)
639
2,581
(3)
—
(3)
(455)
(137)
(592)
808
(489)
—
(489)
—
—
—
—
—
—
(4,881)
(642)
(2,963)
(1,027)
(94)
4,028
(947)
(137)
(1,084)
—
(73)
(21)
639
2,581
(3)
—
(3)
(455)
(35)
(490)
808
(240)
—
(240)
—
—
—
—
—
—
5
24
—
22
51
4,771
146
(3,671)
1,246
14,703
(4,632)
(94)
4,028
(698)
(35)
(733)
$
907
$
3,563
$
6,570
$
3,433
$
Total net assets
__________
(a) Exelon excludes cash of $373 million and $458 million at December 31, 2019 and 2018, respectively, and restricted cash of $110 million and $80 million at December 31,
2019 and 2018, respectively, and includes long-term restricted cash of $177 million and $185 million at December 31, 2019 and 2018, respectively, which is reported in
Other deferred debits in the Consolidated Balance Sheets. Generation excludes cash of $177 million and $283 million at December 31, 2019 and 2018, respectively and
restricted cash of $58 million and $39 million at December 31, 2019 and 2018, respectively.
Includes $90 million and $50 million of cash received from outstanding repurchase agreements at December 31, 2019 and 2018, respectively, and is offset by an
obligation to repay upon settlement of the agreement as discussed in (d) below.
Includes derivative instruments of $2 million and $44 million, which have a total notional amount of $724 million and $1,432 million at December 31, 2019 and 2018,
respectively. The notional principal amounts for these instruments provide one measure of the transaction volume outstanding as of the fiscal years ended and do not
represent the amount of the company's exposure to credit or market loss.
(b)
(c)
5,817
$
3,602
$
14,473
$
1,118
$
3,433
$
13,970
(d) Excludes net liabilities of $147 million and $130 million at December 31, 2019 and 2018, respectively. These items consist of receivables related to pending securities
sales, interest and dividend receivables, repurchase agreement obligations, and payables related to pending securities purchases. The repurchase agreements are
generally short-term in nature with durations generally of 30 days or less.
(e) Collateral posted/(received) from counterparties totaled $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. Collateral posted/(received) from
327
Table of Contents
Combined Notes to Consolidated Financial Statements
(Dollars in millions, except per share data unless otherwise noted)
counterparties totaled $57 million, $224 million and $76 million allocated to Level 1, Level 2 and Level 3 mark-to-market derivatives, respectively, as of December 31,
2018.
(f) Of the collateral posted/(received), $511 million and $(94) million represents variation margin on the exchanges as of December 31, 2019 and 2018, respectively.
As of December 31, 2019, Generation has outstanding commitments to invest in fixed income, private credit, private equity and real estate investments of
approximately $85 million, $166 million, $375 million and $427 million, respectively. These commitments will be funded by Generation’s existing NDT funds.
Exelon and Generation hold investments without readily determinable fair values with carrying amounts of $69 million as of December 31, 2019. Changes were
immaterial in fair value, cumulative adjustments and impairments for the year ended December 31, 2019.
Note 17 — Fair Value of Financial Assets and Liabilities
As of December 31, 2019
Level 1
Level 2
Level 3
Total
Level 1
Level 2
Level 3
Total
Level 1
Level 2
Level 3
Total
ComEd
PECO
BGE
Assets
Cash equivalents(a)
$
280
$
—
$
— $
280 $
15
$
— $
— $
15 $
— $
—
$
— $
Rabbi trust investments
Mutual funds
Life insurance contracts
Rabbi trust investments
subtotal
Total assets
Liabilities
Deferred compensation obligation
Mark-to-market derivative
liabilities(b)
Total liabilities
—
—
—
280
—
—
—
Total net assets (liabilities)
$
280
$
—
—
—
—
(8)
—
(8)
(8)
—
—
—
—
—
(301)
(301)
—
—
—
280
(8)
(301)
(309)
$
(301)
$
(29)
$
—
—
—
—
—
—
—
$
— $
8
11
19
34
(9)
—
(9)
25
$
8
—
8
8
—
—
—
8
$
—
—
—
—
(5)
—
(5)
(5)
—
—
—
—
—
—
—
$
— $
—
11
11
11
(9)
—
(9)
2
8
—
8
23
—
—
—
23
328
$
—
8
—
8
8
(5)
—
(5)
3
Table of Contents
Combined Notes to Consolidated Financial Statements
(Dollars in millions, except per share data unless otherwise noted)
Note 17 — Fair Value of Financial Assets and Liabilities
As of December 31, 2018
Level 1
Level 2
Level 3
Total
Level 1
Level 2
Level 3
Total
Level 1
Level 2
Level 3
Total
ComEd
PECO
BGE
Assets
Cash equivalents(a)
$
209
$
—
$
— $
209 $
111
$
— $
— $
111 $
4
$
—
$
— $
Rabbi trust investments
Mutual funds
Life insurance contracts
Rabbi trust investments
subtotal
Total assets
Liabilities
Deferred compensation obligation
Mark-to-market derivative
liabilities(b)
Total liabilities
—
—
—
209
—
—
—
—
—
—
—
(6)
—
(6)
—
—
—
—
—
(249)
(249)
—
—
—
7
—
7
209
118
(6)
(249)
(255)
—
—
—
—
10
10
10
(10)
—
(10)
—
—
—
—
—
—
—
7
10
17
128
(10)
—
(10)
6
—
6
10
—
—
—
—
—
—
—
(5)
—
(5)
—
—
—
—
—
—
—
4
6
—
6
10
(5)
—
(5)
Total net assets (liabilities)
__________
(a) ComEd excludes cash of $90 million and $93 million at December 31, 2019 and 2018 and restricted cash of $33 million and $28 million at December 31, 2019 and 2018,
(6)
$
(249)
$
(46)
$
— $
— $
— $
(5)
$
118
118
209
10
$
$
$
$
$
5
respectively, and includes long-term restricted cash of $163 million and $166 million at December 31, 2019 and 2018, respectively which is reported in Other deferred
debits in the Consolidated Balance Sheets. PECO excludes cash of $12 million and $24 million at December 31, 2019 and 2018, respectively. BGE excludes cash of $24
million and $7 million at December 31, 2019 and 2018, respectively, and restricted cash of $1 million and $2 million at December 31, 2019 and 2018, respectively.
(b) The Level 3 balance consists of the current and noncurrent liability of $32 million and $269 million, respectively, at December 31, 2019, and $26 million and $223 million,
respectively, at December 31, 2018, related to floating-to-fixed energy swap contracts with unaffiliated suppliers.
PHI
Assets
Cash equivalents(a)
Rabbi trust investments
Cash equivalents
Mutual Funds
Fixed income
Life insurance contracts
Rabbi trust investments subtotal(b)
Total assets
Liabilities
Deferred compensation obligation
Total liabilities
Total net assets
As of December 31, 2019
As of December 31, 2018
Level 1
Level 2
Level 3
Total
Level 1
Level 2
Level 3
Total
$
124 $
— $
— $
124 $
147 $
— $
— $
147
44
14
—
—
58
182
—
—
—
—
12
24
36
36
(19)
(19)
—
—
—
41
41
41
—
—
44
14
12
65
135
259
(19)
(19)
42
13
—
—
55
202
—
—
—
—
15
22
37
37
(21)
(21)
—
—
—
38
38
38
—
—
$
182
$
17
$
41
$
240
$
202
$
16
$
38
$
42
13
15
60
130
277
(21)
(21)
256
329
Table of Contents
Combined Notes to Consolidated Financial Statements
(Dollars in millions, except per share data unless otherwise noted)
Note 17 — Fair Value of Financial Assets and Liabilities
Pepco
DPL
ACE
As of December 31, 2019
Level 1
Level 2
Level 3
Total
Level 1
Level 2
Level 3
Total
Level 1
Level 2
Level 3
Total
Assets
Cash equivalents(a)
$
34 $
— $
— $
34 $
— $
— $
— $
— $
16 $
— $
— $
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
$
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
—
—
16
As of December 31, 2018
Assets
Cash equivalents(a)
Rabbi trust investments
Cash equivalents
Fixed income
Life insurance contracts
Rabbi trust investments subtotal
Total assets
Liabilities
Deferred compensation obligation
Total liabilities
Pepco
DPL
ACE
Level 1
Level 2
Level 3
Total
Level 1
Level 2
Level 3
Total
Level 1
Level 2
Level 3
Total
$
38 $
— $
— $
38 $
16 $
— $
— $
16 $
23 $
— $
— $
23
41
—
—
41
79
—
—
—
5
22
27
27
(3)
(3)
—
—
37
37
37
—
—
41
5
59
105
143
(3)
(3)
—
—
—
—
16
—
—
—
—
—
—
—
(1)
(1)
—
—
—
—
—
—
—
—
—
—
—
16
(1)
(1)
—
—
—
—
23
—
—
—
—
—
—
—
—
—
—
—
—
—
—
—
—
—
—
—
—
23
—
—
$
79
$
Total net assets
__________
(a) PHI excludes cash of $57 million and $39 million at December 31, 2019 and 2018, respectively, and includes long term restricted cash of $14 million and $19 million at
December 31, 2019 and 2018, respectively, which is reported in Other deferred debits in the Consolidated Balance Sheets. Pepco excludes cash of $29 million and $15
million at December 31, 2019 and 2018, respectively. DPL excludes cash of $13 million and $8 million at December 31, 2019 and 2018, respectively. ACE excludes cash
of $12 million and $7 million at December 31, 2019 and 2018, respectively, and includes long-term restricted cash of $14 million and $19 million at December 31, 2019
and 2018, respectively, which is reported in Other deferred debits in the Consolidated Balance Sheets.
— $
15
$
— $
23
37
$
140
24
$
16
$
—
$
(1)
$
23
$
$
330
Table of Contents
Combined Notes to Consolidated Financial Statements
(Dollars in millions, except per share data unless otherwise noted)
Note 17 — Fair Value of Financial 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, 2019 and 2018:
For the year ended December 31, 2019
Total
NDT Fund Investments
Mark-to-Market
Derivatives
Total Generation
Mark-to-Market
Derivatives
Life Insurance Contracts
Eliminated in
Consolidation
Exelon
Generation
ComEd
PHI and Pepco
Balance as of January 1, 2019
$
907 $
543
$
575
$
1,118
$
(249)
$
38 $
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 (losses)
included in income attributed to the
change in unrealized (losses) gains
related to assets and liabilities held as
of December 31, 2019
$
$
(23)
—
(18)
138
176
(23)
(89)
5
(5)
5
34
—
—
44
(21)
(94)
—
—
(31)
(a)
—
—
138
132
(2)
5
5 (c)
(5)
(c)
(26)
34
—
138
176
(23)
(89)
5
(5)
—
—
(b)
(52)
—
—
—
—
—
—
1,068
$
511
$
817
359 $
5
$
351
$
$
1,328
$
(301)
356 $
—
$
$
3
—
—
—
—
—
—
—
—
41
$
3 $
—
—
(34)
34
—
—
—
—
—
—
—
—
331
Table of Contents
Combined Notes to Consolidated Financial Statements
(Dollars in millions, except per share data unless otherwise noted)
Note 17 — Fair Value of Financial Assets and Liabilities
—
—
1
(1)
—
—
—
—
—
—
—
—
For the year ended December 31, 2018
Total
NDT Fund Investments
Mark-to-Market
Derivatives
Total Generation
Mark-to-Market
Derivatives
Life Insurance Contracts
Eliminated in
Consolidation
Balance as of January 1, 2018
$
966 $
648
$
552
$
1,200
$
(256)
$
22 $
Exelon
Generation
ComEd
PHI and Pepco
Total realized / unrealized gains
(losses)
Included in net income
(101)
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, 2018
The amount of total gains (losses)
included in income attributed to the
change in unrealized gains (losses)
related to assets and liabilities held as
of December 31, 2018
$
$
—
6
(5)
226
(4)
(123)
(22)
(36)
907 $
—
(1)
—
—
36
—
(140)
—
—
(105)
(a)
(105)
—
—
(5)
190
(4)
5
(22)
(c)
(36)
(c)
(1)
—
(5)
226
(4)
(135)
(22)
(36)
—
—
7 (b)
—
—
—
—
—
—
543
$
575
$
$
1,118
$
(249)
160 $
—
$
$
4
—
—
—
—
—
12
—
—
38 $
— $
160 $
(5)
$
165
__________
(a)
(b)
Includes a reduction for the reclassification of $377 million and $265 million of realized gains due to the settlement of derivative contracts for the years ended
December 31, 2019 and 2018, respectively.
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. Includes $24 million of decreases in fair value and an increase
for realized losses due to settlements of $17 million recorded in purchased power expense associated with floating-to-fixed energy swap contracts with unaffiliated
suppliers for the year ended December 31, 2018.
(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, 2019 and 2018:
Total gains (losses) included in net
income for the year ended December 31,
2019
Change in the unrealized gains (losses)
relating to assets and liabilities held for
the year ended December 31, 2019
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
$
219 $
(245) $
3 $
5 $
219 $
(245) $
5 $
546
(195)
3
332
5
546
(195)
5
3
3
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Combined Notes to Consolidated Financial Statements
(Dollars in millions, except per share data unless otherwise noted)
Note 17 — 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 (losses) gains included in net
income for the year ended December
31, 2018
Change in the unrealized gains (losses)
relating to assets and liabilities held for
the year ended December 31, 2018
$
(7)
$
(93) $
4 $
3
$
(7)
$
(93) $
3
$
144
21
—
(2)
144
21
(2)
4
—
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 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,
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(Dollars in millions, except per share data unless otherwise noted)
Note 17 — Fair Value of Financial Assets and Liabilities
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
and include unobservable inputs such as cost, operating results, and discounted cash flows. 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. Private credit fund investments
with multiple investors 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. 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. 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 valued by investment managers on a
periodic basis using pricing models that use independent appraisals from sources with professional qualifications. These valuation inputs are not highly
observable. 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, 2019. 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,
2019, there were no significant concentrations (generally defined as greater than 10 percent) of risk in Generation's NDT assets.
See Note 9 — Asset Retirement Obligations for additional information on the NDT fund investments. See Note 14 — Retirement Benefits for the valuation
techniques used for hedge fund investments.
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
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(Dollars in millions, except per share data unless otherwise noted)
Note 17 — Fair Value of Financial Assets and Liabilities
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.
Mark-to-Market Derivatives (Exelon, Generation, ComEd, PHI and DPL). 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. 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 its 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.
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(Dollars in millions, except per share data unless otherwise noted)
Note 17 — Fair Value of Financial Assets and Liabilities
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 $2.22 and $0.54 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 15 — 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 15 — Derivative Financial Instruments for additional information on mark-to-market derivatives.
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Combined Notes to Consolidated Financial Statements
(Dollars in millions, except per share data unless otherwise noted)
Note 17 — 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
Fair Value at
December 31, 2019
Fair Value at
December 31, 2018
Valuation
Technique
Unobservable
Input
2019 Range
2018 Range
Mark-to-market derivatives—Economic
hedges (Exelon and Generation)(a)(b)
$
558
$
Discounted
Cash Flow
443
Option Model
Forward power price
Forward gas price
Volatility percentage
Mark-to-market derivatives—
Proprietary trading (Exelon and
Generation)(a)(b)
$
45
$
Discounted
Cash Flow
56
Forward power price
Mark-to-market derivatives (Exelon and
ComEd)
$
(301) $
(249)
Discounted
Cash Flow
Forward heat rate(c)
Marketability reserve
Renewable factor
$9
$0.83
8%
$25
9X
3%
91%
-
-
-
-
-
-
-
$180
$12
$10.72
$0.78
236%
10%
$180
$14
10X
7%
123%
10X
4%
86%
-
-
-
-
-
-
-
$174
$12.38
277%
$174
11X
8%
120%
______
(a) The valuation techniques, unobservable inputs and ranges are the same for the asset and liability positions.
(b) The fair values do not include cash collateral posted on level three positions of $214 million and $76 million as of December 31, 2019 and December 31, 2018,
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.
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Combined Notes to Consolidated Financial Statements
(Dollars in millions, except per share data unless otherwise noted)
Note 18 — Commitments and Contingencies
18. 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, 2019:
Description
Total commitments
Remaining commitments(a)
_________
(a) Remaining commitments extend through 2026 and include rate credits, energy efficiency programs and delivery system modernization.
101 $
79 $
$
65 $
Exelon
PHI
Pepco
DPL
ACE
$
513 $
320 $
120 $
89 $
8 $
111
6
In addition, Exelon is committed to develop or to assist in the commercial development of approximately 37 MWs of new solar generation in Maryland, District of
Columbia, and Delaware at an estimated cost of approximately $127 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, 2019, 27 MWs of new generation were developed and Exelon and Generation have incurred costs of $120 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.
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Combined Notes to Consolidated Financial Statements
(Dollars in millions, except per share data unless otherwise noted)
Note 18 — Commitments and Contingencies
Commercial Commitments (All Registrants). The Registrants' commercial commitments as of December 31, 2019, representing commitments potentially
triggered by future events, were as follows:
Total
2020
2021
2022
2023
2024
2025 and beyond
Expiration within
$
1,455
$
1,314
$
141
$
Exelon
Letters of credit
Surety bonds(a)
Financing trust guarantees
Guaranteed lease residual values(b)
Total commercial commitments
Generation
Letters of credit
Surety bonds(a)
Total commercial commitments
ComEd
Letters of credit
Surety bonds(a)
Financing trust guarantees
Total commercial commitments
PECO
Surety bonds(a)
Financing trust guarantees
Total commercial commitments
BGE
Letters of credit
Surety bonds(a)
Total commercial commitments
PHI
Surety bonds(a)
Guaranteed lease residual values(b)
Total commercial commitments
Pepco
Surety bonds(a)
Guaranteed lease residual values(b)
Total commercial commitments
DPL
Surety bonds(a)
Guaranteed lease residual values(b)
Total commercial commitments
ACE
Surety bonds(a)
Guaranteed lease residual values(b)
Total commercial commitments
855
378
26
809
—
2
46
—
2
2,714
$
2,125
$
189
$
1,440
$
1,302
$
138
$
670
662
8
2,110
$
1,964
$
146
$
7
50
200
$
$
7
— $
48
—
2
—
257
$
55
$
2
$
$
23
$
$
9
178
187
$
$
$
$
$
2
3
5
21
26
47
14
9
23
$
$
$
$
4
11
15
3
7
10
$
$
9
—
9
$
$
$
$
2
3
5
21
2
$
14
—
14
$
4
1
5
3
1
4
$
$
$
$
— $
—
— $
— $
—
— $
— $
2
2
$
— $
—
— $
— $
1
1
$
— $
1
1
$
$
$
$
$
$
$
$
$
$
$
$
$
$
$
$
$
$
— $
—
—
4
4
$
— $
—
— $
— $
—
—
— $
— $
—
— $
— $
—
— $
— $
4
4
$
— $
1
1
$
— $
2
2
$
— $
1
1
$
— $
—
—
3
3
$
— $
—
— $
— $
—
—
— $
— $
—
— $
— $
—
— $
— $
3
3
$
— $
1
1
$
— $
1
1
$
— $
1
1
$
— $
—
—
6
6
$
— $
—
— $
— $
—
—
— $
— $
—
— $
— $
—
— $
— $
6
6
$
— $
2
2
$
— $
3
3
$
— $
1
1
$
—
—
378
10
388
—
—
—
—
—
200
200
—
178
178
—
—
—
—
10
10
—
5
5
—
3
3
—
2
2
_________
(a) Surety bonds—Guarantees issued related to contract and commercial agreements, excluding bid bonds.
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Combined Notes to Consolidated Financial Statements
(Dollars in millions, except per share data unless otherwise noted)
Note 18 — 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 $69 million
guaranteed by Exelon and PHI, of which $23 million, $29 million and $18 million is guaranteed by Pepco, DPL and ACE, respectively. Historically, payments under the
guarantees have not been made and PHI believes the likelihood of payments being required under the guarantees is remote.
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, 2019, the current liability limit per incident
is $13.9 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 $13.5 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. Exelon’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 $13.9 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 22 — 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 $136 million for 2019, and was $58 million and $60 million for 2018 and 2017, 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 $334 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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(Dollars in millions, except per share data unless otherwise noted)
Note 18 — 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 Exelon 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 2030 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 2017 to provide for the
reimbursement of SNF storage costs through December 31, 2019. Generation expects the terms for each of the settlement agreements to be extended during
2020 for another three years to cover 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 has received cumulative cash reimbursements for costs incurred as follows:
Cumulative cash reimbursements
Total
Net(a)
$
1,288 $
1,113
__________
(a) Total after considering amounts due to co-owners of certain nuclear stations and to the former owner of Oyster Creek.
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Note 18 — Commitments and Contingencies
As of December 31, 2019 and 2018, 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:
DOE receivable - current(a)
DOE receivable - noncurrent(b)
December 31, 2019
December 31, 2018
$
249 $
30
124
15
Amounts owed to co-owners(a)(c)
__________
(a) Recorded in Accounts receivable, other.
(b) Recorded in Deferred debits and other assets, other.
(c) Non-CENG amounts owed to co-owners are recorded in Accounts receivable, other. CENG amounts owed to co-owners are recorded in Accounts payable. Represents
(37)
(17)
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, 2019 and 2018:
Former ComEd units(a)
Fitzpatrick(b)
Total SNF Obligation
December 31, 2019
December 31, 2018
$
$
1,075 $
124
1,199 $
1,052
119
1,171
__________
(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, 2019 was 1.551% for the deferred amount transferred from ComEd and 1.879% 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
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Note 18 — Commitments and Contingencies
or others, or whether such costs will be recoverable from third parties, including customers. Additional costs could have a material, unfavorable impact on the
Registrants' financial statements.
MGP Sites (Exelon and the Utility Registrants). ComEd, PECO, BGE and DPL have identified sites where former MGP or gas purification activities have or
may have resulted in actual site contamination. For almost all of these sites, there are additional PRPs that may share responsibility for the ultimate remediation
of each location.
•
•
•
•
ComEd has 21 sites that are currently under some degree of active study and/or remediation. ComEd expects the majority of the remediation at these
sites to continue through at least 2025.
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 2022.
BGE has 4 sites that currently require some level of remediation and/or ongoing activity. BGE expects the majority of the remediation at these sites to
continue through at least 2021.
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, 2019 and 2018, 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, 2019
December 31, 2018
Total environmental
investigation and
remediation reserve
Portion of total related to
MGP investigation and
remediation
Total environmental
investigation and
remediation reserve
Portion of total related to
MGP investigation and
remediation
Exelon
Generation
$
ComEd
PECO
BGE
PHI
Pepco
DPL
ACE
478 $
105
304
19
2
48
46
1
1
320 $
—
303
17
—
—
—
—
—
496 $
108
329
27
5
27
25
1
1
356
—
327
25
4
—
—
—
—
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.
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Note 18 — Commitments and Contingencies
In September 2018, the EPA issued its Record of Decision (ROD) Amendment for the selection of the final remedy. The ROD modified the EPA’s previously
proposed plan for partial excavation of the radiological materials by reducing the depths of the excavation. The ROD 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 in the 2020 - 2021 time frame. In March 2019 the PRPs received Special Notice Letters from the EPA to perform the Remedial Action
work. On October 8, 2019, Generation 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 remediation
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 Generation’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
possess sufficient information to assess this claim and therefore are unable to estimate a range of loss, if any. As such, no liability has been recorded for the
potential contribution claim. It is reasonably possible, however, that resolution of this matter could have a material, unfavorable impact on Exelon’s and
Generation's financial statements.
In January 2018, the PRPs were advised by the EPA that it will begin an additional investigation and evaluation of groundwater conditions at the West Lake
Landfill. In September 2018, the PRPs agreed to an Administrative 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
$20 million. Generation determined a loss associated with the RI/FS is probable and has recorded a liability included in the table above that reflects
management’s best estimate of Cotter’s allocable share of the cost among the PRPs. At this time Generation cannot predict the likelihood or the extent to which,
if any, remediation activities may be required and therefore cannot estimate a reasonably possible range of loss for response costs beyond those associated
with the RI/FS component. It is reasonably possible, however, that resolution of this matter could have a material, unfavorable impact on Exelon’s and
Generation’s future financial statements.
In August 2011, Cotter was notified by the DOJ that Cotter is considered a PRP with respect to the government’s clean-up costs for contamination attributable to
low level radioactive residues at a former storage and reprocessing facility named Latty Avenue near St. Louis, Missouri. The Latty Avenue site is included in
ComEd’s 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. The DOJ has not yet formally advised the PRPs of the amount that it is seeking, but it is believed to be approximately $90 million from all PRPs.
Pursuant to a series of annual agreements since 2011, the DOJ and the PRPs have tolled the statute of limitations until February 2020 so that settlement
discussions could proceed. Generation has determined that a loss associated with this matter is probable under its indemnification agreement with Cotter and
has recorded an estimated liability, which is included in the table above.
Benning Road Site (Exelon, Generation, PHI and Pepco). In September 2010, PHI received a letter from EPA identifying the Benning Road site as one of six
land-based sites potentially contributing to contamination of the lower Anacostia River. A portion of the site was formerly the location of a Pepco Energy Services
electric generating facility, which was deactivated in June 2012. The remaining portion of the site consists of a Pepco transmission and distribution service
center that remains in operation. In December 2011, the U.S. District Court for the District of Columbia approved a Consent Decree entered into by Pepco and
Pepco Energy Services with the DOEE, which
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Note 18 — Commitments and Contingencies
requires Pepco and Pepco Energy Services to conduct a RI/FS for the Benning Road site and an approximately 10 to 15-acre portion of the adjacent Anacostia
River.
Since 2013, Pepco and Pepco Energy Services (now Generation, pursuant to Exelon's 2016 acquisition of PHI) have been performing RI work and have
submitted multiple draft RI reports to the DOEE. In September 2019, Pepco and Generation issued a draft “final” RI report which DOEE approved and on
October 4, 2019 released this document for review and comment by the public. The 45 day comment period ended on November 18, 2019 and a public meeting
was held by Pepco on November 2, 2019. Pepco and Generation will proceed to develop 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.
DOEE will then prepare a Proposed Plan and issue a Record of Decision identifying any further response actions determined to be necessary, after considering
public comment on the Proposed Plan. 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. DOEE asked Pepco, along with parties responsible for
other sites along the river, to participate in a "Consultative Working Group" to provide input into the process for future remedial actions and to ensure proper
coordination with the other river cleanup efforts currently underway, including cleanup of the river segment adjacent to the Benning Road site resulting from the
Benning Road site RI/FS. In addition, the District of Columbia Council directed DOEE to form an official advisory committee made up of members of federal,
state and local environmental regulators, community and environmental groups and various academic and technical experts to provide guidance and support to
DOEE as the project progressed. This group, called the Anacostia Leadership Council, has met regularly since it was formed. Pepco has participated in the
Consultative Working Group. In April 2018, DOEE released a draft RI report for public review and comment. Pepco submitted written comments to the draft RI
and participated in a public hearing.
Pepco has determined that it is probable that costs for remediation will be incurred and recorded a liability in the third quarter 2019 for management’s best
estimate of its share of those costs based on DOEE’s stated position following a series of meetings attended by representatives from the Anacostia Leadership
Council and the Consultative Working Group. On December 27, 2019, DOEE released a Focused Feasibility Study (FFS) and a Proposed Plan (PP) for review
and comment by the public which will be the basis for the Interim ROD, which is expected to be completed in September 2020. The FFS and PP are consistent
with the DOEE’s stated position to follow an adaptive management approach which will allow 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. The comment period ends on March 2, 2020 and a public meeting will be held
on January 23, 2021. Pepco concluded that incremental exposure remains reasonably possible, however 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, there is a complementary statutory program that requires an assessment to
determine if any natural resources have been damaged as a result of the contamination that is being remediated, and, if so, that a plan be developed by the
federal, state and local Natural Resource Damage Trustees, who are defined by CERCLA as the responsible parties for the restoration or compensation for any
loss of those resources from the environmental contaminants at the site. If natural resources cannot be restored, then compensation for the injury can be sought
from the responsible parties. The assessment of Natural Resource Damages (NRD) typically takes place following cleanup because cleanups sometimes also
effectively restore habitat. During the second quarter of 2018, Pepco became aware that the Trustees are in the beginning stages of this 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.
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(Dollars in millions, except per share data unless otherwise noted)
Note 18 — Commitments and Contingencies
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, 2019 and 2018, Exelon and Generation had recorded estimated liabilities of approximately $83 million and $79 million, respectively, in total for
asbestos-related bodily injury claims. As of December 31, 2019, approximately $26 million of this amount related to 263 open claims presented to Generation,
while the remaining $57 million is for estimated future asbestos-related bodily injury claims anticipated to arise through 2055, based on actuarial assumptions
and analyses, which are updated on an annual basis. On a quarterly basis, Generation monitors actual experience against the number of forecasted claims to be
received and expected claim payments and evaluates whether adjustments to the estimated liabilities are necessary.
It is reasonably possible that additional exposure to estimated future asbestos-related bodily injury claims in excess of the amount accrued could have a
material, unfavorable impact on Exelon’s and Generation’s financial statements.
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
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Note 18 — Commitments and Contingencies
dividend restriction which requires ACE to obtain the prior approval of the NJBPU before dividends can be paid it 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 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 deadline for appeal is March 9, 2020. Generation continues to believe that the City’s claim lacks merit. Accordingly, Generation has not
recorded a liability for payment resulting from such a revocation, nor can Generation estimate a reasonably possible range of loss, if any, associated with any
such revocation. Further, it is reasonably possible that property taxes assessed in future periods, including those following the expiration of the current TIF
Agreement in 2020, could be material to Generation’s financial statements.
Subpoenas (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 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 U.S. Attorney's Office for the Northern District of Illinois requiring production of records of any communications
with certain individuals and entities. On October 22, 2019, the SEC notified Exelon and ComEd that it has also opened an investigation into their lobbying
activities. Exelon and ComEd have cooperated fully and intend to continue to cooperate fully and expeditiously with the U.S. Attorney’s Office and the SEC.
Exelon and ComEd cannot predict the outcome of the U.S. Attorney's Office or the SEC investigations. No loss contingency has been reflected in Exelon's and
ComEd's consolidated financial statements as this contingency is neither probable nor reasonably estimable at this time. Management is currently unable to
estimate a range of reasonably possible loss as these matters are subject to change.
Subsequent to Exelon announcing the receipt of the subpoenas, a putative class action lawsuit has been filed against Exelon and certain officers of Exelon and
ComEd alleging misrepresentations or omissions by Exelon purporting to relate to matters that are the subject of the subpoenas and the SEC
investigation. Exelon believes that these claims lack merit and intends to defend against them, and though the costs or any loss associated with the lawsuit
cannot be reasonably estimated at this time, Exelon does not believe that the lawsuit will have a material adverse impact on Exelon’s or ComEd’s consolidated
financial statements.
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.
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(Dollars in millions, except per share data unless otherwise noted)
Note 19 — Shareholders' Equity
19. Shareholders' Equity (Exelon and Utility Registrants)
ComEd Common Stock Warrants
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
Equity Securities Offering
December 31,
2019
2018
60,228
20,076
60,285
20,095
In June 2014, Exelon issued $1.15 billion of junior subordinated notes in the form of 23 million equity units. In June 2017, Exelon settled the forward equity
purchase contract on these equity units through issuance of 33 million shares of common stock from treasury stock, which triggered full dilution in the EPS
calculation. Previously, the equity units were included in the calculation of diluted EPS using the treasury stock method.
Share Repurchases
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 the Registrants' shares of preferred securities authorized, none of which are outstanding as of December 31, 2019 and 2018:
Exelon
ComEd
PECO
BGE
Pepco
ACE(a)
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, 2019 and 2018, respectively.
The following table presents ComEd's, BGE's and ACE's preference securities authorized, none of which are outstanding as of December 31, 2019 and 2018:
ComEd - Cumulative preference securities
BGE(a)
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, 2019 and 2018,
respectively.
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Combined Notes to Consolidated Financial Statements
(Dollars in millions, except per share data unless otherwise noted)
Note 19 — Shareholders' Equity
20. 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, 2019, there were approximately 12 million shares authorized for issuance under the LTIP. For the years ended December 31, 2019, 2018 and
2017, 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.
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, 2019, 2018 and 2017 was not material.
Exelon
Components of Stock-Based Compensation Expense
Total stock-based compensation expense included in operating and maintenance
expense
Income tax benefit
Total after-tax stock-based compensation expense
Generation
Components of Stock-Based Compensation Expense
Total stock-based compensation expense included in operating and maintenance
expense
Income tax benefit
Total after-tax stock-based compensation expense
$
$
$
$
Year Ended December 31,
2019
2018
2017
77 $
(20)
57 $
37 $
(10)
27 $
208 $
(54)
154 $
77 $
(20)
57 $
191
(74)
117
88
(34)
54
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
Year Ended December 31,
2019
2018
2017
$
41 $
24
16 $
28
29
35
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.
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Combined Notes to Consolidated Financial Statements
(Dollars in millions, except per share data unless otherwise noted)
Note 20 — Stock-Based Compensation Plans
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:
Nonvested at December 31, 2018(a)
Granted
Change in performance
Vested
Forfeited
Undistributed vested awards(b)
Nonvested at December 31, 2019(a)
Shares
Weighted Average
Grant Date Fair
Value (per share)
3,403,228 $
1,089,903
(799,618)
(1,610,146)
(25,249)
(348,363)
1,709,755 $
33.13
47.37
40.85
28.90
45.03
48.82
39.21
__________
(a) Excludes 2,017,870 and 3,586,259 of performance share awards issued to retirement-eligible employees as of December 31, 2019 and 2018, respectively, as they are
fully vested.
(b) Represents performance share awards that vested but were not distributed to retirement-eligible employees during 2019.
The following table summarizes the weighted average grant date fair value and the total fair value of performance share awards granted and settled.
Weighted average grant date fair value (per share)
$
Total fair value of performance shares settled
Year Ended December 31,
2019 (a)
2018
2017
47.37 $
158
38.15 $
61
35.00
72
Total fair value of performance shares settled in cash
__________
(a) As of December 31, 2019, $17 million of total unrecognized compensation costs related to nonvested performance shares are expected to be recognized over the
56
131
49
remaining weighted-average period of 1.6 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 immediately upon the date of grant or through the date at
which the employee reaches retirement eligibility. Exelon processes forfeitures as they occur for employees who do not complete the requisite service period.
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Combined Notes to Consolidated Financial Statements
(Dollars in millions, except per share data unless otherwise noted)
The following table summarizes Exelon’s nonvested restricted stock unit activity:
Nonvested at December 31, 2018(a)
Granted
Vested
Forfeited
Undistributed vested awards (b)
Nonvested at December 31, 2019(a)
Note 20 — Stock-Based Compensation Plans
Shares
Weighted Average
Grant Date Fair
Value (per share)
2,293,341 $
902,857
(1,232,704)
(33,603)
(431,178)
1,498,713 $
35.06
45.65
32.83
39.01
44.75
40.35
__________
(a) Excludes 863,196 and 1,131,487 of restricted stock units issued to retirement-eligible employees as of December 31, 2019 and 2018, respectively, as they are fully
vested.
(b) Represents restricted stock units that vested but were not distributed to retirement-eligible employees during 2019.
The following table summarizes the weighted average grant date fair value and the total fair value of restricted stock units granted and vested.
Weighted average grant date fair value (per share)
Total fair value of restricted stock units vested
Year Ended December 31,
2019 (a)
2018
2017
$
45.65 $
92
38.60 $
106
34.98
88
__________
(a) As of December 31, 2019, $28 million of total unrecognized compensation costs related to nonvested restricted stock units are expected to be recognized over the
remaining weighted-average period of 2.8 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, 2019 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, 2018
Options exercised
Options expired
Balance of shares outstanding at December 31, 2019
Exercisable at December 31, 2019(a)
__________
(a)
Includes stock options issued to retirement eligible employees.
Shares
4,027,652 $
(1,388,165)
(750,442)
1,889,045 $
1,889,045 $
351
Weighted
Average
Exercise
Price
(per share)
Weighted
Average
Remaining
Contractual
Life
(years)
Aggregate
Intrinsic
Value
43.95
42.25
55.96
40.43
40.43
2.90 $
1.56 $
1.56 $
14
10
10
Table of Contents
Combined Notes to Consolidated Financial Statements
(Dollars in millions, except per share data unless otherwise noted)
The following table summarizes additional information regarding stock options exercised:
Intrinsic value(a)
Cash received for exercise price
__________
(a) The difference between the market value on the date of exercise and the option exercise price.
$
21. Changes in Accumulated Other Comprehensive Income (Exelon)
The following tables present changes in Exelon's AOCI, net of tax, by component:
Note 20 — Stock-Based Compensation Plans
Year Ended December 31,
2019
2018
2017
9 $
59
12 $
56
15
107
Balance at December 31, 2016
$
(17)
$
$
(2,610)
$
(30)
$
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)
OCI before reclassifications
Amounts reclassified from AOCI
Net current-period OCI
Impact of adoption of Reclassification of
Certain Tax Effects from AOCI(c)
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(d)
Balance at December 31, 2018
OCI before reclassifications
Amounts reclassified from AOCI
Net current-period OCI
Balance at December 31, 2019
$
$
$
(1)
4
3
—
(14)
$
11
1
12
—
(2)
$
—
—
—
4
6
—
6
—
10
$
—
—
—
(10)
11
140
151
(539)
7
—
7
—
(2,998)
$
(23)
$
(143)
181
38
(10)
—
(10)
Total
$
(2,660)
29
144
173
(7)
6
—
6
—
(539)
(1)
$
(3,026)
1
—
1
(141)
182
41
—
—
—
(10)
— $
(2,960)
$
(33)
$
—
—
—
(289)
84
(205)
6
—
6
—
(2)
2
—
$
(2,995)
(285)
86
(199)
(2)
$
— $
(3,165)
$
(27)
$
—
$
(3,194)
__________
(a) This AOCI component is included in the computation of net periodic pension and OPEB cost. See Note 14 — 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 early adopted the new standard Reclassification of Certain Tax Effects from AOCI. The standard was adopted retrospectively as of December 31, 2017, which
resulted in an increase to Exelon’s Retained earnings and Accumulated other comprehensive loss of $539 million, primarily related to deferred income taxes associated
with Exelon’s pension and OPEB obligations.
(d) Exelon prospectively 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.
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Combined Notes to Consolidated Financial Statements
(Dollars in millions, except per share data unless otherwise noted)
Note 21 — Changes in Accumulated Other Comprehensive Income
The following table presents income tax benefit (expense) allocated to each component of Exelon's other comprehensive income (loss):
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 $
(52)
100
24 $
(86)
50
36
(128)
13
For the Year Ended December 31,
2019
2018
2017
22. Variable Interest Entities (Exelon, Generation, PHI and ACE)
At December 31, 2019 and 2018, Exelon, Generation, PHI and ACE collectively consolidated several VIEs or VIE groups for which the applicable Registrant was
the primary beneficiary (see Consolidated VIEs below) and had significant interests in several other VIEs for which the applicable Registrant does not have the
power to direct the entities’ activities and, accordingly, was not the primary beneficiary (see Unconsolidated VIEs below). Consolidated and unconsolidated VIEs
are aggregated to the extent that the entities have similar risk profiles.
Consolidated VIEs
The table below shows the carrying amounts and classification of the consolidated VIEs’ assets and liabilities included in the consolidated financial statements of
Exelon, Generation, PHI and ACE as of December 31, 2019 and 2018. 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, 2019
December 31, 2018
Exelon(a)
Generation
PHI(a)
ACE
Exelon
Generation
PHI
ACE
Cash and cash equivalents
$
163 $
163 $
— $
— $
414 $
414 $
— $
Restricted cash and cash equivalents
88
85
3
3
66
62
4
Accounts receivable, net
Customer
Other
Unamortized energy contract asset (b)
Inventories, net
Materials and supplies
Other current assets
Total current assets
Property, plant and equipment, net (c)
Nuclear decommissioning trust funds
Unamortized energy contract asset (b)
Other noncurrent assets
Total noncurrent assets
Total assets
Long-term debt due within one year
Accounts payable
Accrued expenses
Unamortized energy contract liabilities
Other current liabilities
Total current liabilities
Long-term debt
Asset retirement obligations (d)
Unamortized energy contract liabilities
Other noncurrent liabilities
151
39
23
227
32
723
6,022
2,741
250
89
9,102
151
39
23
227
31
719
6,022
2,741
250
73
9,086
9,825
$
9,805
$
—
—
—
—
1
4
—
—
—
16
16
20
—
—
—
—
—
3
—
—
—
14
14
146
23
25
212
52
938
6,188
2,351
274
258
9,071
146
23
25
212
49
931
6,188
2,351
274
232
9,045
—
—
—
—
3
7
—
—
—
26
26
$
17 $
10,009 $
9,976 $
33 $
544 $
523 $
21 $
20 $
87 $
66 $
21 $
106
70
8
3
731
527
2,128
1
89
106
70
8
3
710
504
2,128
1
89
—
—
—
—
21
23
—
—
—
—
—
—
—
20
21
—
—
—
96
73
15
3
274
1,072
2,165
1
42
96
72
15
3
252
1,025
2,165
1
42
—
1
—
—
22
47
—
—
—
$
$
—
4
—
—
—
—
—
4
—
—
—
19
19
23
18
—
1
—
—
19
40
—
—
—
Total noncurrent liabilities
2,745
2,722
Total liabilities
$
3,476
$
3,432
$
23
44
21
3,280
3,233
47
$
41 $
3,554 $
3,485 $
69 $
40
59
Includes certain purchase accounting adjustments not pushed down to the ACE standalone entity.
__________
(a)
(b) These are unrestricted assets to Exelon and Generation.
(c) Exelon's and Generation's balances include unrestricted assets of $20 million and $43 million as of December 31, 2019 and 2018, respectively.
(d) Exelon's and Generation's balances include liabilities with recourse of $3 million and $5 million as of December 31, 2019 and 2018, respectively.
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Combined Notes to Consolidated Financial Statements
(Dollars in millions, except per share data unless otherwise noted)
As of December 31, 2019 and 2018, Exelon's and Generation's consolidated VIEs consist of:
Consolidated VIE or VIE groups:
Reason entity is a VIE:
CENG - A joint venture between Generation and EDF.
Generation has a 50.01% equity ownership in CENG. See
additional discussion below.
EGRP - A collection of wind and solar project entities.
Generation has a 51% equity ownership in EGRP. See
additional discussion below.
Blue Stem Wind - A Tax Equity structure which is
consolidated by EGRP. Generation is a minority interest
holder.
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. See note 11- Asset Impairments for additional
information.
Disproportionate relationship between equity interest and
operational control as a result of the Nuclear Operating
Services Agreement (NOSA) described further below.
Similar structure to a limited partnership and the limited
partners do not have kick out rights with respect to the
general partner.
Similar structure to a limited partnership and the limited
partners do not have kick out rights with respect to the
general partner.
The PPA contract absorbs variability through a performance
guarantee.
Similar structure to a limited partnership and the limited
partners do not have kick out rights with respect to the
general partner.
Note 22 — Variable Interest Entities
Reason Generation is primary beneficiary:
Generation conducts the operational activities.
Generation conducts the operational activities.
Generation conducts the operational activities.
Generation conducts all activities.
Generation conducts the operational activities.
CENG - On April 1, 2014, Generation, CENG, and subsidiaries of CENG executed the NOSA pursuant to which Generation conducts all activities associated
with the operations of the CENG fleet and provides corporate and administrative services to CENG and the CENG fleet for the remaining life of the CENG
nuclear plants as if they were a part of the Generation nuclear fleet, subject to the CENG member rights of EDF. See Note 2 — Mergers, Acquisitions and
Dispositions for additional information.
Exelon and Generation, where indicated, provide the following support to CENG:
•
•
•
•
Generation provided a $400 million loan to CENG. The remaining balance was fully paid by CENG in January 2019.
Generation executed an Indemnity Agreement pursuant to which Generation agreed to indemnify EDF against third-party claims that may arise from
any future nuclear incident (as defined in the Price-Anderson Act) in connection with the CENG nuclear plants or their operations. Exelon guarantees
Generation’s obligations under this Indemnity Agreement. (See Note 18 — Commitments and Contingencies 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
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Table of Contents
Combined Notes to Consolidated Financial Statements
(Dollars in millions, except per share data unless otherwise noted)
Note 22 — Variable Interest Entities
facilities, or the customers absorb price variability from the entities through the fixed price power and/or REC purchase agreements. Generation is the primary
beneficiary of these solar and wind entities that qualify as VIEs because Generation controls the design, construction, and operation of the facilities. Generation
provides operating and capital funding to the solar and wind entities for ongoing construction, operations and maintenance and there is limited recourse related
to Generation related to certain solar and wind entities.
In 2017, Generation’s interests in EGRP were contributed to and are pledged for the ExGen Renewables IV non-recourse debt project financing structure. Refer
to Note 16 — Debt and Credit Agreements for additional information on ExGen Renewables IV.
As of December 31, 2019 and 2018, 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 Transition Funding - A special purpose entity formed by ACE for the purpose of
securitizing authorized portions of ACE’s recoverable stranded costs through the
issuance and sale of transition bonds. Proceeds from the sale of each series of
transition bonds by ATF were transferred to ACE in exchange for the transfer by ACE
to ATF of the right to collect a non-bypassable Transition Bond Charge from ACE
customers pursuant to bondable stranded costs rate orders issued by the NJBPU in
an amount sufficient to fund the principal and interest payments on transition bonds
and related taxes, expenses and fees.
ACE’s equity investment is a variable interest
as, by design, it absorbs any initial variability
of ACETF. The bondholders also have a
variable interest for the investment made to
purchase the transition bonds.
ACE controls the servicing activities.
Unconsolidated VIEs
Exelon’s and Generation’s variable interests in unconsolidated VIEs generally include equity investments and energy purchase and sale contracts. For the equity
investments, the carrying amount of the investments is reflected in Exelon’s and Generation’s Consolidated Balance Sheets in Investments. For the energy
purchase and sale contracts (commercial agreements), the carrying amount of assets and liabilities in Exelon’s and Generation’s Consolidated Balance Sheets
that relate to their involvement with the VIEs are predominately related to working capital accounts and generally represent the amounts owed by, or owed to,
Exelon and Generation for the deliveries associated with the current billing cycles under the commercial agreements.
As of December 31, 2019 and 2018, Exelon and Generation had significant unconsolidated variable interests in several VIEs for which Exelon or Generation, as
applicable, was not the primary beneficiary. These interests include certain equity method investments and certain commercial agreements.
The following table presents summary information about Exelon 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)
Registrants’ maximum exposure to loss:
Carrying amount of equity method
investments
Commercial
Agreement
VIEs
December 31, 2019
Equity
Investment
VIEs
Total
Commercial
Agreement
VIEs
December 31, 2018
Equity
Investment
VIEs
Total
$
636 $
443 $
1,079 $
597 $
472 $
1,069
33
—
604
227
191
25
260
191
629
37
—
560
222
223
27
259
223
587
—
—
—
—
223
223
__________
(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.
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Combined Notes to Consolidated Financial Statements
(Dollars in millions, except per share data unless otherwise noted)
Note 22 — Variable Interest Entities
For each of the unconsolidated VIEs, Exelon and Generation have assessed the risk of a loss equal to their maximum exposure to be remote and, accordingly,
Exelon and Generation have not recognized a liability associated with any portion of the maximum exposure to loss.
As of December 31, 2019 and 2018, 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 a
distributed energy company (See Consolidated VIEs disclosure above).
Generation fully impaired this investment in the third quarter of 2019. See
note 11- 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.
23. 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.
Taxes other than income taxes
Exelon
Generation
ComEd
PECO
BGE
PHI
Pepco
DPL
ACE
For the year ended December 31, 2019
Utility(a)
Property
Payroll
For the year ended December 31, 2018
Utility(a)
Property
Payroll
For the year ended December 31, 2017
Utility(a)
Property
$
$
$
881 $
112 $
242 $
132 $
90 $
304 $
286 $
18 $
—
595
232
274
29
17
153
122
85
34
115
27
15
17
24
7
4
919 $
557
247
114 $
273
130
243 $
30
27
131 $
15
16
94 $
143
17
337 $
94
24
316 $
58
5
21 $
32
3
2
2
—
3
2
—
3
Payroll
__________
(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
2
898 $
545
230
126 $
269
121
240 $
28
26
125 $
14
15
89 $
132
15
318 $
101
26
300 $
62
6
18 $
32
4
gross receipts taxes related to their operating revenues.
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Combined Notes to Consolidated Financial Statements
(Dollars in millions, except per share data unless otherwise noted)
Note 23 — Supplemental Financial Information
Exelon
Generation
ComEd
PECO
BGE
PHI
Pepco
DPL
ACE
Other, Net
For the year ended December 31, 2019
Decommissioning-related activities:
Net realized income on NDT funds(a)
Regulatory agreement units
$
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(a)
Regulatory agreement units
$
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
For the year ended December 31, 2017
Decommissioning-related activities:
Net realized income on NDT funds(a)
Regulatory agreement units
$
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
297 $
363
297 $
363
— $
—
— $
—
— $
—
— $
—
— $
—
— $
—
795
411
(876)
990
85
13
795
411
(876)
990
—
—
—
—
—
—
17
—
—
—
—
—
13
—
—
—
—
—
21
—
—
—
—
—
34
—
—
—
—
—
25
—
—
—
—
—
4
—
506 $
302
506 $
302
— $
—
— $
—
— $
—
— $
—
— $
—
— $
—
(715)
(483)
171
(219)
69
(47)
488 $
209
455
521
(724)
949
73
(109)
(715)
(483)
171
(219)
—
—
—
—
—
—
19
—
—
—
—
—
7
—
—
—
—
—
18
—
—
—
—
—
25
—
—
—
—
—
22
—
—
—
—
—
2
—
488 $
209
— $
—
— $
—
— $
—
— $
—
— $
—
— $
—
455
521
—
—
—
—
(724)
949
—
—
—
—
12
—
—
—
9
—
—
—
—
—
16
—
—
—
—
—
36
—
—
—
—
—
23
—
—
—
—
—
7
—
—
—
—
—
—
—
5
—
—
—
—
—
—
—
1
—
—
—
—
—
—
—
6
—
Non-service net periodic benefit cost
__________
(a) Realized income includes interest, dividends and realized gains and losses on sales of NDT fund investments.
(b)
Includes the elimination of decommissioning-related activities for the Regulatory Agreement Units, including the elimination of income taxes related to all NDT fund activity
for those units. See Note 9 — Asset Retirement Obligations for additional information regarding the accounting for nuclear decommissioning.
357
Table of Contents
Combined Notes to Consolidated Financial Statements
(Dollars in millions, except per share data unless otherwise noted)
Note 23 — Supplemental Financial Information
Supplemental Cash Flow Information
The following tables provide additional information about material items recorded in the Registrants' Consolidated Statements of Cash Flows.
For the year ended December 31, 2019
Property, plant and equipment
Amortization of regulatory assets
Amortization of intangible assets, net
Amortization of energy contract assets and
liabilities(a)
Nuclear fuel(b)
ARO accretion(c)
Total depreciation, amortization and accretion
For the year ended December 31, 2018
Property, plant and equipment
Amortization of regulatory assets
Amortization of intangible assets, net
Amortization of energy contract assets and
liabilities(a)
Nuclear fuel(b)
ARO accretion(c)
Total depreciation, amortization and accretion
For the year ended December 31, 2017
Property, plant and equipment
Amortization of regulatory assets
Amortization of intangible assets, net
Amortization of energy contract assets and
liabilities(a)
Nuclear fuel(b)
ARO accretion(c)
$
$
$
$
$
Exelon
Generation
ComEd
PECO
BGE
PHI
Pepco
DPL
ACE
Depreciation, amortization and accretion
3,665 $
528
59
21
1,016
491
1,485 $
—
50
886 $
147
—
21
1,016
491
—
—
—
303 $
359 $
547 $
239 $
146 $
123
30
—
—
—
—
143
—
—
—
—
207
—
—
—
—
135
—
—
—
—
38
—
—
—
—
34
—
—
—
—
5,780 $
3,063 $
1,033
$
333 $
502
$
754 $
374
$
184
$
157
3,740 $
555
58
14
1,115
489
1,748 $
—
49
820 $
120
—
14
1,115
489
—
—
—
274 $
335 $
480 $
218 $
131 $
27
—
—
—
—
148
—
—
—
—
260
—
—
—
—
167
—
—
—
—
51
—
—
—
—
94
42
—
—
—
—
5,971 $
3,415 $
940 $
301 $
483 $
740 $
385 $
182 $
136
3,293 $
478
57
35
1,096
468
1,409 $
—
48
777 $
73
—
35
1,096
468
—
—
—
261 $
312 $
457 $
203 $
124 $
25
—
—
—
—
161
—
—
—
—
218
—
—
—
—
118
—
—
—
—
43
—
—
—
—
89
57
—
—
—
—
$
5,427 $
3,056
$
850
$
286
$
473 $
675 $
321
$
167
$
146
Total depreciation, amortization and accretion
__________
(a)
(b)
(c)
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.
Included in Operating and maintenance expense 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)
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)
For the year ended December 31, 2017
Interest (net of amount capitalized)
Income taxes (net of refunds)
$
$
$
Note 23 — Supplemental Financial Information
Exelon
Generation
ComEd
PECO
BGE
PHI
Pepco
DPL
ACE
Cash paid (refunded) during the year:
1,470 $
265
373 $
(44)
343 $
(42)
129 $
82
106 $
17
255 $
29
130 $
7
59 $
19
55
(5)
1,421 $
95
369 $
746
332 $
(153)
125 $
(2)
94 $
14
250 $
(32)
123 $
41
56 $
(6)
61
(12)
2,430 $
540
391 $
337
307 $
83
103 $
47
96 $
(2)
236 $
(144)
114 $
(104)
49 $
(49)
59
(2)
359
Table of Contents
Combined Notes to Consolidated Financial Statements
(Dollars in millions, except per share data unless otherwise noted)
Note 23 — Supplemental Financial Information
Exelon
Generation
ComEd
PECO
BGE
PHI
Pepco
DPL
ACE
Other non-cash operating activities:
For the year ended December 31, 2019
Pension and non-pension postretirement benefit
costs
Provision for uncollectible accounts
$
Other decommissioning-related activity(a)
Energy-related options(b)
Amortization of rate stabilization deferral
Discrete impacts from EIMA and FEJA(d)
Long-term incentive plan
Amortization of operating ROU asset
Change in environmental liabilities
For the year ended December 31, 2018
Pension and non-pension postretirement benefit
costs
Provision for uncollectible accounts
$
Other decommissioning-related activity(a)
Energy-related options(b)
Amortization of rate stabilization deferral
Asset retirement costs
Discrete impacts from EIMA and FEJA(d)
Long-term incentive plan
For the year ended December 31, 2017
Pension and non-pension postretirement benefit
costs
$
Provision for uncollectible accounts
Other decommissioning-related activity(a)
Energy-related options(b)
Amortization of rate stabilization deferral
Discrete impacts from EIMA and FEJA(d)
Vacation accrual adjustment(e)
Long-term incentive plan
Change in environmental liabilities
438 $
120
(506)
22
(4)
128
10
244
23
583 $
159
(2)
10
21
20
28
140
643 $
125
(313)
7
(3)
(52)
(68)
109
44
135 $
31
(506)
22
—
—
—
172
—
204 $
48
(2)
10
—
—
—
—
227 $
38
(313)
7
—
—
(35)
—
44
96 $
33
—
—
—
128
—
3
—
177 $
40
—
—
—
—
28
—
176 $
34
—
—
—
(52)
(12)
—
—
12 $
31
—
—
—
—
—
—
—
18 $
33
—
—
—
—
—
—
29 $
26
—
—
—
—
—
—
—
61 $
8
—
—
—
—
—
30
—
59 $
10
—
—
—
—
—
—
62 $
8
—
—
7
—
—
—
—
95 $
17
—
—
(4)
—
—
33
23
67 $
28
—
—
21
20
—
—
94 $
19
—
—
(10)
—
(8)
—
—
25 $
7
—
—
(4)
—
—
8
23
15 $
11
—
—
21
22
—
—
25 $
8
—
—
(10)
—
(8)
—
—
15 $
4
—
—
—
—
—
8
—
6 $
6
—
—
—
(1)
—
—
13 $
3
—
—
—
—
—
—
—
16
5
—
—
—
—
—
4
—
12
11
—
—
—
(1)
—
—
13
8
—
—
—
—
—
—
—
__________
(a)
Includes the elimination of decommissioning-related activities for the Regulatory Agreement Units, including the elimination of operating revenues, ARO accretion, ARC
amortization, investment income and income taxes related to all NDT fund activity for these units. See Note 9 — Asset Retirement Obligations 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)
(c) See Note 2 - Mergers, Acquisitions and Dispositions for additional information.
360
Table of Contents
Combined Notes to Consolidated Financial Statements
(Dollars in millions, except per share data unless otherwise noted)
(d) Reflects the change in ComEd's distribution and energy efficiency formula rates . See Note 3 — Regulatory Matters for additional information.
(e) On December 1, 2017, Exelon adopted a single, standard vacation accrual policy for all non-represented, non-craft (represented and craft policies remained unchanged)
employees effective January 1, 2018. To reflect the new policy, Exelon recorded a one-time, $68 million pre-tax credit to expense to reverse 2018 vacation cost originally
accrued throughout 2017 that was accrued ratably during 2018.
The following tables provide a reconciliation of cash, cash equivalents and restricted cash reported within the Registrants' Consolidated Balance Sheets that
sum to the total of the same amounts in their Consolidated Statements of Cash Flows.
Note 23 — Supplemental Financial Information
Exelon
Generation
ComEd
PECO
BGE
PHI
Pepco
DPL
ACE
December 31, 2019
Cash and cash equivalents
Restricted cash
Restricted cash included in other
long-term assets
Total cash, cash equivalents and
restricted cash
December 31, 2018
Cash and cash equivalents
Restricted cash
Restricted cash included in other
long-term assets
Total cash, cash equivalents and
restricted cash
December 31, 2017
Cash and cash equivalents
Restricted cash
Restricted cash included in other
long-term assets
Total cash, cash equivalents and
restricted cash
December 31, 2016
Cash and cash equivalents
Restricted cash
Restricted cash included in other
long-term assets
Total cash, cash equivalents and
restricted cash
$
$
$
$
$
$
$
$
587 $
358
177
303 $
146
90 $
150
21 $
6
24 $
1
131 $
36
30 $
33
13 $
—
—
163
—
—
14
—
—
1,122 $
449 $
403 $
27 $
25 $
181 $
63 $
13 $
1,349 $
247
185
750 $
153
135 $
29
130 $
5
7 $
6
124 $
43
16 $
37
23 $
1
—
166
—
—
19
—
—
1,781 $
903 $
330 $
135 $
13 $
186 $
53 $
24 $
898 $
207
85
416 $
138
—
76 $
5
63
271 $
4
17 $
1
30 $
42
5 $
35
2 $
—
—
—
23
—
—
1,190 $
554 $
144 $
275 $
18 $
95 $
40 $
2 $
635 $
253
26
290 $
158
—
56 $
2
—
63 $
4
—
23 $
24
170 $
43
9 $
33
46 $
—
3
23
—
—
12
2
14
28
7
4
19
30
2
6
23
31
101
9
23
914 $
448 $
58 $
67 $
50 $
236 $
42 $
46 $
133
361
Table of Contents
Combined Notes to Consolidated Financial Statements
(Dollars in millions, except per share data unless otherwise noted)
Note 23 — Supplemental Financial Information
Supplemental Balance Sheet Information
The following tables provide additional information about material items recorded in the Registrants' Consolidated Balance Sheets.
December 31, 2019
December 31, 2018
Exelon
Generation
ComEd
PECO
BGE
PHI
Pepco
DPL
ACE
$
1,535 $
1,656
807 $
965
218 $
223
146 $
114
170 $
168
194 $
186
100 $
97
61 $
59
33
30
Unbilled customer revenues(a)
__________
(a) Unbilled customer revenues are classified in customer accounts receivables, net in Exelon's and the Utility Registrants' Consolidated Balance Sheets.
Exelon
Generation
ComEd
PECO
BGE
PHI
Pepco
DPL
ACE
Investments
December 31, 2019
Equity method investments:
Other equity method investments
$
92
$
71
$
6
$
8
$
— $
— $
— $
— $
—
Other investments:
Employee benefit trusts and
investments(a)
Equity investments without readily
determinable fair values
Other available for sale debt security
investments
Total investments
$
December 31, 2018
Equity method investments:
Distributed energy companies
$
Other equity method investments
Total equity method investments
Other investments:
Employee benefit trusts and
investments(a)
Equity investments without readily
determinable fair values
Other available for sale debt security
investments
Other
Total investments
$
262
69
41
464
$
180 $
87
267
244
72
40
2
625 $
54
69
41
235
$
—
—
—
6
$
19
—
—
27
$
7
—
—
7
135
110
—
—
—
—
—
—
—
$
135
$
110
$
— $
180 $
71
251
— $
6
6
— $
8
8
— $
—
—
— $
—
—
— $
—
—
49
72
—
—
17
—
5
—
40
2
414 $
—
—
6 $
—
—
25 $
—
—
5 $
130
105
—
—
—
—
—
—
130 $
105 $
— $
—
—
—
—
—
—
— $
—
—
—
—
—
—
—
—
—
—
—
—
__________
(a) The Registrants’ debt and equity security investments are recorded at fair market value.
362
Table of Contents
Combined Notes to Consolidated Financial Statements
(Dollars in millions, except per share data unless otherwise noted)
Note 23 — Supplemental Financial Information
Exelon
Generation
ComEd
PECO
BGE
PHI
Pepco
DPL
ACE
Accrued expenses
December 31, 2019
Compensation-related accruals(a)
Taxes accrued
Interest accrued
December 31, 2018
Compensation-related accruals(a)
Taxes accrued
Interest accrued
$
$
1,052 $
414
337
1,191 $
412
334
422 $
222
65
171 $
83
110
58 $
3
37
78 $
26
46
101 $
117
49
28 $
90
23
19 $
14
8
479 $
226
77
187 $
71
105
49 $
28
33
68 $
46
39
99 $
74
50
29 $
58
25
19 $
4
8
15
8
12
12
5
12
__________
(a) Primarily includes accrued payroll, bonuses and other incentives, vacation and benefits.
24. 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:
ComEd (a)(b)
PECO (c)
BGE (d)
PHI
Pepco (e)
DPL (f)
ACE (g)
Other
Total operating revenues from affiliates (Generation)
For the Years Ended
December 31,
2019
2018
2017
369 $
523 $
158
289
353
264
70
19
3
128
260
355
206
120
29
2
121
138
388
463
255
179
29
5
1,172 $
1,268 $
1,115
$
$
__________
(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 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. For 2018, ComEd’s Purchased power from Generation of $529 million is recorded as Operating revenues from ComEd of $523 million
and Purchased power and fuel from ComEd of $6 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 and gas commodity programs.
363
Table of Contents
Combined Notes to Consolidated Financial Statements
(Dollars in millions, except per share data unless otherwise noted)
(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
Note 24 — Related Party Transactions
The Registrants receive a variety of corporate support services from BSC. Pepco, DPL and ACE also receive corporate support services from PHISCO. See
Note 1 - Significant Accounting Policies for additional information regarding BSC and PHISCO.
The following table presents the service company costs allocated to the Registrants:
Operating and maintenance from
affiliates
Operating and maintenance
Capitalized costs
For the years ended December 31,
For the years ended December
31,
For the years ended December 31,
2019
2018
2017
2017
2019
2018
2017
Exelon
BSC
PHISCO
Generation
BSC
ComEd
BSC
PECO
BSC
BGE
BSC
PHI
BSC
PHISCO (a)
Pepco
BSC
PHISCO (a)
PES (b)
DPL
BSC
PHISCO (a)
PES (b)
ACE
BSC
PHISCO (a)
$
570 $
652 $
689 $
—
72
66
79
67
$
516 $
448 $
263
265
270
—
148
135
149
146
146
—
88
157
157
152
—
126
139
—
85
124
—
52
100
—
42
90
147
—
89
137
—
51
111
—
42
98
145
—
53
5
—
31
—
—
25
—
—
—
—
219
29
—
165
9
—
135
88
72
38
33
—
25
20
—
19
19
64
79
102
79
40
32
—
28
25
—
20
21
330
—
98
118
59
54
—
—
—
—
—
—
—
—
—
—
__________
(a) Due to the PHI entities' system conversion to Exelon's accounting systems on January 1, 2018, corporate support services received from PHISCO are reported in
Operating and maintenance from affiliates and in Capitalized costs beginning in 2018.
(b) PES performed underground transmission, distribution construction and maintenance services, including services that are treated as capital costs, for Pepco and DPL.
364
Table of Contents
Combined Notes to Consolidated Financial Statements
(Dollars in millions, except per share data unless otherwise noted)
Note 24 — Related Party Transactions
Current Receivables from/Payables to affiliates
The following tables present current receivables from affiliates and current payables to affiliates:
December 31, 2019
Receivables from affiliates:
Payables to affiliates:
Generation
Comed
PECO
BGE
ACE
BSC
PHISCO
Other
Total
Generation
ComEd
PECO
BGE
PHI
Pepco
DPL
ACE
Other
Total
December 31, 2018
$
$
$
27 $
78 (a)
27
28
—
34
7
7
9
190
$
—
—
—
—
—
—
1
28 $
— $
—
—
—
—
—
—
1
1 $
— $
—
—
—
—
—
—
1
1 $
— $
—
—
—
—
—
3
1
4 $
67 $
54
25
34
4
16
10
7
—
217 $
— $
—
—
—
—
15
11
10
—
36 $
23 $
8
3
4
10
1
1
1
117
140
55
66
14
66
32
25
13
51 $
528
Payables to affiliates:
Generation
Comed
BGE
Pepco
ACE
BSC
PHISCO
Other
Total
Receivables from affiliates:
Generation
$
19 $
$
ComEd
PECO
BGE
PHI
Pepco
DPL
ACE
Other
69 (a)
30
24
—
28
7
5
10
173
— $
—
—
—
—
—
—
1
1 $
— $
—
—
—
—
1
—
—
1 $
— $
—
—
—
—
—
1
—
1 $
95 $
56
26
38
3
19
11
8
—
256 $
— $
—
—
—
—
14
12
13
—
39 $
25 $
8
3
3
9
1
1
2
139
133
59
65
12
62
33
28
12
52 $
543
—
—
—
—
—
—
1
20 $
$
Total
__________
(a) At December 31, 2019 and 2018, Generation also had a contract liability with ComEd for $37 million and $14 million, respectively, that was included in Other liabilities on
Generation’s Consolidated Balance Sheets. At December 31, 2019 and 2018, ComEd had a Current Payable to Generation of $41 million and $55 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.
$
365
Table of Contents
Combined Notes to Consolidated Financial Statements
(Dollars in millions, except per share data unless otherwise noted)
Note 24 — Related Party Transactions
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 9 — 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
Other
Total:
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,
2019
2018
2,622 $
480
1
3,103 $
2,217
389
—
2,606
$
$
Exelon
2019
ComEd
As of December 31,
PECO
Exelon
2018
ComEd
$
$
206 $
205 $
— $
206 $
205 $
81
103
—
—
81
103
81
103
—
—
390 $
205 $
184 $
390 $
205 $
PECO
—
81
103
184
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.
366
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Combined Notes to Consolidated Financial Statements
(Dollars in millions, except per share data unless otherwise noted)
Note 25 — Quarterly Data
25. Quarterly Data (Unaudited) (All Registrants)
Exelon
The data shown below, which may not equal the total for the year due to the effects of rounding and dilution, includes all adjustments that Exelon considers
necessary for a fair presentation of such amounts:
Quarter ended:
March 31
June 30
September 30
December 31(a)
Quarter ended:
March 31
June 30
September 30
December 31
Operating Revenues
Operating Income
Net Income
Attributable to
Common Shareholders
2019
2018
2019
2018
2019
2018
$
9,477 $
9,691 $
1,218 $
1,099 $
907 $
7,689
8,929
8,343
8,074
9,401
8,812
841
1,353
962
940
1,144
706
484
772
773
Net Income
per Basic Share
Net Income
per Diluted Share
2019
2018
2019
2018
$
0.93 $
0.50
0.79
0.79
0.60 $
0.56
0.76
0.16
0.93 $
0.50
0.79
0.79
583
537
731
152
0.60
0.55
0.75
0.16
__________
(a) Operating revenues, Operating income and Net income attributable to common shareholders for the quarter ended December 31, 2019 include a $6 million reduction
related to a correction for Pepco’s decoupling mechanism for the 2019 interim periods. See Note 1 — Significant Accounting Policies for additional information.
Generation
The data shown below includes all adjustments that Generation considers necessary for a fair presentation of such amounts:
Quarter ended:
March 31
June 30
September 30
December 31
Operating Revenues
Operating Income
Net Income (Loss)
Attributable to
Membership Interest
2019
2018
2019
2018
2019
2018
$
5,296 $
5,512 $
333 $
347 $
363 $
4,210
4,774
4,644
4,579
5,278
5,069
147
482
362
282
311
35
108
257
397
136
178
234
(178)
367
Table of Contents
ComEd
Combined Notes to Consolidated Financial Statements
(Dollars in millions, except per share data unless otherwise noted)
Note 25 — Quarterly Data
The data shown below includes all adjustments that ComEd considers necessary for a fair presentation of such amounts:
Operating Revenues
Operating Income
Net Income
2019
2018
2019
2018
2019
2018
$
1,408 $
1,512 $
276 $
292 $
157 $
1,351
1,583
1,405
1,398
1,598
1,373
311
328
255
288
323
242
186
200
144
Quarter ended:
March 31
June 30
September 30
December 31
PECO
The data shown below includes all adjustments that PECO considers necessary for a fair presentation of such amounts:
Operating Revenues
Operating Income
Net Income
2019
2018
2019
2018
2019
2018
$
900 $
866 $
222 $
142 $
168 $
655
778
766
653
757
765
145
183
162
127
154
165
102
140
118
Quarter ended:
March 31
June 30
September 30
December 31
BGE
The data shown below includes all adjustments that BGE considers necessary for a fair presentation of such amounts:
Quarter ended:
March 31
June 30
September 30
December 31
Operating Revenues
Operating Income
Net Income
2019
2018
2019
2018
2019
2018
$
976 $
977 $
220 $
177 $
160 $
649
703
779
662
731
799
368
80
91
142
85
103
109
45
55
99
165
164
193
141
113
96
126
124
128
51
63
71
Table of Contents
PHI
Combined Notes to Consolidated Financial Statements
(Dollars in millions, except per share data unless otherwise noted)
Note 25 — Quarterly Data
The data shown below includes all adjustments that PHI considers necessary for a fair presentation of such amounts:
Quarter ended:
March 31
June 30
September 30
December 31(a)
Operating Revenues
Operating Income
Net Income
2019
2018
2019
2018
2019
2018
$
1,228 $
1,249 $
175 $
124 $
117 $
1,091
1,380
1,107
1,074
1,359
1,115
165
256
128
151
243
124
106
189
65
63
82
185
62
__________
(a) Operating revenues, Operating income and Net income attributable to common shareholders for the quarter ended December 31, 2019 include a $6 million reduction
related to a correction for Pepco’s decoupling mechanism for the 2019 interim periods. See Note 1 — Significant Accounting Policies for additional information.
Pepco
The data shown below includes all adjustments that Pepco considers necessary for a fair presentation of such amounts:
Quarter ended:
March 31
June 30
September 30
December 31(a)
Operating Revenues
Operating Income
Net Income
2019
2018
2019
2018
2019
2018
$
575 $
555 $
84 $
54 $
531
642
513
521
626
529
93
127
57
83
110
63
55 $
64
98
26
29
52
87
36
_________
(a) Operating revenues, Operating income and Net income attributable to common shareholders for the quarter ended December 31, 2019 include a $6 million reduction
related to a correction for Pepco’s decoupling mechanism for the 2019 interim periods. See Note 1 — Significant Accounting Policies for additional information.
DPL
The data shown below includes all adjustments that DPL considers necessary for a fair presentation of such amounts:
Operating Revenues
Operating Income
Net Income
2019
2018
2019
2018
2019
2018
Quarter ended:
March 31
June 30
September 30
December 31
$
380 $
384 $
287
319
319
289
328
331
369
72 $
44
51
50
49 $
42
51
48
53 $
30
33
31
31
26
33
30
Table of Contents
ACE
Combined Notes to Consolidated Financial Statements
(Dollars in millions, except per share data unless otherwise noted)
Note 25 — Quarterly Data
The data shown below includes all adjustments that ACE considers necessary for a fair presentation of such amounts:
Quarter ended:
March 31
June 30
September 30
December 31
Operating Revenues
Operating Income
Net Income (Loss)
2019
2018
2019
2018
2019
2018
$
273 $
310 $
274
419
274
265
406
254
21 $
28
79
23
23 $
25
84
14
10 $
14
63
12
7
8
61
(1)
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 2019, each registrant’s management, including its principal executive officer and principal financial officer, evaluated the
effectiveness of that registrant’s disclosure controls and procedures related to the recording, processing, summarizing and 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, 2019, 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 2019 that have materially affected, or are reasonably likely to materially affect, any of the registrant's internal control over financial reporting.
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, 2019. As a result of that
assessment, management determined that there were no material weaknesses as of December 31, 2019 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
None.
370
Table of Contents
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 11, 2020.
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 2020 proxy statement (2020 Exelon Proxy Statement) and the
ComEd information statement (2020 ComEd Information Statement) to be filed with the SEC on or before April 30, 2020 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.
371
Table of Contents
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 2020 Annual Meeting of Shareholders or the ComEd 2020 Information Statement, which are incorporated herein by reference.
372
Table of Contents
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 2020 Exelon Proxy Statement or the ComEd 2020
Information Statement and incorporated herein by reference.
Securities Authorized for Issuance under Exelon Equity Compensation Plans
[A]
[B]
[C]
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)
Number of securities
remaining available
for future issuance
under equity
compensation plans
(excluding securities
reflected in
column [A]) (Note 3)
Plan Category
Equity compensation plans approved by security
holders
__________
(1) Balance includes stock options, unvested performance shares, and unvested restricted shares 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 ranging from 0% to 150% of target award values and to a total shareholder return modifier. For performance
shares granted in 2017, 2018 and 2019, the total includes the number of shares that could be issued pursuant to the terms of the Exelon LTIP plan, which provides that
final payouts are made 50% in shares of stock and 50% in cash, and if the performance and total shareholder return modifier metrics were both at maximum, representing
a best case performance scenario, for a total of 4,005,200 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 2,002,600. The deferred stock units granted to directors includes 467,218 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 occurs after a director terminates service to the Exelon
board or the board of any of its subsidiary companies. See Note 20 — Stock-Based Compensation Plans of the Combined Notes to Consolidated Financial Statements for
additional information about the material features of the plans.
8,738,206 $
31,091,584
21.17
(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 17,125,705 shares remaining available for issuance from the employee stock purchase plan.
No ComEd securities are authorized for issuance under equity compensation plans.
373
Table of Contents
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 2020 Annual Meeting of Shareholders or the ComEd 2020 Information Statement, which are incorporated herein by reference.
374
Table of Contents
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 2020 in
the Exelon Proxy Statement for the 2020 Annual Meeting of Shareholders and the ComEd 2020 Information Statement, which are incorporated herein by
reference.
375
Table of Contents
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 11, 2020 of PricewaterhouseCoopers LLP
Consolidated Statements of Operations and Comprehensive Income for the Years Ended December 31, 2019, 2018 and 2017
Consolidated Statements of Cash Flows for the Years Ended December 31, 2019, 2018 and 2017
Consolidated Balance Sheets at December 31, 2019 and 2018
Consolidated Statements of Changes in Equity for the Years Ended December 31, 2018, 2017 and 2016
Notes to Consolidated Financial Statements
(ii)
Financial Statement Schedules:
Schedule I—Condensed Financial Information of Parent (Exelon Corporate) at December 31, 2019 and 2018 and for the Years Ended
December 31, 2019, 2018 and 2017
Schedule II—Valuation and Qualifying Accounts for the Years Ended December 31, 2019, 2018 and 2017
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.
376
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 gain on cash flow hedges
Unrealized gain on marketable securities
Unrealized gain on equity investments
Unrealized (loss) gain on foreign currency translation
Other comprehensive income (loss)
Comprehensive income
For the Years Ended
December 31,
2019
2018
2017
$
33 $
(5) $
9
1
43
(43)
(321)
3,254
39
14
2,986
2,943
7
9
4
8
(8)
(312)
2,183
42
3
1,916
1,908
(97)
$
$
$
2,936 $
2,005 $
(64) $
148
(289)
1
—
—
—
(204)
2,732 $
(66) $
247
(143)
12
—
1
(10)
41
2,046 $
10
25
4
39
(39)
(315)
4,407
40
1
4,133
4,094
315
3,779
(56)
197
10
3
6
6
7
173
3,952
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 Statements of Cash Flows
(In millions)
Net cash flows provided by operating activities
Cash flows from investing activities
Changes in Exelon intercompany money pool
Investment in affiliates
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
Retirement of long-term debt
Common stock issued from treasury stock
Dividends paid on common stock
Proceeds from employee stock plans
Other financing activities
Net cash flows used in financing activities
(Decrease) Increase in cash, cash equivalents and restricted cash
Cash, cash equivalents and restricted cash at beginning of period
For the Years Ended
December 31,
2019
2018
2017
$
1,948 $
2,576 $
1,914
95
(1,071)
—
(976)
136
—
—
—
(1,408)
112
—
(1,160)
(188)
189
1
(1,231)
—
(1,230)
—
—
—
—
(1,332)
105
(4)
(1,231)
115
74
189 $
(129)
(1,710)
(5)
(1,844)
—
500
(569)
1,150
(1,236)
150
(9)
(14)
56
18
74
Cash, cash equivalents and restricted cash at end of period
$
1 $
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 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
ASSETS
December 31,
2019
2018
$
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
379
189
48
44
—
216
182
4
683
48
3,742
40,425
1,455
898
235
46,755
47,486
Table of Contents
Exelon Corporation and Subsidiary Companies
Schedule I – Condensed Financial Information of Parent (Exelon Corporate)
Condensed Balance Sheets
(In millions)
LIABILITIES AND SHAREHOLDERS’ EQUITY
Current liabilities
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, 973 shares and 968 shares outstanding
at December 31, 2019 and 2018, respectively)
Treasury stock, at cost (2 shares at December 31, 2019 and 2018)
Retained earnings
Accumulated other comprehensive loss, net
Total shareholders’ equity
Total liabilities and shareholders’ equity
See the Notes to Financial Statements
380
December 31,
2019
2018
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
500
—
1
184
360
15
63
14
1,137
7,147
32
7,795
199
233
202
8,461
16,745
19,116
(123)
14,743
(2,995)
30,741
47,486
$
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%, and Baltimore Gas and Electric Company (BGE), of which Exelon owns 100% of the common stock but none of BGE’s
preferred stock.
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 $136 million of
outstanding commercial paper borrowings at December 31, 2019 and no outstanding commercial paper borrowings at December 31, 2018.
Short-Term Loan Agreements
On March 23, 2017, Exelon Corporate entered into a $500 million term loan agreement, which was renewed on March 22, 2018 with an expiration of March 21,
2019. The loan agreement was renewed on March 20, 2019 and will expire on March 19, 2020. Pursuant to the loan agreement, loans made thereunder bear
interest at a variable rate equal to LIBOR plus 0.95% and all indebtedness thereunder is unsecured. The loan agreement is reflected in Exelon’s Consolidated
Balance Sheet within Short-Term borrowings.
Revolving Credit Agreements
On May 26, 2016, Exelon Corporate amended its syndicated revolving credit facility with aggregate bank commitments of $600 million through May 26, 2021. On
May 26, 2018, Exelon Corporate had its maturity date extended to May 26, 2023. As of December 31, 2019, Exelon Corporation had available capacity under
those commitments of $458 million. See Note 16—Debt and Credit Agreements of the Combined Notes to Consolidated Financial Statements for additional
information regarding Exelon Corporation’s credit agreement.
Long-Term Debt
The following tables present the outstanding long-term debt for Exelon Corporate as of December 31, 2019 and December 31, 2018:
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
Rates
Maturity
Date
December 31,
2019
2018
2.45% -
3.50%
7.60%
2022 $
1,150 $
2020 - 2046
5,889
7,039
(7)
(39)
182
(1,458)
1,150
5,889
7,039
(7)
(47)
162
—
$
5,717
$
7,147
__________
(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 2020, 2021, 2022, 2023, 2024 and thereafter are as follows:
381
Table of Contents
2020
2021
2022
2023
2024
Remaining years
Total long-term debt
Exelon Corporation and Subsidiary Companies
Schedule I – Condensed Financial Information of Parent (Exelon Corporate)
Notes to Financial Statements
$
$
1,458
300
1,150
—
—
4,131
7,039
3. Commitments and Contingencies
See Note 18—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.
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:
BSC(a)
Other
Total operating and maintenance from affiliates:
Interest income from affiliates, net:
Generation
BSC
Exelon Energy Delivery Company, LLC(b)
Total interest income from affiliates, net:
Equity in earnings (losses) of investments:
Exelon Energy Delivery Company, LLC(b)
Generation
UII, LLC
PCI
BSC
Exelon Enterprises
Exelon INQB8R
Exelon Transmission Company, LLC
Other
Total equity in earnings of investments:
Cash contributions received from affiliates
For the Years Ended
December 31,
2019
2018
2017
9 $
—
9 $
36 $
3
—
39 $
2,054 $
1,125
97
1
—
(16)
(8)
(2)
3
11 $
(2)
9 $
36 $
4
2
42 $
1,830 $
369
—
(17)
—
—
—
1
—
23
2
25
37
3
—
40
1,663
2,710
41
1
1
1
—
(10)
—
3,254 $
2,183 $
4,407
2,514 $
2,302 $
1,879
$
$
$
$
$
$
$
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):
BSC(a)
Generation
ComEd
PECO
BGE
PHISCO
Exelon VTI, LLC
Total accounts receivable from affiliates (current):
Notes receivable from affiliates (current):
BSC(a)
Generation(c)
PHI
Total notes receivable from affiliates (current):
Investments in affiliates:
BSC(a)
Exelon Energy Delivery Company, LLC(b)
Generation
PCI
UII, LLC
Exelon Transmission Company, LLC
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, LLC
Exelon Enterprises
Total accounts payable to affiliates (current):
December 31,
2019
2018
11 $
13
2
2
1
7
5
41 $
109 $
558
12
679 $
197 $
28,147
13,484
62
365
—
(4)
6
(8)
(4)
13
17
4
2
2
6
—
44
116
100
—
216
197
26,679
13,204
61
268
1
(1)
22
—
(6)
42,245 $
40,425
329 $
360 $
3
363 $
898
360
—
360
$
$
$
$
$
$
$
$
$
__________
(a) Exelon Corporate receives a variety of corporate support services from BSC, including legal, human resources, financial, information technology and supply management
services. All services are provided at cost, including applicable overhead.
(b) Exelon Energy Delivery Company, LLC consists of ComEd, PECO, 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.
Exelon Corporation and Subsidiary Companies
Schedule II – Valuation and Qualifying Accounts
Column A
Column B
Column C
Column D
Column E
Description
For the year ended December 31, 2019
Additions and adjustments
Balance at
Beginning
of Period
Charged to
Costs and
Expenses
Charged
to Other
Accounts
(in millions)
Deductions
Balance at
End
of Period
Allowance for uncollectible accounts(a)
$
319
$
119
$
26
(c)
$
170 (e) $
294
Deferred tax valuation allowance
Reserve for obsolete materials
For the year ended December 31, 2018
Allowance for uncollectible accounts(a)
Deferred tax valuation allowance
Reserve for obsolete materials
For the year ended December 31, 2017
Allowance for uncollectible accounts(a)
Deferred tax valuation allowance
35
156
—
6
(9)
— (d)
—
7
$
322
$
159
$
37
174
—
25
35
5
(31)
(c)
$
197 (e) $
7
12
$
334
$
20
126
$
—
27
17
(b)(c) $
(b)
165 (e) $
—
26
155
319
35
156
322
37
Reserve for obsolete materials
__________
(a) Excludes the non-current allowance for uncollectible accounts related to PECO’s installment plan receivables of $9 million, $13 million, and $15 million for the years ended
174
113
(b)
56
10
5
December 31, 2019, 2018 and 2017, respectively.
Includes charges for late payments and non-service receivables.
(b) Primarily represents the addition of PHI's results as of March 23, 2016, the date of the merger.
(c)
(d) Primarily reflects the reclassification of assets as held for sale.
(e) Write-off of individual accounts receivable.
383
Table of Contents
(2) Generation
(i)
Financial Statements (Item 8):
Exelon Generation Company, LLC and Subsidiary Companies
Report of Independent Registered Public Accounting Firm dated February 11, 2020 of PricewaterhouseCoopers LLP
Consolidated Statements of Operations and Comprehensive Income for the Years Ended December 31, 2019, 2018 and 2017
Consolidated Statements of Cash Flows for the Years Ended December 31, 2019, 2018 and 2017
Consolidated Balance Sheets at December 31, 2019 and 2018
Consolidated Statements of Changes in Equity for the Years Ended December 31, 2019, 2018 and 2017
Notes to Consolidated Financial Statements
(ii)
Financial Statement Schedule:
Schedule II—Valuation and Qualifying Accounts for the Years Ended December 31, 2019, 2018 and 2017
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
384
Table of Contents
Exelon Generation Company, LLC and Subsidiary Companies
Schedule II – Valuation and Qualifying Accounts
Column A
Column B
Column C
Column D
Column E
Description
Balance at
Beginning
of Period
Charged to
Costs and
Expenses
Charged
to Other
Accounts
(in millions)
Deductions
Balance at
End
of Period
Additions and adjustments
For the year ended December 31, 2019
Allowance for uncollectible accounts
$
104
$
Deferred tax valuation allowance
Reserve for obsolete materials
For the year ended December 31, 2018
26
145
Allowance for uncollectible accounts
$
114
$
Deferred tax valuation allowance
Reserve for obsolete materials
For the year ended December 31, 2017
Allowance for uncollectible accounts
Deferred tax valuation allowance
$
Reserve for obsolete materials
__________
(a) Primarily reflects the reclassification of assets as held for sale.
23
166
91
$
9
106
385
$
$
27
—
—
44
—
20
34
$
—
51
$
$
$
(11)
(2)
—
4
3
(32)
(a)
—
14
9
39 $
—
2
58 $
—
9
11 $
—
—
81
24
143
104
26
145
114
23
166
Table of Contents
(3) ComEd
(i)
Financial Statements (Item 8):
Commonwealth Edison Company and Subsidiary Companies
Report of Independent Registered Public Accounting Firm dated February 11, 2020 of PricewaterhouseCoopers LLP
Consolidated Statements of Operations and Comprehensive Income for the Years Ended December 31, 2019, 2018 and 2017
Consolidated Statements of Cash Flows for the Years Ended December 31, 2019, 2018 and 2017
Consolidated Balance Sheets at December 31, 2019 and 2018
Consolidated Statements of Changes in Shareholders’ Equity for the Years Ended December 31, 2019, 2018 and 2017
Notes to Consolidated Financial Statements
(ii)
Financial Statement Schedule:
Schedule II—Valuation and Qualifying Accounts for the Years Ended December 31, 2019, 2018 and 2017
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
386
Table of Contents
Commonwealth Edison Company and Subsidiary Companies
Schedule II – Valuation and Qualifying Accounts
Column A
Column B
Column C
Column D
Column E
Description
Balance at
Beginning
of Period
Charged to
Costs and
Expenses
Charged
to Other
Accounts
(in millions)
Deductions
Balance at
End
of Period
Additions and adjustments
For the year ended December 31, 2019
Allowance for uncollectible accounts
Reserve for obsolete materials
For the year ended December 31, 2018
Allowance for uncollectible accounts
Reserve for obsolete materials
For the year ended December 31, 2017
Allowance for uncollectible accounts
$
$
$
Reserve for obsolete materials
__________
(a) Primarily charges for late payments and non-service receivables.
(b) Write-off of individual accounts receivable.
$
$
$
81
6
73
5
70
4
387
$
$
$
35
6
44
3
39
3
20 (a) $
—
23 (a) $
1
20 (a) $
1
57 (b) $
5
59 (b) $
3
56 (b) $
3
79
7
81
6
73
5
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 11, 2020 of PricewaterhouseCoopers LLP
Consolidated Statements of Operations and Comprehensive Income for the Years Ended December 31, 2019, 2018 and 2017
Consolidated Statements of Cash Flows for the Years Ended December 31, 2019, 2018 and 2017
Consolidated Balance Sheets at December 31, 2019 and 2018
Consolidated Statements of Changes in Shareholder's Equity for the Years Ended December 31, 2019, 2018 and 2017
Notes to Consolidated Financial Statements
(ii)
Financial Statement Schedule:
Schedule II—Valuation and Qualifying Accounts for the Years Ended December 31, 2019, 2018 and 2017
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
388
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
Balance at
Beginning
of Period
Charged to
Costs and
Expenses
Charged
to Other
Accounts
(in millions)
Deductions
Balance at
End
of Period
Additions and adjustments
For the year ended December 31, 2019
Allowance for uncollectible accounts(a)
Reserve for obsolete materials
For the year ended December 31, 2018
Allowance for uncollectible accounts(a)
Reserve for obsolete materials
For the year ended December 31, 2017
Allowance for uncollectible accounts(a)
$
$
$
$
$
61
2
56
2
$
$
31
—
33
—
3 (b) $
—
3 (b) $
—
33 (c) $
—
31 (c) $
—
62
2
61
2
56
Reserve for obsolete materials
__________
(a) Excludes the non-current allowance for uncollectible accounts related to PECO’s installment plan receivables of $9 million, $13 million, and $15 million for the years ended
—
—
2
2
61
$
26
$
4 (b) $
35 (c) $
—
December 31, 2019, 2018, and 2017, respectively.
(b) Primarily charges for late payments.
(c) Write-off of individual accounts receivable.
389
Table of Contents
(5) BGE
(i)
Financial Statements (Item 8):
Baltimore Gas and Electric Company and Subsidiary Companies
Report of Independent Registered Public Accounting Firm dated February 11, 2020 of PricewaterhouseCoopers LLP
Consolidated Statements of Operations and Comprehensive Income for the Years Ended December 31, 2019, 2018 and 2017
Consolidated Statements of Cash Flows for the Years Ended December 31, 2019, 2018 and 2017
Consolidated Balance Sheets at December 31, 2019 and 2018
Consolidated Statements of Changes in Shareholder's Equity for the Years Ended December 31, 2019, 2018 and 2017
Notes to Consolidated Financial Statements
(ii)
Financial Statement Schedule:
Schedule II—Valuation and Qualifying Accounts for the Years Ended December 31, 2019, 2018 and 2017
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
390
Table of Contents
Baltimore Gas and Electric Company and Subsidiary Companies
Schedule II – Valuation and Qualifying Accounts
Column A
Column B
Column C
Column D
Column E
Description
Balance at
Beginning
of Period
Charged to
Costs and
Expenses
Charged
to Other
Accounts
(in millions)
Deductions
Balance at
End
of Period
Additions and adjustments
For the year ended December 31, 2019
Allowance for uncollectible accounts
Deferred tax valuation allowance
Reserve for obsolete materials
For the year ended December 31, 2018
Allowance for uncollectible accounts
Deferred tax valuation allowance
Reserve for obsolete materials
For the year ended December 31, 2017
Allowance for uncollectible accounts
Deferred tax valuation allowance
Reserve for obsolete materials
__________
(a) Write-off of individual accounts receivable.
$
20
$
$
$
1
1
24
1
—
$
32
$
1
—
391
$
$
$
8
—
—
10
—
1
8
—
—
$
7
—
—
(2)
$
—
—
(3)
$
—
—
18 (a) $
—
—
12 (a) $
—
—
13 (a) $
—
—
17
1
1
20
1
1
24
1
—
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 11, 2020 of PricewaterhouseCoopers LLP
Consolidated Statements of Operations and Comprehensive Income for the Years Ended December 31, 2019, 2018 and 2017
Consolidated Statements of Cash Flows for the Years Ended December 31, 2019, 2018 and 2017
Consolidated Balance Sheets at December 31, 2019 and 2018
Consolidated Statements of Changes in Equity for the Years Ended December 31, 2019, 2018 and 2017
Notes to Consolidated Financial Statements
(ii)
Financial Statement Schedule:
Schedule II – Valuation and Qualifying Accounts for the Years Ended December 31, 2019, 2018 and 2017
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
392
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
Balance at
Beginning
of Period
Charged to
Costs and
Expenses
Charged
to Other
Accounts
(in millions)
Deductions
Balance at
End
of Period
Additions and adjustments
For the Year Ended December 31, 2019
Allowance for uncollectible accounts
$
53 $
Deferred tax valuation allowance
Reserve for obsolete materials
For the Year Ended December 31, 2018
Allowance for uncollectible accounts
Deferred tax valuation allowance
Reserve for obsolete materials
For the Year Ended December 31, 2017
Allowance for uncollectible accounts
Deferred tax valuation allowance
Reserve for obsolete materials
__________
(a) Primarily charges for late payments.
(b) Write-off of individual accounts receivable.
$
$
8
2
55 $
13
2
80 $
10
2
393
17 $
—
1
28 $
—
—
19 $
—
2
(a) $
7
(8)
—
24 (b) $
—
—
(a) $
37 (b) $
7
2
—
(a) $
6
3
—
7
—
50 (b) $
—
2
53
—
3
53
8
2
55
13
2
Table of Contents
(7) Pepco
(i)
Financial Statements (Item 8):
Potomac Electric Power Company
Report of Independent Registered Public Accounting Firm dated February 11, 2020 of PricewaterhouseCoopers LLP
Statements of Operations and Comprehensive Income for the Years Ended December 31, 2019, 2018 and 2017
Statements of Cash Flows for the Years Ended December 31, 2019, 2018 and 2017
Balance Sheets at December 31, 2019 and 2018
Statements of Changes in Shareholder's Equity for the Years Ended December 31, 2019, 2018 and 2017
Notes to Financial Statements
(ii)
Financial Statement Schedule:
Schedule II—Valuation and Qualifying Accounts for the Years Ended December 31, 2019, 2018 and 2017
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
394
Table of Contents
Potomac Electric Power Company
Schedule II – Valuation and Qualifying Accounts
Column A
Column B
Column C
Column D
Column E
Description
Balance at
Beginning
of Period
Charged to
Costs and
Expenses
Charged
to Other
Accounts
(in millions)
Deductions
Balance at
End
of Period
Additions and adjustments
For the year ended December 31, 2019
Allowance for uncollectible accounts
Reserve for obsolete materials
For the year ended December 31, 2018
Allowance for uncollectible accounts
Reserve for obsolete materials
For the year ended December 31, 2017
Allowance for uncollectible accounts
Reserve for obsolete materials
__________
(a) Primarily charges for late payments.
(b) Write-off of individual accounts receivable.
$
$
$
21 $
1
21 $
1
29 $
1
395
7 $
—
11 $
—
8 $
1
2 (a) $
—
3 (a) $
—
2 (a) $
—
10 (b) $
—
14 (b) $
—
18 (b) $
1
20
1
21
1
21
1
Table of Contents
(8) DPL
(i)
Financial Statements (Item 8):
Delmarva Power & Light Company
Report of Independent Registered Public Accounting Firm dated February 11, 2020 of PricewaterhouseCoopers LLP
Statements of Operations and Comprehensive Income for the Years Ended December 31, 2019, 2018 and 2017
Statements of Cash Flows for the Years Ended December 31, 2019, 2018 and 2017
Balance Sheets at December 31, 2019 and 2018
Statements of Changes in Shareholder's Equity for the Years Ended December 31, 2019, 2018 and 2017
Notes to Financial Statements
(ii)
Financial Statement Schedule:
Schedule II—Valuation and Qualifying Accounts for the Years Ended December 31, 2019, 2018 and 2017
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
396
Table of Contents
Delmarva Power & Light Company
Schedule II – Valuation and Qualifying Accounts
Column A
Column B
Column C
Column D
Column E
Description
Balance at
Beginning
of Period
Charged to
Costs and
Expenses
Charged
to Other
Accounts
(in millions)
Deductions
Balance at
End
of Period
Additions and adjustments
For the year ended December 31, 2019
Allowance for uncollectible accounts
Reserve for obsolete materials
For the year ended December 31, 2018
Allowance for uncollectible accounts
Reserve for obsolete materials
For the year ended December 31, 2017
Allowance for uncollectible accounts
Reserve for obsolete materials
__________
(a) Primarily charges for late payments.
(b) Write-off of individual accounts receivable.
$
$
$
13 $
—
16 $
—
24 $
—
397
4 $
—
6 $
—
3 $
1
3 (a) $
—
2 (a) $
—
2 (a) $
—
5 (b) $
—
11 (b) $
—
13 (b) $
1
15
—
13
—
16
—
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 11, 2020 of PricewaterhouseCoopers LLP
Consolidated Statements of Operations and Comprehensive Income for the Years Ended December 31, 2019, 2018 and 2017
Consolidated Statements of Cash Flows for the Years Ended December 31, 2019, 2018 and 2017
Consolidated Balance Sheets at December 31, 2019 and 2018
Consolidated Statements of Changes in Shareholder's Equity for the Years Ended December 31, 2019, 2018 and 2017
Notes to Consolidated Financial Statements
(ii)
Financial Statement Schedule:
Schedule II—Valuation and Qualifying Accounts for the Years Ended December 31, 2019, 2018 and 2017
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
398
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
Balance at
Beginning
of Period
Charged to
Costs and
Expenses
Charged
to Other
Accounts
(in millions)
Deductions
Balance at
End
of Period
Additions and adjustments
For the year ended December 31, 2019
Allowance for uncollectible accounts
Reserve for obsolete materials
For the year ended December 31, 2018
Allowance for uncollectible accounts
Reserve for obsolete materials
For the year ended December 31, 2017
Allowance for uncollectible accounts
Reserve for obsolete materials
__________
(a) Primarily charges for late payments.
(b) Write-off of individual accounts receivable.
$
$
$
19 $
1
18 $
1
27 $
1
399
5 $
—
11 $
—
8 $
—
2 (a) $
—
2 (a) $
—
2 (a) $
—
8 (b) $
—
12 (b) $
—
19 (b) $
—
18
1
19
1
18
1
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
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 No. 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 No. 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 No. 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 No. 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 for the quarter ended September 30, 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.
(Designated as Exhibit No. 2.1 to the Current Report on Form 8-K dated November 1, 2010, filed by Constellation Energy Group, Inc., File No.
1-12869).
Put Termination Agreement dated as of November 3, 2010, by and among EDF Inc. (formerly known as EDF Development, Inc.), E.D.F.
International S.A., Constellation Nuclear, LLC, and Constellation Energy Nuclear Group, LLC. (Designated as Exhibit No. 2.1 to the Current
Report on Form 8-K dated November 8, 2010, filed by Constellation Energy Group, Inc., File No. 1-12869).
Contribution Agreement, dated as of February 4, 2010, by and among Constellation Energy Group, Inc., Baltimore Gas and Electric Company
and RF HoldCo LLC. (Designated as Exhibit No. 99.2 to the Current Report on Form 8-K dated February 4, 2010, filed by Constellation
Energy Group, Inc., File Nos. 1-12869 and 1-1910).
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 September 25, 2019 (File No. 001-16169, Form 8-K dated September
13, 2019, Exhibit 3.1).
Certificate of Formation of Exelon Generation Company, LLC (Registration Statement No. 333-85496, Form S-4, Exhibit 3-1).
400
Table of Contents
Exhibit No.
Description
3-4
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
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).
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. 1-
1839, 1994 Form 10-K, Exhibit 3-2).
Commonwealth Edison Company Amended and Restated By-Laws, Effective June 11, 2019 (File No. 001-1839, Information Statement on
Schedule 14C, Appendix B).
Amended and Restated Articles of Incorporation of PECO Energy Company (File No. 1-01401, 2000 Form 10-K, Exhibit 3-3).
PECO Energy Company Amended and Restated Bylaws dated May 1, 2019 (File 000-16844, Form 10-Q dated May 2, 2019, Exhibit 3.2).
Articles of Amendment to the Charter of Baltimore Gas and Electric Company as of February 2, 2010. (File No. 1-1910, Form 8-K dated
February 4, 2010).
Articles of Restatement to the Charter of Baltimore Gas and Electric Company, restated as of August 16, 1996. (File No. 1-1910, Form 10-Q
dated November 14, 1996, Exhibit No. 3).
Amended and Restated Bylaws of Baltimore Gas and Electric Company dated May 1, 2019 (File No. 1-1910, Form 10-Q dated May 2, 2019,
Exhibit 3.1).
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 May 1, 2019 (File No. 001-31403, Form 10-Q
dated May 2, 2019, Exhibit 3.3)
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)
401
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
March 1, 2007
September 1, 2012
September 15, 2013
September 1, 2014
File Reference
2-4863(a)
Exhibit No.
B-1(h)
0-6844, September 30, 2004 Form 10-Q(a)
4-1-1
000-16844, Form 8-K dated September 25,
2006
4.1
000-16844, Form 8-K dated March 19, 2007
4.1
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
000-16844, Form 8-K dated September 21,
2016
000-16844, Form 8-K dated September 18,
2017
4.1
4.1
February 1, 2018
000-16844, Form 8-K dated February 23, 2018
4.1
September 1, 2018
August 15, 2019
Exhibit No.
Description
000-16844, Form 8-K dated September 11,
2018
000-16844, Form 8-K dated September 10,
2019
4.1
4.1
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)
402
Table of Contents
Exhibit No.
4-3-1
Description
Supplemental Indentures to Commonwealth Edison Company Mortgage.
Dated as of
January 13, 2003
February 22, 2006
August 1, 2006
File Reference
001-01839, Form 8-K dated February 13, 2003 4-4
001-01839, Form 8-K dated March 6, 2006
001-01839, Form 8-K dated August 28, 2006
September 15, 2006
001-01839, Form 8-K dated October 2, 2006
March 1, 2007
August 30, 2007
001-01839, Form 8-K dated March 23, 2007
001-01839, Form 8-K dated September 10,
2007
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
001-01839, Form 8-K dated August 2, 2010
001-01839, Form 8-K dated September 7,
2011
September 17, 2012
001-01839, Form 8-K dated October 1, 2012
4.1
4.1
4.1
4.1
4.1
4.1
4.1
4.1
4.1
4.1
August 1, 2013
January 2, 2014
October 28, 2014
February 18, 2015
November 4, 2015
June 15, 2016
August 9, 2017
001-01839, Form 8-K dated August 19, 2013
001-01839, Form 8-K dated January 10, 2014 4.1
001-01839, Form 8-K dated November 10,
2014
4.1
001-01839, Form 8-K dated March 2, 2015
4.1
001-01839, Form 8-K dated November 19,
2015
4.1
001-01839, Form 8-K dated June 27, 2016
4.1
001-01839, Form 8-K dated August 23, 2017
4.1
403
Table of Contents
Dated as of
February 6, 2018
July 26, 2018
February 7, 2019
October 29, 2019
File Reference
001-01839, Form 8-K dated February 20, 2018 4.1
001-01839, Form 8-K dated August 14, 2018
4.1
001-01839, Form 8-K dated February 19, 2019 4.1
001-01839, Form 8-K dated November 12,
2019
4.1
Exhibit No.
4-4
4-5
4-6
4-7
4-8
4-9
4-10
4-11
4-12
4-13
4-14
4-15
Description
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. 1-1839,
2001 Form 10-K, 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. 1-1839, 1995 Form 10-K, 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, June 30, 2003 Form 10-Q, Exhibit 4.1).
Form of 4.25% Senior Note due 2022 issued by Exelon Generation Company, LLC. (File 333-85496, Form 8-K dated June 18, 2012, Exhibit
4.1).
Form of 5.60% Senior Note due 2042 issued by Exelon Generation Company, LLC. (File 333-85496, Form 8-K dated June 18, 2012, Exhibit
4.2).
Form of 2.80% Senior Note due 2022 issued by Baltimore Gas and Electric Company. (File 1-1910, Form 8-K dated August 17, 2012,
Exhibit 4.1).
Form of 3.35% Senior Note due 2023 Baltimore Gas and Electric Company. (File 1-1910, 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, June 30, 2003 Form 10-Q, 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, June 30, 2003 Form 10-Q, 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. 1-16169, June 30, 2005 Form 10-Q, Exhibit 4-10).
Form of $500,000,000 5.625% senior notes due 2035 dated June 9, 2005 issued by Exelon Corporation (File No. 1-16169, Form 8-K dated
June 9, 2005, Exhibit 99.3).
404
Table of Contents
Exhibit No.
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
Description
Indenture dated as of September 28, 2007 from Exelon Generation Company, LLC to U.S. Bank National Association, as trustee (File 333-
85496, Form 8-K dated September 28, 2007, Exhibit 4.1).
Form of 6.25% Exelon Generation Company, LLC Senior Note due 2039 (File 333-85496, Form 8-K dated September 23, 2009, Exhibit 4.2).
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. (Designated as Exhibit
No. 4(a) to the Registration Statement on Form S-3 dated March 29, 1999, filed by Constellation Energy Group, Inc., File No. 333-75217.)
First Supplemental Indenture between Constellation Energy Group, Inc. and the Bank of New York, Trustee dated as of January 24, 2003.
(Designated as Exhibit No. 4(b) to the Registration Statement on Form S-3 dated January 24, 2003, filed by Constellation Energy Group,
Inc., File No. 333-102723).
Indenture dated as of July 24, 2006 between Constellation Energy Group, Inc. and Deutsche Bank Trust Company Americas, as trustee.
(Designated as Exhibit No. 4(a) to the Registration Statement on Form S-3 filed July 24, 2006, filed by Constellation Energy Group, Inc., File
No. 333-135991).
First Supplemental Indenture between Constellation Energy Group, Inc. and Deutsche Bank Trust Company Americas, as trustee, dated as
of June 27, 2008. (Designated as Exhibit 4(a) to the Current Report on Form 8-K dated June 30, 2008, filed by Constellation Energy Group,
Inc., File No. 1-12869).
Indenture dated June 19, 2008 between Constellation Energy Group, Inc. and Deutsche Bank Trust Company Americas, as trustee.
(Designated as Exhibit No. 4(a) to the Quarterly Report on Form 10-Q for the quarter ended June 30, 2008, filed by Constellation Energy
Group, Inc., File Nos. 1-12869 and 1-1910).
Indenture, dated as of September 30, 2013, among Continental Wind, LLC, the guarantors party thereto and Wilmington Trust, National
Association, as trustee (File No. 333-85496, Form 8-K dated September 30, 2013, Exhibit No. 4.1).
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. (Designated as Exhibit 4(b) to the Registration Statement on Form S-3 filed July 24, 2006, filed by Constellation Energy Group, Inc.,
File No. 333-135991).
Indenture dated as of June 29, 2007, by and between RSB BondCo LLC and Deutsche Bank Trust Company Americas, as Trustee and
Securities Intermediary. (Designated as Exhibit 4.1 to the Current Report on Form 8-K dated July 5, 2007, filed by Baltimore Gas and
Electric Company, File No. 1-1910).
405
Table of Contents
Exhibit No.
4-29
4-30
4-31
4-32
4-33
4-34
Description
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 (Designated as Exhibit No. 4(b) to the Quarterly Report on Form 10-Q for the quarter
ended September 30, 2009, filed by Baltimore Gas and Electric Company, File No. 1-1910).
Replacement Capital Covenant dated June 27, 2008. (Designated as Exhibit No. 4(b) to the Current Report on Form 8-K dated June 30,
2008, filed by Constellation Energy Group, Inc., File No. 1-12869).
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 No. 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. (Designated as Exhibit No. 4 (b) to the Current Report on Form 8-K dated December 14, 2010, filed
by Constellation Energy Group, Inc., File No. 1-12869).
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. (Designated as Exhibit No. 4(b) to the Current Report on Form 8-K dated November 16, 2011, filed
by Baltimore Gas and Electric Company, File No. 1-1910).
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).
4-35-1
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).
4-35-2
Form of 2.50% Notes due 2024 (File No. 001-16169, Form 8-K dated June 23, 2014, Exhibit 4.2, Exhibit A).
4-35-3
4-35-4
4-35-5
4-35-6
4-36
4-36-1
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 (incorporated herein by reference to Exhibit 4.1 to Exelon Corporation’s Current Report on Form 8-K, filed on June 11, 2015).
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 (incorporated herein by reference to Exhibit 4.2 to Exelon Corporation’s Current Report on Form 8-K, filed
on June 11, 2015).
406
Table of Contents
Exhibit No.
Description
4-36-2
4-37
4-38
4-39
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 (incorporated herein by reference to Exhibit 4.1 to Exelon Corporation’s Current Report on Form
8-K, filed on December 2, 2015).
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)
4-39-1
Supplemental Indentures to Potomac Electric Power Company Mortgage.
Dated as of
December 10, 1939
March 16, 2004
May 24, 2005
File Reference
Form 8-K, 1/3/40(a)
001-01072, Form 8-K, 3/23/04
001-01072, Form 8-K, 5/26/05
November 13, 2007
001-01072, Form 8-K, 11/15/07
March 24, 2008
December 3, 2008
March 28, 2012
March 11, 2013
001-01072, Form 8-K, 3/28/08
001-01072, Form 8-K, 12/8/08
001-01072, Form 8-K, 3/29/12
001-01072, Form 8-K, 3/12/13
November 14, 2013
001-01072, Form 8-K, 11/15/13
March 11, 2014
March 9, 2015
May 15, 2017
June 1, 2018
001-01072, Form 8-K, 3/12/14
001-01072, Form 8-K, 3/10/15
001-01072, Form 8-K, 5/22/17
001-01072, Form 8-K, 6/21/18
May 2, 2019
001-01072, Form 8-K, 6/13/19
407
Exhibit No.
B
4.3
4.2
4.2
4.1
4.2
4.2
4.2
4.2
4.2
4.3
4.2
4.2
4.2
Table of Contents
Exhibit No.
4-40
4-41
4-41-1
4-42
Description
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)
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
File Reference
Exhibit No.
33-53855, Registration Statement, 1/30/95(a)
4-L
33-53855, Registration Statement, 1/30/95(a)
4-N
001-01405, Form 10-K, 2/24/12
November 7, 2013
001-01405, Form 8-K, 11/8/13
June 2, 2014
May 4, 2015
001-01405, Form 8-K, 6/3/14
001-01405, Form 8-K, 5/5/15
December 5, 2016
001-01405, Form 8-K, 12/12/16
April 5, 2017
April 3, 2018
June 1, 2018
April 3, 2019
May 2, 2019
001-01405, Form 10-Q, 5/3/17
000-01405, Form 10-Q, 5/2/18
000-01405, Form 8-K, 6/21/18
001-01405, Form 10-Q, 5/2/19
001-01405, Form 8-K, 12/12/19
408
4.4
4.2
4.3
4.2
4.2
4.5
4.3
4.2
4.2
4.2
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 (formerly
Irving Trust Company), as trustee (File No. 2-66280, Registration Statement dated December 21, 1979, Exhibit 2(a))(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
File Reference
2-66280, Registration Statement,
12/21/79(a)
Form 10-K, 3/28/91(a)
001-03559, Form 8-K, 4/6/04
001-03559, Form 8-K, 3/17/06
001-03559, Form 8-K, 4/1/11
001-03559, Form 8-K, 8/19/14
December 1, 2015
001-03559, Form 8-K, 12/2/15
October 9, 2018
May 2, 2019
001-03559, Form 8-K, 10/16/18
001-03559, Form 8-K, 5/21/19
Exhibit No.
2(b)
4(d)(1)
4.3
4
4.2
4.2
4.2
4.1
4.3
Exhibit No.
4-45
4-46
4-47
4-48
4-49
4-50
Description
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)
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)
409
Table of Contents
Exhibit No.
4-51
Description
Corporate Commercial Paper Master Note (File No. 001-31403, Form 10-K dated February 24, 2012, Exhibit 4.13)
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
10-1
10-2
10-3
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
Description of PECO Securities
Description of ComEd Securities
Exelon Corporation Non-Employee Directors’ Deferred Stock Unit Plan (As Amended and Restated Effective September 25, 2019). * (File
No. 001-16169, Form 10-Q dated October 31, 2019, Exhibit 10.1).
Form of Exelon Corporation Unfunded Deferred Compensation Plan for Directors (as amended and restated Effective March 12, 2012). *
(File No. 1-16169, 2015 Form 10-K, 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).
410
Table of Contents
Exhibit No.
10-4
Description
Unicom Corporation Deferred Compensation Unit Plan, as amended (File Nos. 1-11375 and 1-1839, 1995 Form 10-K, Exhibit 10-12).
10-5
10-6
10-7
10-8
10-9
10-10
10-11
10-12
10-13
10-14
10-15
10-16
10-17
10-18
10-19
10-20
Amendment Number One to the Unicom Corporation Deferred Compensation Unit Plan, as amended January 1, 2008 * (File No. 001-16169,
2008 Form 10-K, Exhibit 10.16).
Exelon Corporation Supplemental Management Retirement Plan (As Amended and Restated Effective January 1, 2009) * (File No. 001-
16169, 2008 Form 10-K, Exhibit 10.19).
PECO Energy Company Supplemental Pension Benefit Plan (As Amended and Restated Effective January 1, 2009) (File No. 000-16844,
2008 Form 10-K, Exhibit 10.20).
Exelon Corporation Annual Incentive Plan for Senior Executives (As Amended Effective January 1, 2014 * (File No. 1-16169, Exelon Proxy
Statement dated April 1, 2014, Appendix A).
Exelon Corporation Employee Stock Purchase Plan, as amended and restated effective September 25, 2019 (File No. 1-16169, 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. 1-16169, Form 8-K filed
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. 1-16169, Form 10-Q dated October 31, 2019, Exhibit 10.4).
Exelon Corporation Senior Management Severance Plan (As Amended and Restated Effective January 1, 2020) *
Exelon Corporation Executive Death Benefits Plan dated as of January 1, 2003 * (File No. 1-16169, 2006 Form 10-K, Exhibit 10-52).
First Amendment to Exelon Corporation Executive Death Benefits Plan, Effective January 1, 2006 * (File No. 1-16169, 2006 Form 10-K,
Exhibit 10-53).
Amendment Number One to the Exelon Corporation 2006 Long-Term Incentive Plan, Effective December 4, 2006 (File No. 1-16169, 2006
Form 10-K, Exhibit 10-54).
Exelon Corporation Deferred Compensation Plan (As Amended and Restated Effective January 1, 2005) (File No. 1-16169, 2006 Form 10-
K, Exhibit 10-56).
Exelon Corporation Stock Deferral Plan (As Amended and Restated Effective September 25, 2019) (File No. 1-16169, Form 10-Q dated
October 31, 2019, Exhibit 10.5).
Restricted stock unit award agreement (File 1-16169, 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. 1-16169, 2015 Form 10-
K, Exhibit 10-34)
10-20-1
Form of Exelon Corporation Long-Term Incentive Program, as amended and restated as of January 1, 2020. *
10-20-2
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. 1-16169, 2015 Form 10-K, Exhibit 10-34-3)
411
Table of Contents
Exhibit No.
10-21
Description
Form of Separation Agreement under Exelon Corporation Senior Management Severance Plan (As Amended and Restated Effective
January 1, 2020)
10-22
10-23
10-24
10-25
10-26
10-27
10-28
10-29
10-30
10-31
10-32
10-33
Credit Agreement for $500,000,000 dated as of March 23, 2011 between Exelon Corporation and Various Financial Institutions (File No.
001-16169, Form 8-K dated March 23, 2011, Exhibit No. 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 No. 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 No. 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 No. 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 No. 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 No. 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 No. 4-6).
Constellation Energy Group, Inc. Nonqualified Deferred Compensation Plan, as amended and restated. * (Designated as Exhibit No. 10(b) to
the Constellation Annual Report on Form 10-K for the year ended December 31, 2008, filed by Constellation Energy Group, Inc., File Nos. 1-
12869 and 1-1910).
Constellation Energy Group, Inc. Deferred Compensation Plan for Non-Employee Directors, as amended and restated. * (Designated as
Exhibit No. 10(c) to the Constellation Annual Report on Form 10-K for the year ended December 31, 2008, filed by Constellation Energy
Group, Inc., File Nos. 1-12869 and 1-1910).
Constellation Energy Group, Inc. Benefits Restoration Plan, amended and restated effective June 1, 2010. * (Designated as Exhibit No.
10(b) to the Constellation Quarterly Report on Form 10-Q for the quarter ended June 30, 2010, filed by Constellation Energy Group, Inc.,
File Nos. 1-12869 and 1-1910).
Constellation Energy Group, Inc. Supplemental Pension Plan, as amended and restated. * (Designated as Exhibit No. 10(e) to the
Constellation Annual Report on Form 10-K for the year ended December 31, 2008, filed by Constellation Energy Group, Inc., File Nos. 1-
12869 and 1-1910).
Constellation Energy Group, Inc. Senior Executive Supplemental Plan, as amended and restated. * (Designated as Exhibit No. 10(f) to the
Constellation Annual Report on Form 10-K for the year ended December 31, 2008, filed by Constellation Energy Group, Inc., File Nos. 1-
12869 and 1-1910).
412
Table of Contents
Exhibit No.
10-34
Description
Constellation Energy Group, Inc. Executive Supplemental Benefits Plan, as amended and restated. * (Designated as Exhibit No. 10(a) to the
Constellation Quarterly Report on Form 10-Q for the quarter ended June 30, 2008, filed by Constellation Energy Group, Inc., File Nos. 1-
12869 and 1-1910).
10-35
10-36
10-37
10-38
10-39
10-40
10-41
10-42-1
10-42-2
10-42-3
10-42-4
10-43
Constellation Energy Group, Inc. Amended and Restated 2007 Long-Term Incentive Plan. * (Designated as Exhibit No. 10.1 to the Current
Report on Form 8-K dated June 4, 2010, filed by Constellation Energy Group, Inc., File No. 1-12869).
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. (Designated as Exhibit No. 10.1 to the Current Report on Form 8-K dated November 12, 2009, filed by
Constellation Energy Group, Inc., File No. 1-12869).
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.
(Designated as Exhibit No. 10(s) to the Annual Report on Form 10-K for the year ended December 31, 2010, filed by Constellation Energy
Group, Inc., File Nos. 1-12869 and 1-1910).
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.
(Designated as Exhibit No. 10(t) to the Annual Report on Form 10-K for the year ended December 31, 2010, filed by Constellation Energy
Group, Inc., File Nos. 1-12869 and 1-1910).
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.
(Designated as Exhibit No. 10.1 to the Current Report on Form 8-K dated November 3, 2010, filed by Constellation Energy Group, Inc., File
No. 1-12869).
Termination Agreement dated as of November 3, 2010, by and among EDF Inc. (formerly known as EDF Development, Inc.), E.D.F.
International S.A., and Constellation Energy Group, Inc. (Designated as Exhibit No. 10.2 to the Current Report on Form 8-K dated November
3, 2010, filed by Constellation Energy Group, Inc., File No. 1-12869).
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. (Designated as Exhibit No. 10.1 to the Current Report on Form 8-K dated
January 19, 2012, File Nos. 1-12869 and 1-1910).
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).
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)
413
Table of Contents
Exhibit No.
10-44
Description
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)
10-45
10-46
10-47
10-48
10-49
10-50
10-51
10-52
10-52-1
10-52-2
10-52-3
10-52-4
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)
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)
414
Table of Contents
Exhibit No.
Description
10-53
10-53-1
10-53-2
10-54
10-55
10-56
10-57
10-58
10-59
10-60
10-61
10-62
10-63
10-64
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)
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.)
415
Table of Contents
Exhibit No.
10-65
Description
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)
10-66
10-67
10-68
14
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
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 Code of Conduct, as amended March 12, 2012 (File No. 1-16169, Form 8-K dated March 14, 2012, Exhibit No. 14-1).
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
416
Table of Contents
Exhibit No.
24-7
24-8
24-9
24-10
24-11
24-12
24-13
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
Description
Linda P. Jojo
Paul Joskow
Robert J. Lawless
Richard W. Mies
Reserved.
Mayo A. Shattuck III
Stephen D. Steinour
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
Juan Ochoa
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
417
Table of Contents
Exhibit No.
24-37
Description
Michael E. Cryor
24-38
24-39
24-40
24-41
24-42
24-43
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
James R. Curtiss
Joseph Haskins, Jr.
Calvin G. Butler
Michael D. Sullivan
Maria Harris Tildon
Power of Attorney (Pepco Holdings LLC)
Christopher M. Crane
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, 2018 filed by the following officers for the following registrants:
Exhibit No.
31-1
Description
Filed by Christopher M. Crane for Exelon Corporation
31-2
31-3
31-4
Filed by Joseph Nigro for Exelon Corporation
Filed by Kenneth W. Cornew for Exelon Generation Company, LLC
Filed by Bryan P. Wright for Exelon Generation Company, LLC
418
Table of Contents
Exhibit No.
31-5
Description
Filed by Joseph Dominguez for Commonwealth Edison Company
31-6
31-7
31-8
31-9
31-10
31-11
31-12
31-13
31-14
31-15
31-16
31-17
31-18
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
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,
2018 filed by the following officers for the following registrants:
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 Kenneth W. Cornew 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
419
Table of Contents
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.
Cover Page Interactive Data File (formatted as Inline XBRL and contained in Exhibit 101)
104
__________
* Compensatory plan or arrangements in which directors or officers of the applicable registrant participate and which are not available to all employees.
(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.
420
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.
421
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 11th day of February, 2020.
SIGNATURES
EXELON CORPORATION
By:
/s/ CHRISTOPHER M. CRANE
Name:
Christopher M. Crane
Title:
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 11th day of February, 2020.
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 Thomas S. O'Neill, 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
Richard W. Mies
John M. Richardson
Mayo A. Shattuck III
Stephen D. Steinour
John F. Young
By:
Name:
/s/ THOMAS S. O'NEILL
Thomas S. O'Neill
February 11, 2020
422
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 11th day of February, 2020.
SIGNATURES
EXELON GENERATION COMPANY, LLC
By:
Name:
Title:
/s/ KENNETH W. CORNEW
Kenneth W. Cornew
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 11th day of February, 2020.
Signature
Title
/s/ KENNETH W. CORNEW
Kenneth W. Cornew
/s/ BRYAN P. WRIGHT
Bryan P. Wright
/s/ MATTHEW N. BAUER
Matthew N. Bauer
President and Chief Executive Officer (Principal Executive Officer)
Senior Vice President and Chief Financial Officer (Principal Financial Officer)
Vice President and Controller (Principal Accounting Officer)
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 11th day of February, 2020.
SIGNATURES
COMMONWEALTH EDISON COMPANY
By:
/s/ JOSEPH DOMINGUEZ
Name:
Joseph Dominguez
Title:
Chief Executive Officer
Pursuant to the requirements of the Securities Exchange Act of 1934, this report has been signed by the following persons on behalf of the Registrant and in the
capacities indicated on the 11th day of February, 2020.
Signature
Title
/s/ JOSEPH DOMINGUEZ
Joseph Dominguez
/s/ JEANNE M. JONES
Jeanne M. Jones
/s/ GERALD J. KOZEL
Gerald J. Kozel
Chief Executive Officer (Principal Executive Officer) and Director
Senior Vice President, Chief Financial Officer and Treasurer (Principal
Financial Officer)
Vice President and Controller (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
Nicholas DeBenedictis
Peter V. Fazio, Jr.
Michael H. Moskow
Juan Ochoa
By:
Name:
/s/ JOSEPH DOMINGUEZ
Joseph Dominguez
February 11, 2020
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 11th day of February, 2020.
SIGNATURES
PECO ENERGY COMPANY
By:
/s/ MICHAEL A. INNOCENZO
Name:
Michael A. Innocenzo
Title:
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 11th day of February, 2020.
Signature
Title
/s/ MICHAEL A. INNOCENZO
Michael A. Innocenzo
/s/ ROBERT J. STEFANI
Robert J. Stefani
/s/ SCOTT A. BAILEY
Scott A. Bailey
President, Chief Executive Officer (Principal Executive Officer) and Director
Senior Vice President, Chief Financial Officer and Treasurer (Principal
Financial Officer)
Vice President and Controller (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
425
February 11, 2020
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 11th day of February, 2020.
SIGNATURES
BALTIMORE GAS AND ELECTRIC COMPANY
By:
/s/ CARIM V. KHOUZAMI
Name:
Carim V. Khouzami
Title:
Chief Executive Officer
Pursuant to the requirements of the Securities Exchange Act of 1934, this report has been signed by the following persons on behalf of the Registrant and in the
capacities indicated on the 11th day of February, 2020.
Signature
Title
/s/ CARIM V. KHOUZAMI
Carim V. Khouzami
/s/ DAVID M. VAHOS
David M. Vahos
/s/ ANDREW W. HOLMES
Andrew W. Holmes
Chief Executive Officer (Principal Executive Officer) and Director
Senior Vice President, Chief Financial Officer and Treasurer (Principal
Financial Officer)
Vice President and Controller (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
426
February 11, 2020
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 11th day of February, 2020.
SIGNATURES
PEPCO HOLDINGS LLC
By:
/s/ DAVID M. VELAZQUEZ
Name:
David M. Velazquez
Title:
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 11th day of February, 2020.
Signature
Title
/s/ DAVID M. VELAZQUEZ
David M. Velazquez
President, Chief Executive Officer (Principal Executive Officer), and Director
/s/ PHILLIP S. BARNETT
Senior Vice President, Chief Financial Officer and Treasurer (Principal
Financial Officer)
Phillip S. Barnett
/s/ ROBERT M. AIKEN
Robert M. Aiken
Vice President and Controller (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
Christopher M. Crane
Linda W. Cropp
By:
Name:
/s/ DAVID M. VELAZQUEZ
David M. Velazquez
Michael E. Cryor
Ernest Dianastasis
Debra P. DiLorenzo
427
February 11, 2020
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 11th day of February, 2020.
SIGNATURES
POTOMAC ELECTRIC POWER COMPANY
By:
/s/ DAVID M. VELAZQUEZ
Name:
David M. Velazquez
Title:
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 11th day of February, 2020.
Signature
Title
/s/ DAVID M. VELAZQUEZ
David M. Velazquez
/s/ PHILLIP S. BARNETT
Phillip S. Barnett
/s/ ROBERT M. AIKEN
Robert M. Aiken
President, Chief Executive Officer (Principal Executive Officer), and Director
Senior Vice President, Chief Financial Officer and Treasurer (Principal
Financial Officer)
Vice President and Controller (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
By:
Name:
/s/ DAVID M. VELAZQUEZ
David M. Velazquez
Christopher M. Crane
Melissa A. Lavinson
Kevin M. McGowan
428
February 11, 2020
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 11th day of February, 2020.
SIGNATURES
DELMARVA POWER & LIGHT COMPANY
By:
/s/ DAVID M. VELAZQUEZ
Name:
David M. Velazquez
Title:
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 11th day of February, 2020.
Signature
Title
/s/ DAVID M. VELAZQUEZ
David M. Velazquez
/s/ PHILLIP S. BARNETT
Phillip S. Barnett
/s/ ROBERT M. AIKEN
Robert M. Aiken
President, Chief Executive Officer (Principal Executive Officer), and Director
Senior Vice President, Chief Financial Officer and Treasurer (Principal
Financial Officer)
Vice President and Controller (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 11, 2020
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 11th day of February, 2020.
SIGNATURES
ATLANTIC CITY ELECTRIC COMPANY
By:
/s/ DAVID M. VELAZQUEZ
Name:
David M. Velazquez
Title:
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 11th day of February, 2020.
Signature
Title
/s/ DAVID M. VELAZQUEZ
David M. Velazquez
/s/ PHILLIP S. BARNETT
Phillip S. Barnett
/s/ ROBERT M. AIKEN
Robert M. Aiken
President, Chief Executive Officer (Principal Executive Officer), and Director
Senior Vice President, Chief Financial Officer and Treasurer (Principal
Financial Officer)
Vice President and Controller (Principal Accounting Officer)
430
EXELON CORPORATION
DESCRIPTION OF SECURITIES
As of December 31, 2019, the common stock of Exelon Corporation (“Exelon” or the “Company”) is registered under Section 12(b)
of the Securities Exchange Act of 1934, as amended (the “Exchange Act”).
The summary of the general terms and provisions of the Company’s common stock set forth below does not purport to be complete
and is subject to and qualified by reference to the Company’s Articles of Incorporation (as amended, the “Articles”) and Bylaws (as
amended, the “Bylaws,” and together with the Articles, the “Charter Documents”), each of which is incorporated by reference as an
exhibit to the Company’s Annual Report on Form 10-K filed with the Securities and Exchange Commission of which this Exhibit is a
part. For additional information, please read the Company’s Charter Documents and the applicable provisions of the Pennsylvania
Business Corporation Law of 1988 (as amended from time to time, the “PBCL”).
Description of Capital Stock
Authorized Capital Stock. The Company is authorized under the Articles to issue 2,100,000,000 shares, divided into
2,000,000,000 shares of common stock, without par value, and 100,000,000 shares of preferred stock, without par value. As of
December 31, 2019, the Company had 976,152,022 shares of common stock outstanding, and zero shares of preferred stock
outstanding. The outstanding shares of the Company’s common stock are fully paid and nonassessable.
Voting Rights. Except as otherwise provided in the Charter Documents or by law, the holders of common stock have the exclusive
voting power, and every holder of common stock is entitled to one vote for every share of common stock standing in the name of
the shareholder on the Company’s books. Except as otherwise provided in the PBCL or the Charter Documents, whenever any
corporate action is to be taken by vote of the shareholders of the Company, it shall be authorized by a majority of the votes cast at
a duly organized meeting of shareholders by the holders of shares entitled to vote thereon. The shareholders of the Company may
act only at a duly organized meeting. The Board of Directors of the Company shall have the full authority permitted by law to
determine the voting rights, if any, and designations, preferences, limitations, and special rights of any class or any series of any
class of preferred stock that may be desired to the extent not determined by the Charter Documents.
Dividend Rights. Holders of common stock are entitled to receive ratably those dividends, if any, as may be declared from
time to time by the Board of Directors, in its discretion, out of funds legally available therefor, subject to any preferential dividend
rights of outstanding preferred stock.
Liquidation Rights. In the event of a liquidation, dissolution or winding up of the Company, the holders of the Company’s
common stock are entitled to share ratably in all assets remaining
after the payment of all of the Company’s liabilities and subject to the liquidation preferences of any outstanding preferred stock.
Other Rights and Preferences. The Company’s common stock does not carry preemptive rights, is not redeemable, does not
have any conversion rights, is not subject to further calls and is not subject to any sinking fund provisions. The rights and
preferences of holders of the Company’s common stock are subject to the rights of any series of preferred stock that the Company
may issue.
Listing. The Company’s common stock is listed on The Nasdaq Stock Market LLC under the trading symbol “EXC”.
Certain Anti-Takeover Provisions
Potential Issuances of the Company’s Preferred Stock. Although the Company does not currently have any shares of
preferred stock outstanding, it is authorized under the Articles to issue 100,000,000 shares of preferred stock, and the rights,
preferences and privileges of holders of common stock are subject to, and may be adversely affected by, the rights of the holders
of any series of preferred stock that the Company may designate and issue in the future. The Articles also authorize the Company’s
Board of Directors to establish, from the authorized but unissued shares, one or more series of the shares of preferred stock and to
determine, with respect to any such series of the Company’s preferred shares, the terms and rights of such series, including, for
example, the designation, the number of shares, the dividend rate of the shares, the right, if any, of the Company to redeem
shares, the voting power, if any, the obligation, if any, of the Company to retire shares, the terms and conditions, if any, upon
which shares shall be convertible into or exchangeable for shares of stock of any other class or classes, and any other rights,
preferences or limitations of the shares of such series.
The authorized shares of the Company, including shares of preferred stock and common stock, will be available for issuance
without further action by the Company’s shareholders, unless such action is required by applicable law or the rules of any stock
exchange or automated quotation system on which the Company’s securities may be listed or traded.
Provisions for Shareholder Nominations and Shareholder Proposals at Annual Meetings. The Company’s Bylaws establish an
advance notice procedure for shareholders to nominate candidates for election as directors or to bring other business before
annual meetings of the Company’s shareholders (the “Shareholder Notice Procedure”). The Shareholder Notice Procedure requires
that written notice of nominations or proposals for substantive business must be received by the Company not less than 120 days
nor more than 150 days prior to the first anniversary of the date on which the Company first mailed its proxy materials to
shareholders for the prior year’s annual meeting of shareholders; provided, that nothing in the Bylaws affects any rights of
shareholders to request inclusion of proposals in the Company’s proxy statement pursuant to Rule 14a-8 under the Exchange Act.
A shareholder who wishes to recommend a candidate (including a self-nomination) to be considered by the Corporate
Governance Committee of the Board for nomination as a Director must submit the recommendation in writing to the Chair of the
Corporate Governance Committee as set forth in the Bylaws. The Corporate Governance Committee will consider all
recommended candidates and self-nominees when making its recommendation to the full Board of Directors to nominate a slate
of Directors for election. A shareholder may also use one of two alternative provisions of the Bylaws to nominate a candidate for
election as a Director. Under one provision of the Bylaws currently in effect, a shareholder must comply with the Shareholder
Notice Procedure and the notice must include information set forth in the Bylaws. Under this procedure, any shareholder can
nominate any number of candidates for Director for election at the annual meeting, but the shareholder’s nominees will not be
included in Exelon’s proxy statement or form of proxy for the meeting.
In addition, A shareholder who meets criteria in the Exelon bylaws may also nominate a limited number of candidates for
election as Directors through provisions commonly referred to as “proxy access.” Subject to the requirements set forth in the
Bylaws, any shareholder or group of up to 20 shareholders holding both investment and voting rights with respect to at least 3% of
Exelon’s outstanding common stock continuously for at least 3 years may nominate up to 20% of the Exelon Directors to be
elected. The nominating shareholder(s) must comply with the Shareholder Notice Procedure and the notice must include
information required under the Bylaws. Under this procedure, the shareholder’s nominees will be included in the Exelon proxy
statement and the form of proxy for the meeting.
Provisions Relating to the Election of the Company’s Board of Directors. Under the Articles Articles, shareholders are
entitled to only one vote for each share held in all elections for directors. Directors are elected by a plurality of votes cast. In
addition, each director must meet the suitability requirements set forth in the Bylaws.
Removal of Company Directors. Under the Bylaws, the entire Board of Directors or any individual Director may be removed
from office by vote of the shareholders entitled to vote thereon only for cause. In case the Board or any one or more Directors are
so removed, new Directors may be elected at the same meeting.
Director Vacancies. Under the Bylaws, vacancies in the Board of Directors, including vacancies resulting from an increase in
the number of Directors, may be filled by a majority vote of the remaining members of the Board though less than a quorum, or by
a sole remaining director, and each person so selected shall be a Director to serve until the next annual meeting of shareholders,
and until a successor has been selected and qualified or until his or her earlier death, resignation or removal.
Amendment to Articles. Any amendment to the articles requires the affirmative vote of a majority of the votes cast by all
shareholders entitled to vote thereon and, if any class or series of shares is entitled to vote thereon as a class, the affirmative vote
of a majority of the votes cast in each such class vote, except for amendments on matters specified in Section 1914(c) of the PBCL
that do not require shareholder approval.
Amendment to Bylaws. Except as otherwise provided for in the express terms of any series of the shares of the Company,
any one or more provisions of the Bylaws may be altered or repealed by the Board of Directors. The shareholders or the Board of
Directors may adopt new, except that the Board of Directors may not adopt, alter or repeal bylaws that the PBCL specifies may be
adopted only by shareholders, and the Board of Directors may not alter or repeal any bylaw adopted by the shareholders that
presumes that such bylaw shall not be altered or repealed by the Board of Directors.
Special Meeting of Company Shareholders. The Charter Documents do not contain a provision permitting shareholders to
call a special meeting.
Shareholder Action by Written Consent. The Charter Documents do not contain a provision permitting action by written
consent of the shareholders.
Pennsylvania Anti-Takeover Statutes. Under Section 1715 of the PBCL, directors stand in a fiduciary relation to their
corporation and, as such, are required to perform their duties in good faith, in a manner they reasonably believe to be in the best
interests of the corporation and with such care, including reasonable inquiry, skill and diligence, as a person of ordinary prudence
would use under similar circumstances. In discharging their duties, directors may, in considering the best interests of their
corporation, consider various constituencies, including, shareholders, employees, suppliers, customers and creditors of the
corporation, and upon communities in which offices or other establishments of the corporation are located. Absent a breach of
fiduciary duty, a lack of good faith or self-dealing, any act of the Board of Directors, a committee thereof or an individual director is
presumed to be in the best interests of the corporation. The PBCL expressly provides that the fiduciary duty of directors does not
require them to (i) redeem or otherwise render inapplicable outstanding rights issued under any shareholder rights plan; (ii) render
inapplicable the anti-takeover statutes set forth in Chapter 25 of the PBCL (described below); or (iii) take any action solely because
of the effect it may have on a proposed acquisition or the consideration to be received by shareholders in such a transaction.
Chapter 25 of the PBCL contains several anti-takeover statutes applicable to publicly-traded corporations. Corporations
may opt-out of such anti-takeover statutes under certain circumstances. The Company has not opted-out of any of such statutes.
Section 2538 of Subchapter 25D of the PBCL requires certain transactions with an “interested shareholder” to be approved
by a majority of disinterested shareholders. “Interested shareholder” is defined broadly to include any shareholder who is a party
to the transaction or who is treated differently than other shareholders and affiliates of the corporation.
Subchapter 25E of the PBCL requires a person or group of persons acting in concert which acquires 20% or more of the
voting shares of the corporation to offer to purchase the shares of any other shareholder at “fair value.” “Fair value” means the
value not less than the highest price paid by the controlling person or group during the 90-day period prior to the control
transaction, plus a control premium. Among other exceptions, Subchapter 25E does not apply to shares acquired directly from the
corporation in a transaction exempt from the registration requirements of the Securities Act of 1933, as amended, or to a one-step
merger.
Subchapter 25F of the PBCL generally establishes a 5-year moratorium on a “business combination” with an “interested
shareholder.” “Interested shareholder” is defined generally to be any beneficial owner of 20% or more of the corporation's voting
stock. “Business combination” is defined broadly to include mergers, consolidations, asset sales and certain self-dealing
transactions. Certain restrictions apply to business combination following the 5-year period. Among other exceptions, Subchapter
25F will be rendered inapplicable if the board of directors approves the proposed business combination or approves the interested
shareholder's acquisition of 20% of the voting shares, in either case prior to the date on which the shareholder first becomes an
interested shareholder.
Subchapter 25G of the PBCL provides that “control shares” lose voting rights unless such rights are restored by the
affirmative vote of a majority of (i) the disinterested shares (generally, shares held by persons other than the acquirer, executive
officers of the corporation and certain employee stock plans) and (ii) the outstanding voting shares of the corporation. “Control
shares” are defined as shares which, upon acquisition, will result in a person or group acquiring for the first time voting control
over (a) 20%, (b) 331/3% or (c) 50% or more of the outstanding shares, together with shares acquired within 180 days of attaining
the applicable threshold and shares purchased with the intention of attaining such threshold. A corporation may redeem control
shares if the acquiring person does not request restoration of voting rights as permitted by Subchapter 25G. Among other
exceptions, Subchapter 25G does not apply to a merger, consolidation or a share exchange if the corporation is a party to the
transaction agreement.
Subchapter 25H of the PBCL provides in certain circumstances for the recovery by the corporation of profits realized from
the sale of its stock by a controlling person or group if the sale occurs within 18 months after the controlling person or group
became a controlling person or group, and the stock was acquired during such 18-month period or within 24 months before such
period. A controlling person or group is a person or group that has acquired, offered to acquire, or publicly disclosed an intention
to acquire 20% or more of the voting shares of the corporation. Among other exceptions, Subchapter 25H does not apply to
transactions approved by both the board of directors and the shareholders prior to the acquisition or distribution, as appropriate.
Subchapter 25I of the PBCL mandates severance compensation for eligible employees who are terminated within 24
months after the approval of a control share acquisition. Eligible employees generally are all employees employed in Pennsylvania
for at least two years prior to the control share approval. Severance equals the weekly compensation of the employee multiplied
by the employee's years of service (up to 26 years), less payments made due to the termination.
Subchapter 25J of the PBCL requires the continuation of certain labor contracts relating to business operations owned at
the time of a control share approval.
PECO ENERGY COMPANY
DESCRIPTION OF SECURITIES
As of December 31, 2019, PECO Energy Capital Trust III (the Trust), a statutory business trust and indirect, wholly owned subsidiary
of PECO Energy Company (PECO), had 78,105 Capital Trust Pass-Through Securities (the Capital Securities) registered under Section
12(b) of the Securities Exchange Act of 1934, as amended (the Exchange Act). The Capital Securities each represent a 7.38%
Cumulative Preferred Security, Series D (a Series D Preferred Security) of PECO Energy Capital, L.P., a limited partnership formed
under the laws of the State of Delaware (PECO Energy Capital). Each share of the Series D Preferred Securities has a stated
liquidation preference of $1,000.
The Trust used the proceeds from the sale of its Capital Securities to purchase the Series D Preferred Securities, which will be the
sole assets of the Trust. PECO Energy Capital lent the proceeds from the sale of its Series D Preferred Securities, plus the capital
contribution made by PECO Energy Capital Corp., a Delaware corporation and the sole general partner of PECO Energy Capital, to
PECO, which loan was evidenced by PECO’s 7.38% Subordinated Deferrable Interest Debentures, Series D, due 2028 (the Series D
Subordinated Debt Securities).
Holders of the Capital Securities are entitled to receive distributions at the rate of 7.38% of the liquidation amount of $1,000 per
Capital Security accumulating from the date of original issuance and payable (subject to any extension period) semiannually in
arrears on April 30 and October 31, of each year, commencing April 30, 1998. Whenever the Trust receives any cash distribution
representing a semiannual distribution on the Series D Preferred Securities (whether or not distributed by PECO Energy Capital on
the regular semiannual distribution date therefor) or payment under the Payment and Guarantee Agreement (the Series D
Guarantee) issued by PECO for the benefit of the holders of the Series D Preferred Securities, the Trust will distribute such
amounts to the holders of the Capital Securities in proportion to their respective number of Series D Preferred Securities
represented by such Capital Securities.
Through the Series D Guarantee, the Amended and Restated Trust Agreement relating to the Trust, the Indenture dated as of July
1, 1994 between PECO and First Union National Bank, as successor trustee, and the Series D Subordinated Debt Securities, taken
together, PECO fully, irrevocably and unconditionally guarantees all of PECO Energy Capital's obligations under the Series D
Preferred Securities. Under the Series D Guarantee, PECO will guarantee payment of accumulated and unpaid semiannual
distributions, amounts payable upon redemption and amounts payable upon liquidation with respect to the Series D Preferred
Securities, in each case, only to the extent that PECO Energy Capital has funds on hand legally available therefor and payment does
not violate applicable law. The obligations of PECO under the Series D Guarantee are subordinate and junior in right of payment to
all general liabilities of PECO and its obligations under the Series D Subordinated Debt Securities will be subordinate and junior in
right of payment to all senior indebtedness of PECO.
COMMONWEALTH EDISON COMPANY
DESCRIPTION OF SECURITIES
As of December 31, 2019, Commonwealth Edison Company (“ComEd” or the “Company”) had two classes of common stock
purchase warrants registered under Section 12(g) of the Securities Exchange Act of 1934, as amended (the “Exchange Act”); the
Company’s common stock, into which both classes of warrants are exercisable, is not registered under Section 12 of the Exchange
Act.
1971 Warrants
On April 13, 1971, the ComEd Board of Directors created a series of common stock purchase warrants (the 1971 Warrants),
pursuant to which holders can convert the 1971 Warrants into the Company’s common stock at a rate of one (1) share of common
stock for every three (3) warrants; prior to April 30, 1981, the 1971 Warrants were exercisable into shares of the Company’s
common stock at a rate of one (1) share of common stock for every three (3) warrants at an exercise price of $30 per warrant. The
1971 Warrants do not have an expiration date.
The 1971 Warrants have no established trading market and there is no assurance concerning the liquidity of any market that may
develop for the 1971 Warrants. Consequently, holders of the 1971 Warrants may not be able to liquidate their investment readily,
and lenders may not readily accept the 1971 Warrants as collateral for loans.
As of December 31, 2019, there were 40,588 1971 Warrants outstanding.
Series B Warrants
On February 1, 1972, the ComEd Board of Directors created a series of common stock purchase warrants (the Series B Warrants),
pursuant to which holders can convert the Series B Warrants into the Company’s common stock at a rate of one (1) share of
common stock for every three (3) warrants; prior to April 30, 1981, the Series B Warrants were exercisable into shares of the
Company’s common stock at a rate of one (1) share of common stock for every three (3) warrants at an exercise price of $30 per
warrant. The Series B Warrants do not have an expiration date.
The Series B Warrants have no established trading market and there is no assurance concerning the liquidity of any market that
may develop for the Series B Warrants. Consequently, holders of the Series B Warrants may not be able to liquidate their
investment readily, and lenders may not readily accept the Series B Warrants as collateral for loans.
As of December 31, 2019, there were 19,670 Series B Warrants outstanding.
EXELON CORPORATION
SENIOR MANAGEMENT SEVERANCE PLAN
(As Amended and Restated)
1.
PURPOSE OF THE PLAN
The Exelon Corporation Senior Management Severance Plan, as amended and restated herein (the “Plan”), is effective as of
January 1, 2020 (the “Effective Date”) except as otherwise specifically provided herein, and supersedes in its entirety all prior
versions of the Plan with respect to any Termination of Employment occurring on or after the Effective Date. The Plan is intended to
encourage the attraction and retention of executives of Exelon Corporation (“Exelon”) and its participating subsidiaries.
2.ELIGIBILITY
Each employee of the Company selected by the Plan Administrator whose position is in Salary Band E09 or above (an
“Executive”) shall be eligible to participate in the Plan in the event of his or her Termination of Employment, other than an
Executive whose Termination of Employment is governed by the terms and conditions of another separation or change in control
plan or agreement between such Executive and the Company or an affiliate thereof.
3.PARTICIPATION
Each eligible Executive shall become a participant in the Plan (a “Participant”) as of his or her Termination Date, subject to
his or her timely execution of, and compliance with the terms and conditions of (a) a separation agreement with the Company
(“Separation Agreement”), (b) a waiver and release of claims which has become irrevocable (“Waiver and Release”) and (c) non-
solicitation, confidential information, and intellectual property covenants and, in the discretion of the Plan Administrator, non-
competition covenants (collectively, “Restrictive Covenants”), each of the foregoing documents in such form as the Plan
Administrator, in its sole discretion, may require.
4.BENEFITS
In addition to payment of all Accrued Obligations, a Participant shall be entitled to the following benefits upon his or her
Termination of Employment:
4.1.
4.2.
Severance Pay. Continued payment of (a) his or her Base Salary, and (b) if the Participant is a participant in the Annual
Incentive Award Plan for the year in which the Termination Date occurs, his or her Target Incentive, each payable during the
Severance Period in substantially equal regular payroll installments commencing within 45 days after his or her Termination
Date.
Annual Incentive Awards. Each Participant who is a participant in the Annual Incentive Award Plan for the year in which the
Termination Date occurs shall remain eligible to receive a pro-rated Annual Incentive based on the number of days elapsed
during such year as of the Termination Date, payable at the time such awards are paid to active
employees for such year (but not later than March 15 of the year following the Termination Date). A Participant who is not a
participant in the Annual Incentive Award Plan for the year in which the Termination Date occurs shall not be entitled to an
Annual Incentive for such year, and the amount (if any) payable under any other annual incentive plan in which the
Participate participates for such year shall be determined by the Plan Administrator in its sole discretion.
4.3.
Long-Term Incentive Awards. Each of the Participant’s outstanding awards (if any) under the LTIP, including stock options,
restricted stock, restricted stock units, restricted cash, performance shares, performance units and similar stock or cash
incentive awards, shall become vested and payable to a Participant solely to the extent (and at the time) provided under the
terms of the LTIP, applicable program and/or award agreement under which such awards are granted.
4.4.
Health Care Coverage.
(a)
(b)
COBRA Coverage. During the Severance Period, a Participant (and his or her eligible dependents) who so
elects shall be eligible to participate in the health care plans under which he or she was covered immediately
prior to the Termination Date, in accordance with and subject to the terms and conditions of such plans as in
effect from time to time. The Participant’s out of pocket costs (including premiums, deductibles and co-
payments) for such coverage shall be the same as those in effect from time to time for active peer employees
during such period. Such coverage shall be provided during the Severance Period in satisfaction of
continuation coverage under Section 4980B of the Code and Section 601 to 609 of ERISA (“COBRA”) for
such period. At the end of the Severance Period, COBRA continuation coverage at the Participant’s expense
may be continued for any remaining balance of the statutory COBRA coverage period.
Retiree Coverage. A Participant who, as of the last day of the Severance Period, has attained at least age 50
and completed at least 10 years of service (or who has completed such other age and service requirement then
in effect under the Exelon Corporation Severance Benefit Plan or any successor plan as of the relevant time set
forth in such plan) shall be entitled to elect to participate in such Company group health care programs that are
then available to similarly situated retirees of his or her legacy Company. The eligibility for coverage and
availability of programs or plans, the amounts charged for coverage, and the other terms, conditions and
limitations under the Company’s group health care programs or plans shall remain subject to the Company’s
right to amend, change or terminate such programs or plans at any time.
4.5.
SERP / Other Deferred Compensation. With respect to a Participant who has a vested benefit and actively participates in the
SERP as of his or her Termination Date, the Severance Period (but not to exceed 24 months unless such Participant was
entitled to a
greater period as of January 1, 2004 under a plan or agreement then in effect) shall be taken into account as service solely for
purposes of determining, to the extent relevant under the qualified defined benefit pension plan then covering the Participant,
the amount of the Participant’s regular accrued SERP benefit, but not for purposes of determining eligibility for early
retirement benefits (including any social security supplement) or any other purpose. In determining the amount of the
Participant’s benefit, if any, the severance payments made under Section 4.1 shall be considered as if such payments were
normal base salary and incentive payments. All amounts previously deferred by, or accrued to the benefit of, such Participant
under a non-qualified deferred compensation plan of the Company shall, to the extent vested, be paid in accordance with the
Participant’s distribution election in effect thereunder as of the Termination Date (or, if no affirmative election is in effect as
of such date, the default election applicable to the Participant).
Life Insurance and Disability Coverage. A Participant shall be eligible for continued coverage under the applicable life
insurance and executive-only long term disability plans sponsored by the Company (or other equivalent coverage or benefits)
through the last day of the Severance Period applicable to such Participant on the same terms and subject to the same terms
and conditions as are applicable to active peer employees (including, without limitation, submission of proof by an Executive
who seeks long term disability benefits that such Executive would have satisfied the conditions for such benefits had the
Executive been an employee during the Severance Period and terminated employment on or before the last day of such
period).
Outplacement and Financial Counseling Services. During the twelve-month period following the Termination Date, the
Company shall reimburse the Participant for reasonable fees as incurred for services rendered by a professional outplacement
organization approved by the Plan Administrator to provide individual outplacement services, and the Participant shall be
eligible to receive financial counseling services consistent with the terms and conditions applicable to active peer executives
under Exelon’s executive perquisite policy.
4.6.
4.7.
5.CHANGE IN CONTROL BENEFITS
A Participant, whose Termination Date occurs during the period commencing ninety (90) days before a Change Date and
ending on the second anniversary of such Change Date, shall be entitled to the payment of all Accrued Obligations and the following
benefits in lieu of the benefits described in Section 4 hereof:
5.1.
Severance Pay. Continued payment of (a) his or her Base Salary, and (b) if the Participant is a participant in the Annual
Incentive Award Plan for the year in which the Termination Date occurs, his or her Target Incentive, each payable during the
Severance Period in substantially equal regular payroll installments commencing within 45 days after his or her Termination
Date.
5.2.
Annual Incentive for Year of Termination. A pro-rated Annual Incentive under the annual incentive plan applicable to such
Participant for the year in which the Termination Date
occurs, based on the number of days elapsed during such year as of the Termination Date, payable at the time such awards
are paid to active employees for such year (but not later than March 15 of the year following the Termination Date).
5.3.
Long-Term Incentive Awards.
(a)
(b)
(c)
Stock Options. Each outstanding stock option granted to the Participant under the LTIP shall (i) become fully
vested as of the Termination Date, and (ii) thereafter remain exercisable until the fifth anniversary of the
Termination Date or, if earlier, the expiration date of any such stock option, provided that this provision shall
not limit the right of the Company to cancel such stock options in connection with a Change in Control in
accordance with the terms and conditions of the LTIP.
Restricted Stock, Stock Unit and Cash Awards. All forfeiture conditions that are applicable as of the
Termination Date to any outstanding shares of restricted stock, restricted stock units or restricted cash awarded
to the Participant under the LTIP shall (except as expressly provided to the contrary in such awards) lapse and
such awards shall become fully vested as of the Termination Date.
Other LTIP Awards. To the extent the performance period applicable to any outstanding performance shares,
performance units or similar stock or cash incentive awards granted to the Executive under the LTIP has
ended as of the Termination Date (or, if later, the Change Date), including performance periods that are
terminated early in connection with the Change in Control, such awards shall become fully vested and payable
(to the extent not already paid), based on the performance level attained (or deemed to have been attained in
connection with the Change in Control). To the extent the performance period applicable to any such award
has not ended as of the Termination Date (or, if later, the Change Date), such award shall become fully vested
and payable based on the extent to which the performance goals established under the LTIP for such
performance period are attained as of the last day of the performance period.
5.4. Make-Whole if Termination Date Precedes Change Date. Notwithstanding the foregoing provisions of this Section 5, in the
event the Participant’s Termination Date occurs during the 90-day period preceding the Change Date, then (i) any payments
that would have been to the Participant earlier under Sections 5.1 or 5.2, had the Change Date preceded his or her
Termination Date, will be paid in a lump sum within 45 days after the Change Date, (ii) none of the Participant’s LTIP
awards described in Section 5.3 shall expire or be forfeited during the 90-day period preceding the Change Date, except to
the extent they would have expired or been forfeited had the Participant remained employed until the Change Date, and (iii)
any lapse of restrictions and vesting of such LTIP awards that would have occurred as of the Termination Date, had it been
preceded by the Change Date, shall occur as of the Change Date.
5.5.
Continuation of Welfare Benefits.
(a)
(b)
COBRA Coverage. During the Severance Period, a Participant (and his or her dependents) who so elects shall
be eligible to participate in the health care plans under which he or she was covered immediately prior to the
Termination Date, in accordance with and subject to the terms and conditions of such plans as in effect from
time to time. The Participant’s out of pocket costs (including premiums, deductibles and co-payments) for
such coverage shall be the same as those in effect from time to time for active peer employees during such
period. Such coverage shall be provided during the Severance Period in satisfaction of continuation coverage
under COBRA for such period. At the end of the Severance Period, COBRA continuation coverage at the
Participant’s expense may be continued for the remaining balance of the statutory COBRA coverage period, if
any.
Retiree Coverage. A Participant who, as of the last day of the Severance Period, has attained at least age 50
and completed at least 10 years of service (or who has completed such other age and service requirement then
in effect under the Exelon Corporation Severance Benefit Plan or any successor plan as of the relevant time set
forth in such plan) shall be entitled to elect to participate in such Company group health care programs that are
then available to similarly situated retirees of his or her legacy Company. The eligibility for coverage and
availability of programs or plans, the amounts charged for coverage, and the other terms, conditions and
limitations under the Company’s group health care programs or plans shall remain subject to the Company’s
right to amend, change or terminate such programs or plans at any time.
5.6.
SERP/ Other Deferred Compensation. For purposes of the Participant’s SERP benefit (if the Participant then actively
participates in the SERP), the Severance Period (but not to exceed 24 months unless such Participant was entitled to a greater
period as of January 1, 2004 under a plan or agreement then in effect) shall be taken into account as service solely for
purposes of determining whether the Participant is vested and, to the extent relevant under the qualified defined benefit
pension plan then covering the Participant, the amount of the Participant’s regular accrued SERP benefit, but not for purposes
of determining eligibility for early retirement benefits (including any social security supplement) or any other purpose. In
determining the amount of the Participant’s vested benefit, if any, the severance payments made under Section 5.1 shall be
considered as if such payments were normal base salary and incentive payments. All amounts previously deferred by, or
accrued to the benefit of, such Participant under a non-qualified deferred compensation plan of the Company shall, to the
extent vested, be paid in accordance with the Participant’s distribution election in effect thereunder as of the Termination
Date (or, if no affirmative election is in effect as of such date, the default election applicable to the Participant)
5.7.
5.8.
5.9.
Life Insurance and Disability Coverage. A Participant shall be eligible for continued coverage under the applicable life
insurance and executive-only long term disability plans or programs sponsored by the Company (or other equivalent
coverage or benefits) through the last day of the Severance Period applicable to such Participant on the same terms and
subject to the same terms and conditions as are applicable to active peer employees (including, without limitation, submission
of proof by an Executive who seeks long term disability benefits that such Executive would have satisfied the conditions for
such benefits had the Executive been an employee during the Severance Period and terminated employment on or before the
last day of such period).
Outplacement and Financial Counseling Services. During the 12-month period following the Termination Date, the Company
shall pay or cause to be paid on behalf of such Participant, as incurred, all reasonable fees and costs charged by a nationally
recognized outplacement firm selected by such Participant for outplacement services. During such period, the Participant also
shall be eligible to receive financial counseling services consistent with the terms and conditions applicable to active peer
executives under Exelon’s executive perquisite policy as of the Termination Date.
Procedural Requirements. The Company shall strictly observe or cause to be strictly observed each of the following
procedures in connection with any termination for Cause during the period commencing on a Change Date and ending on the
second anniversary of such Change Date: an eligible Executive’s termination of employment shall not be deemed to be for
Cause unless and until there shall have been delivered to such Executive a written notice of the determination of the Chief
Executive Officer of the Company which is the Executive’s employer (“CEO”) (after reasonable written notice of such
consideration by the CEO of acts or omissions alleged to constitute Cause is provided to such Executive and such Executive
is given an opportunity to present a written response to the CEO regarding such allegations), finding that, in his or her good
faith opinion, such Executive’s acts, or failure to act, constitutes Cause and specifying the particulars thereof in detail.
5.10. Sole and Exclusive Obligations. The obligations of the Company under this Plan with respect to any Termination of
Employment under this Section 5 shall supersede and not duplicate any severance obligations of the Company in any other
plan of the Company or prior agreement between such Participant and the Company or its predecessor in interest.
5.11. Payment Capped. If the Plan Administrator determines that any benefits paid or payable under this Plan to a Participant
would give rise to liability of the Participant for the excise tax imposed by Section 4999 of the Code or any successor
provision, then the amount payable to the Participant hereunder shall be reduced by the Company to the extent necessary so
that no portion is subject to such excise tax; provided, however, such reduction shall be made only if it results in the
Participant retaining a greater amount of benefits on an after-tax basis (taking into account the excise tax and applicable
federal, state, and local income and payroll taxes) than the amount of benefits on an after-tax basis (taking into account the
excise tax and applicable federal, state, and local income and payroll taxes) the Participant would have retained absent such
reduction. In the event benefits are required to be reduced pursuant to this Section 5.11, then they shall be
reduced in the following order of priority in a manner consistent with Section 409A of the Code: (i) first from cash benefits
(ii) next from performance-vested equity benefits, with benefits having later payments dates being reduced first; (iii) next
from time-vested equity benefits, with benefits having later payment dates being reduced first; and (iv) in the case of equity
benefits having the same payments dates, pro-rata amongst all such benefits. The Plan Administrator shall, in its sole
discretion, choose an independent public accounting firm or professional consulting services provider of national reputation
and experience to make in writing in good faith all calculations and determinations under this Section 5.11 including the
assumptions to be used in arriving at any calculations. For purposes of making the calculations and determinations under this
Section 5.11, the accountants may make reasonable assumptions and approximations concerning the application of Sections
280G and 4999 of the Code. The Plan Administrator shall furnish to the accountants information and documents as the
Accountants may reasonably request to make the calculations and determinations under this Section 5.11 and shall bear all
costs the accountants incur in connection with any calculations contemplated hereby.
6.TERMINATION OF PARTICIPATION; CESSATION OF BENEFITS; RECOUPMENT
A Participant’s benefits under the Plan shall terminate on the last day of the Participant’s Severance Period; provided that a
Participant’s right to benefits shall terminate immediately on the date that the Participant breaches any of the terms of his or her
Separation Agreement, Restrictive Covenants or Waiver and Release, or if at any time the Company determines (in accordance with
Section 5.9 with respect to a Participant receiving benefits under Section 5) that in the course of his or her employment the Executive
engaged in conduct described in Section 7.5(b), (c), (d) or (e), in which case the Company may require the repayment of amounts
paid pursuant to Section 4 or Section 5 (other than any Accrued Obligations) prior to such breach or other conduct, and shall
discontinue the payment of any additional amounts under the Plan.
To the extent that the Company makes payments and provides benefits to an Executive and the Executive either does not
timely execute and deliver the Waiver and Release to the Company or revokes the Waiver and Release in accordance with its terms,
Executive shall pay to the Company within 10 days following the expiration of the consideration period of the Waiver and Release
or the date such Waiver and Release was revoked, a lump sum payment of all payments and the value of all benefits (other than
Accrued Obligations) received by Executive to date hereunder.
Notwithstanding any provision of the Plan or any Separation Agreement to the contrary, benefits paid or payable to a
Participant under the Plan shall be subject to any executive or officer recoupment or claw back policy of the Board of Directors as in
effect as of the Termination Date. Any termination and/or recoupment of benefits under the Plan shall be in addition and without
prejudice to any other remedies that the Company may elect to assert.
7.DEFINITIONS
In addition to terms previously defined, when used in the Plan, the following capitalized terms shall have the following
meanings unless the context clearly indicates otherwise:
7.1.
7.2.
7.3.
7.4.
“Accrued Obligations” means, the sum of a Participant’s (a) Base Salary (b) any annual incentive with respect to the
preceding fiscal year, (c) any unused vacation or paid time off days and (d) any properly reimbursable business expenses; in
each case which are accrued but unpaid as of the Termination Date.
“Annual Incentive” means (a) for purposes of Section 4 hereof, an amount to which a Participant would have been entitled
under the Annual Incentive Award Plan based on the actual performance goals established pursuant to such plan and
assuming a “meaningful impact” individual performance rating, or (b) for purposes of Section 5 hereof, an amount to which a
Participant would have been entitled under the Annual Incentive Award Plan (or any other short-term incentive plan of the
Company or its successor applicable to such Participant in lieu of the Annual Incentive Award Plan) based on the actual
achievement of performance goals established pursuant to such plan (or if such performance cannot reasonably be
determined, the average of the actual Annual Incentives paid or payable to the Participant for each of the two calendar years
preceding the Termination Date), assuming a “meaningful impact” individual performance rating (if applicable) and
disregarding any reduction in a Participant’s Base Salary or Target Incentive (if any) occurring during the period beginning
90 days prior to the Change Date.
“Annual Incentive Award Plan”, means the Exelon Corporation Annual Incentive Award Plan (but not any other short-term
incentive plan of a Company), or any successor plan thereto (including but not limited to any annual incentive plan of a
successor to Exelon pursuant to a Change in Control).
“Base Salary” means (a) for purposes of Section 4, the annualized base salary payable to the Participant as of his or her
Termination Date, and (b) for purposes of Section 5, the greater of the amount determined in the immediately preceding
clause and 12 times the highest annualized base salary paid or payable to the Participant by the Company in respect of the 12-
month period immediately before the Change Date.
7.5.
“Cause” means, with respect to any Executive:
(a)
(b)
the refusal to perform or habitual neglect in the performance of the Executive’s duties or responsibilities, or of
specific directives of the Board of Directors of a Company or the officer or other executive to whom the
Executive reports which are not materially inconsistent with the scope and nature of the Executive’s
employment duties and responsibilities;
the Executive’s willful or reckless commission of act(s) or omission(s) which have resulted in, or in the
Company’s reasonable judgment are likely to result in, a material loss to, or material damage to the reputation
of the Company or any of its affiliates, or that compromise the safety of any employee or other person;
(c)
(d)
the Executive’s commission of a felony or any crime involving dishonesty or moral turpitude;
the Executive’s material violation of Exelon’s or any of its affiliate’s Code of Business Conduct (including the
corporate policies referenced therein), or of any statutory or common law duty of loyalty to Exelon or any of
its affiliates; or
(e)
any breach by the Executive of one or more of the Restrictive Covenants.
7.6.
“Change Date” means the date on which a Change in Control occurs.
7.7.
“Change in Control” has the meaning set forth in the definition of such term in the LTIP.
7.8.
“COBRA” has the meaning set forth in Section 4.4 hereof.
7.9.
“Code” means the Internal Revenue Code of 1986, as amended.
7.10.
“Company” means, individually and collectively, Exelon, Atlantic City Electric Company, Baltimore Gas and Electric
Company, Commonwealth Edison Company, Delmarva Power & Light Company, Exelon Business Services Company, LLC,
Exelon Generation Company, LLC (including its Constellation business unit), PECO Energy Company, Pepco Holdings,
LLC, Potomac Electric Power Company and any other subsidiary of the foregoing of which Exelon directly or indirectly
owns at least 80% of the outstanding voting power and that is designated by the Plan Administrator as a participating
employer in the Plan.
7.11.
“ERISA” means the Employee Retirement Income Security Act of 1974, as amended.
7.12.
“Executive” has the meaning set forth in Section 2 hereof.
7.13.
“Exelon” has the meaning set forth in Section 1 hereof.
7.14.
“Good Reason” means:
(a)
for purposes of Section 4 hereof,
(i)
a material reduction of an Executive’s base salary unless such reduction is part of a policy, program or
arrangement applicable to peer executives of the Company or of the Executive’s business unit;
(ii)
a demotion below the Executive level; or
(iii)
with respect to Exelon’s Chief Executive Officer, a material adverse reduction in his or her position or
duties, but excluding any such change caused solely by a disposition of all or a significant portion of a
Company’s business or operations.
(b)
for purposes of Section 5 hereof, the occurrence of any one or more of the following actions or omissions that
occurs during the period commencing on a Change Date and ending on the second anniversary of such Change
Date:
(i)
(ii)
(iii)
a material reduction of an Executive’s base salary, incentive compensation opportunity or aggregate
benefits;
a material adverse reduction in the Executive’s position, duties or responsibilities (excluding, with
respect to an Executive other than the Chief Executive Officer of a Company, a change in the position
or level of officer to whom the Executive reports);
a relocation by more than 50 miles of (A) the Executive’s primary workplace, or (B) the principal
offices of Exelon or its successor (if such offices are such Executive’s workplace), in each case
without the Executive’s consent; provided, however, in both cases of (A) and (B) of this subsection (b)
(iii), such new location is farther from the Executive’s residence than the prior location; or
(iv)
a material breach of this Plan by Exelon or its successor.
(c)
Limitations on Good Reason. Notwithstanding the foregoing provisions of this Section, no act or omission
shall constitute a material breach of this Plan by Exelon, nor grounds for “Good Reason”:
(i)
(ii)
unless the Executive gives the Plan Administrator a Notice of Termination at least 30 days prior to the
Executive’s Termination Date, and the Company fails to cure such act or omission within the 30-day
period;
if the Executive first acquired knowledge of such act or omission more than 90 days before such
Participant gives the Plan Administrator such Notice or Termination; or
(iii)
if the Executive has consented in writing to such act or omission.
7.15.
“including” means including without limitation.
7.16.
“LTIP” means the Exelon Corporation Long-Term Incentive Plan, as amended from time to time, or any successor thereto.
7.17.
“Notice of Termination” means a written notice given by an Executive to the executive or officer to whom he or she reports
and to the Plan Administrator which sets forth in reasonable detail the specific facts and circumstances claimed to provide a
basis for a Termination of Employment for Good Reason.
7.18.
“Participant” has the meaning set forth in Section 3 hereof.
7.19.
7.20.
“Person” means any individual, sole proprietorship, partnership, joint venture, limited liability company, trust,
unincorporated organization, association, corporation, institution, public benefit corporation, entity or government
instrumentality, division, agency, body or department.
“Plan Administrator” means Exelon’s Vice President, Corporate Compensation or, in the event the person holding such
position as of a Change Date ceases to hold such position during the succeeding 24 months, a person appointed by the
majority of the member of the board of directors who were directors of Exelon immediately prior to the Change Date.
7.21.
“Restrictive Covenants” has the meaning set forth in Section 3 hereof.
7.22.
“Section” means, unless the context otherwise requires, a section of this Plan.
7.23.
“Senior Executive Management” means (a) Exelon’s Chief Executive Officer and each Senior Vice President or above of
Exelon who reports directly to Exelon’s Chief Executive Officer and/or who is Exelon’s Chief Financial, Human Resources
or Legal Officer, and (b) any other Executive who was a member of Senior Executive Management as of December 31, 2019
(as defined in the Plan as of such date).
7.24.
“Separation Agreement” has the meaning set forth in Section 3 hereof.
7.25.
“SERP” means the non-qualified supplemental defined benefit pension plan of the Company, if any, in which an Executive
actively participates as of his or her Termination Date.
7.26.
“Severance Period” means the period during which Base Salary and Target Incentive is payable to a Participant, based on his
or her level of seniority and period of continuous service with the Company immediately preceding the Termination Date, as
set forth below.
(a)
For purposes of Section 4 hereof, the Severance Period with respect to:
(i)
(ii)
Senior Executive Management shall be 24 months (18 months if less than 2 continuous years of
service; 12 months if less than one continuous year of service);
any other Senior Vice President or above of Exelon or a Chief Executive Officer of a Company other
than Exelon shall be 18 months (12 months if less than 2 continuous years of service; 6 months if less
than 1 continuous year of service); and
(iii)
any other Executive shall be 15 months (12 months if less than 2 continuous years of service; 6 months
if less than 1 continuous year of service).
(b)
For purposes of Section 5 (i.e., Change in Control) hereof, the Severance Period with respect to:
(i)
(ii)
Senior Executive Management shall be 2.99 years;
any other Senior Vice President or above of Exelon or a Chief Executive Officer of a Company other
than Exelon shall be 24 months;
(iii)
a Senior Vice President or above of a Company other than Exelon shall be 18 months; and
(iv)
any other Executive shall be 15 months.
7.27.
“Specified Employee” means a “specified employee” within the meaning of Section 409A of the Code.
7.28.
7.29.
“Target Incentive” means an amount equal to the percentage of the Participant’s Base Salary (if any) to which he or she
would have been entitled immediately prior to such date under the Annual Incentive Award Plan for the year in which the
Termination Date occurs if the Participant were employed for the entire year and the performance goals established pursuant
to such plan were achieved at the 100% (target) level.
“Termination Date” means the effective date of an eligible Executive’s Termination of Employment with the Company,
which shall be the date on which such Executive has a “separation from service,” within the meaning of Section 409A of the
Code; provided, however, that if the Executive terminates his or her employment for Good Reason, the Termination Date
shall not be earlier than the thirtieth day following the Company’s receipt of such Executive’s Notice of Termination, unless
the Plan Administrator consents in writing to an earlier Termination Date.
7.30.
“Termination of Employment” means:
(a)
a termination of an eligible Executive’s employment by the Company for reasons other than for Cause or
disability; or
(b)
a resignation by an eligible Executive for Good Reason.
The following shall not constitute a Termination of Employment for purposes of the Plan: (i) a termination of employment
for Cause, (ii) an Executive’s resignation for any reason other than for Good Reason, (iii) the cessation of an Executive’s
employment with the Company or any Affiliate due to death or disability (as determined by the Plan Administrator in good
faith), or (iv) the cessation of an Executive’s employment with the Company or any subsidiary thereof as the result of the
sale, spin-off or other divestiture of a plant, division, business unit or subsidiary or a merger or other business combination
followed by employment or reemployment with the purchaser or successor in interest to the Executive’s employer with
regard to such plant, division, business unit or subsidiary,
or an offer of employment by such purchaser or successor in interest on terms and conditions substantially comparable in the
aggregate (as determined by the Plan Administrator in its sole discretion) to the terms and conditions of the Executive’s
employment with the Company or its subsidiary immediately prior to such transaction.
7.31 “Waiver and Release” has the meaning set forth in Section 3 hereof.
8.FUNDING
The Plan is an unfunded employee welfare benefit plan maintained for the purpose of providing severance benefits to a select
group of management or highly compensated employees. Nothing in the Plan shall be interpreted as requiring the Company to set
aside any of its assets for the purpose of funding its obligations under the Plan. No person entitled to benefits under the Plan shall
have any right, title or claim in or to any specific assets of the Company, but shall have the right only as a general creditor to receive
benefits from the Company on the terms and conditions provided in the Plan.
9.ADMINISTRATION OF THE PLAN
The Plan shall be administered on a day-to-day basis by the Plan Administrator. The Plan Administrator has the sole and
absolute power and authority to interpret and apply the provisions of this Plan to a particular circumstance, make all factual and legal
determinations, construe uncertain or disputed terms and make eligibility and benefit determinations in such manner and to such
extent as the Plan Administrator, in his or her sole discretion may determine. Benefits under the Plan will be paid only if the Plan
Administrator, in his or her discretion, determines that an individual is entitled to them; provided, however, that any dispute after the
claims procedure under Section 10 has been exhausted regarding whether an Executive’s termination of employment for purposes of
Section 5 is based on either Good Reason or Cause may, at the election of the Executive, be submitted to binding arbitration pursuant
to Section 11.
The Plan Administrator may promulgate any rules and regulations it deems necessary to carry out the purposes of the Plan or
to interpret the terms and conditions of the Plan; provided, however, that no rule, regulation or interpretation shall be contrary to the
provisions of the Plan. The rules, regulations and interpretations made by the Plan Administrator shall, where appropriate, be applied
on a consistent basis with respect to similarly situated Executives, and shall be final and binding on any Executive or former
Executive and any successor in interest.
The Plan Administrator may delegate any administrative duties, including, without limitation, duties with respect to the
processing, review, investigation, approval and payment of severance pay and provision of severance benefits, to designated
individuals or committees. The Plan Administrator may amend any Participant’s Separation Agreement to the extent the Plan
Administrator determines it is reasonably necessary or appropriate to do so to comply with section 409A of the Code.
10.CLAIMS PROCEDURE
The Plan Administrator shall determine the status of an individual as an Executive and the eligibility and rights of any
Executive or former Executive as a Participant to any severance
pay or benefits hereunder. Any Executive or former Executive who believes that he or she is entitled to receive severance pay or
benefits under the Plan, including severance pay or benefits other than those initially determined by the Plan Administrator, may file
a claim in writing with the Plan Administrator. Within 90 days after the receipt of the claim the Plan Administrator shall either allow
or deny the claim in writing, unless special circumstances require an extension of time for processing, in which case a decision shall
be rendered as soon as practicable, but not later than 180 days after receipt of a request for review.
A claimant whose claim is denied (or his or her duly authorized representative) may, within 60 days after receipt of the denial
of his or her claim, request a review upon written application to Exelon’s Chief Human Resources Officer or other officer designated
by Exelon and specified in the claim denial; review (without charge) relevant documents; and submit written comments, documents,
records and other information relating to the claim.
The Chief Human Resources Officer or other designated officer shall notify the claimant of his or her decision on review
within 60 days after receipt of a request for review unless special circumstances require an extension of time for processing, in which
case a decision shall be rendered as soon as possible, but not later than 120 days after receipt of a request for review. Notice of the
decision on review shall be in writing. The officer’s decision on review shall be final and binding on any claimant or any successor
in interest.
In reviewing a claim or an appeal of a claim denial, the Plan Administrator and the Chief Human Resources Officer or other
officer designated by Exelon shall have all of the powers and authority granted to the Plan Administrator pursuant to Section 9.
11.STATUTE OF LIMITATIONS; ARBITRATION
No Executive (or representative thereof) may bring any legal or equitable action to recover benefits under the Plan until he or
she has exhausted the internal claims and appeals process described above. Any such action must be commenced no later than the
first anniversary of a final decision on a claim for benefits (or such earlier date provided in any applicable statute of limitations). Any
such action shall be brought exclusively in the federal courts in the Northern District of Illinois, provided that any dispute,
controversy or claim between the parties hereto concerning whether an Executive’s termination of employment for purposes of
Section 5 is based on either Good Reason or Cause may, at the election of the Executive, be settled by binding arbitration in
Chicago, Illinois, before an impartial arbitrator pursuant to the rules and regulations of the American Arbitration Association
(“AAA”) pertaining to the arbitration of commercial disputes. The costs and fees of the arbitrator shall be borne equally by the
parties, regardless of the result of the arbitration. Notwithstanding anything to the contrary contained in this Section or elsewhere in
this Plan, any party may seek relief in the form of specific performance, injunctive or other equitable relief in order to enforce the
decision of the arbitrator, and the Company may seek injunctive relief to enforce the above-referenced statutes of limitations.
12.AMENDMENT OR TERMINATION OF PLAN
The Compensation and Leadership Development Committee of Exelon’s Board of Directors (or its delegate) may amend,
modify or terminate the Plan at any time, and Exelon’s
Chief Human Resources Officer may amend the Plan with respect to matters other than eligibility and severance levels of executive
officers at any time; provided, however, that no amendment, modification or termination shall deprive any Participant of any
payment or benefit that the Plan Administrator previously has determined is payable under the Plan. Notwithstanding the foregoing,
no amendment or termination that reduces the severance payments or materially adversely affects any Participant’s other benefits
under Section 5 shall become effective as to such Participant during the 24-month period following a Change Date unless such
Participant consents to such termination or amendment. Any purported Plan termination or amendment in violation of this Section 12
shall be void and of no effect.
13.MISCELLANEOUS
13.1. Limitation on Rights. Participation in the Plan is limited to the individuals described in Sections 2 and 3, and the benefits
under the Plan shall not be payable with respect to any voluntary or involuntary termination of employment that is not a
Termination of Employment.
13.2. Offset; No Mitigation.
(a)
(b)
To the extent permitted by Section 409A of the Code, the amount of a Participant’s payments under Section 4
of this Plan may be reduced to the extent necessary to defray amounts owed by the Participant due to unused
expense account balances, overpayment of salary, awards or bonuses, advances or loans.
A Participant shall not have any duty to mitigate the amounts payable by the Company under this Plan by
seeking new employment following termination. Except as specifically otherwise provided in this Plan, all
amounts payable pursuant to this Plan shall be paid without reduction regardless of any amounts of salary,
compensation or other amounts which may be paid or payable to the Executive as the result of the Executive’s
employment by another, unaffiliated employer.
13.3.
Indemnification. Each Participant shall be indemnified and held harmless by the Company to the greatest extent permitted
under applicable law and the Company’s by-laws (as in effect immediately preceding the Change Date with respect to a
termination pursuant to Section 5) if such Participant was, is, or is threatened to be, made a party to any pending, completed
or threatened action, suit, arbitration, alternate dispute resolution mechanism, investigation, administrative hearing or any
other proceeding brought by a third party whether civil, criminal, administrative or investigative, and whether formal or
informal, by reason of the fact that such Participant is or was, or had agreed to become, a director, officer, employee, agent,
or fiduciary of the Company or any other entity which such Participant is or was serving at the request of the Company
(“Proceeding”), against all expenses (including all reasonable attorneys’ fees) and all claims, damages, liabilities and losses
incurred or suffered by such Participant or to which such Participant may become subject for any reason; provided, that the
Participant provides the Plan Administrator written notice of any such Proceeding promptly after receipt and such that
the Company’s ability to defend shall not be prejudiced in any fashion and the Company shall have the right to direct the
defense, approve any settlement and shall not be required to indemnify the Participant in connection with any proceeding
initiated by the Participant, including a counterclaim or crossclaim.
13.4. Severability. If any one or more Sections, subsections or other portions of this Plan are declared by any court or
governmental authority to be unlawful or invalid, such unlawfulness or invalidity shall not serve to invalidate any Section,
subsection or other portion not so declared to be unlawful or invalid. Any Section, subsection or other portion so declared to
be unlawful or invalid shall be construed so as to effectuate the terms of such Section, subsection or other portion to the
fullest extent possible while remaining lawful and valid. Notwithstanding the foregoing, in the event a determination is made
that the Restrictive Covenants are invalid or unenforceable in whole or in part, then the Separation Agreement with respect to
the Participant subject to such determination shall be void and the Company shall have no obligation to provide benefits
under this Plan to such Participant.
13.5. Governing Law. The Plan shall be construed and enforced in accordance with the applicable provisions of ERISA and
Section 409A of the Code.
13.6. No Right to Continued Employment. Nothing in this Plan shall guarantee the right of a Participant to continue in
employment, and the Company retains the right to terminate a Participant’s employment at any time for any reason or for no
reason.
13.7. Successors and Assigns. This Plan shall be binding upon and inure to the benefit of Exelon and its successors and assigns and
shall be binding upon and inure to the benefit of a Participant and his or her legal representatives, heirs and legatees. No
rights, obligations or liabilities of a Participant hereunder shall be assignable without the Plan Administrator’s prior written
consent. In the event of the death of a Participant prior to receipt of severance pay or benefits to which he or she is entitled
hereunder (and, with respect to benefits under Section 4 or Section 5, after he or she has signed the Waiver and Release), the
severance pay described in Section 4.1 or 5.1, as applicable, shall be paid to his or her estate, and the Participant’s dependents
who are covered under any health care plans maintained by the Company shall be entitled to continued rights under
Section 4.4 or Section 5.5, as applicable; provided that the estate or other successor of the Participant has not revoked such
Waiver and Release.
13.8. Notices. All notices and other communications under this Plan shall be in writing and delivered by hand, by nationally
recognized delivery service that promises overnight delivery, or by first-class registered or certified mail, return receipt
requested, postage prepaid, addressed as follows:
(a)
(b)
If to a Participant, to such Participant at his most recent home address on file with the Company;
If to the Company, to the Plan Administrator;
(c)
or to such other address as either party shall have furnished to the other in writing. Notice and
communications shall be effective upon notice of delivery to the addressee.
13.9. Tax Withholding. The Company may withhold from any amounts payable under this Plan or otherwise payable to a
Participant or beneficiary any federal, state, city and other taxes the Company determines to be appropriate under applicable
law and may report all such amounts payable to such authority in accordance with any applicable law or regulation.
13.10. Section 409A and Changes to Law.
(a)
(b)
(c)
It is the intention of the Company that the provisions of this Plan comply with Section 409A of the Code, and
all provisions of this Plan shall be construed and interpreted in a manner consistent with Section 409A of the
Code. The Company shall administer and operate this Plan in compliance with Section 409A of the Code and
any rules, regulations or other guidance promulgated thereunder as in effect from time to time and in the event
that the Company determines that any provision of this Plan does not comply with Section 409A of the Code
or any such rules, regulations or guidance and that as a result any Participant may become subject to a tax
under Section 409A of the Code, notwithstanding Section 12, the Company shall have the discretion to amend
or modify such provision to avoid the application of such tax, and in no event shall any Participant’s consent
be required for such amendment or modification. Notwithstanding any provision of this Plan to the contrary,
each Participant shall be solely responsible and liable for the satisfaction of all taxes and penalties that may
arise in connection with amounts payable pursuant to this Plan (including any taxes arising under Section
409A of the Code), and the Company not shall have any obligation to indemnify or otherwise hold such
Participant harmless from any or all of such taxes.
In the event that the Company determines that any provision of this Plan violates, or would result in any
material liability (other than liabilities for the severance benefits) to the Company, under any law, regulation,
rule or similar authority of any governmental agency the Company shall be entitled, notwithstanding Section
12, to amend or modify such provision as the Company determines in its discretion to be necessary or
desirable to avoid such violation or liability, and in no event shall any Participant’s consent be required for
such amendment or modification.
The payments under this Plan are designated as separate payments for purposes of the short-term deferral rule
under Treasury Regulation Section 1.409A-1(b)(4), the exemption for involuntary terminations under
separation pay plans under Treasury Regulation Section 1.409A 1(b)(9)(iii), and the exemption for medical
expense reimbursements under Treasury Regulation Section 1.409A 1(b)(9)(v)(B). As a result, (A)
(d)
(e)
payments that are made on or before the 15th day of the third month of the calendar year following the year
that includes the Participant’s Termination Date, (B) any additional payments that are made on or before the
last day of the second calendar year following the year of the Participant’s Termination Date and do not
exceed the lesser of two times the Participant’s annual rate of pay in the year prior to his termination or two
times the limit under Section 401(a)(17) of the Code then in effect, and (C) continued medical expense
reimbursements during the applicable COBRA period, are exempt from the requirements of Section 409A of
the Code.
To the extent any amounts under this Plan are payable by reference to a Participant’s Termination of
Employment, such term and similar terms shall be deemed to refer to such Participant’s “separation from
service,” within the meaning of Section 409A of the Code. Notwithstanding any other provision in this Plan,
to the extent any payments hereunder constitute “nonqualified deferred compensation,” within the meaning of
Section 409A of the Code (a “Section 409A Payment”), and the Participant is a specified employee, within the
meaning of Treasury Regulation Section 1.409A 1(i), as determined by the Company in accordance with any
method permitted under Section 409A of the Code, as of the date of the Participant’s separation from service,
each such Section 409A Payment that is payable upon such Participant’s separation from service and would
have been paid prior to the six-month anniversary of such Participant’s separation from service, shall be
delayed until the earlier to occur of (i) the six-month anniversary of Participant’s separation from service and
(ii) the date of Participant’s death. Further, to the extent that any amount is a Section 409A Payment and such
payment is conditioned upon Participant’s execution of a release and which is to be paid or provided during a
designated period that begins in one taxable year and ends in a second taxable year, then such Section 409A
Payment shall be paid or provided in the later of the two taxable years.
Any reimbursements payable to a Participant pursuant to this Plan or otherwise shall be paid to such
Participant in no event later than the last day of the calendar year following the calendar year in which such
Participant incurred the reimbursable expense. Any amount of expenses eligible for reimbursement, or in-kind
benefit provided, during a calendar year shall not affect the amount of expenses eligible for reimbursement, or
in-kind benefit to be provided, during any other calendar year. The right to any reimbursement or in-kind
benefit pursuant to this Plan shall not be subject to liquidation or exchange for any other benefit. Any tax
gross-up payment payable to a Participant, whether under this Plan or otherwise, shall be paid to the
Participant or to the applicable taxing authorities on the Participant’s behalf as soon as practicable after the
related taxes are due, but in any event not later than the last day of the calendar year
following the calendar year in which the related taxes are remitted to the taxing authorities
EXELON CORPORATION
By: _______________________________
Senior Vice President and
Chief Human Resources Officer
THIS SEPARATION AGREEMENT (this “Agreement”) is entered into as of ____________, 20_____ between Exelon Corporation (“Exelon”), __________
(“Subsidiary”, and, collectively with Exelon, the “Company”) and _________________ (the “Executive”).
SEPARATION AGREEMENT
WHEREAS, the Executive is separating from all positions with the Company and its respective affiliates.
W I T N E S S E T H:
NOW, THEREFORE, in consideration of the mutual promises and agreements contained herein, the adequacy and sufficiency of which are hereby
acknowledged, the Company and the Executive agree as follows:
1. Resignation & Termination of Employment. The Executive’s employment will be terminated and Executive hereby resigns, each effective as
of the close of business on ______ , 20 _____ (the “Termination Date”), from his or her position as ____ and from all other positions as an officer or director of
Exelon and its subsidiaries and affiliates. [During the period commencing on the date hereof and ending on the Termination Date, Executive shall cooperate with
and assist in the orderly transition of his or her duties, and shall diligently perform such other services reasonably consistent with his or her position as may be
requested from time to time. Executive’s current base salary and annual incentive target shall remain in effect, and Executive (and his or her eligible dependents)
shall also remain eligible to participate in the Company’s applicable employee benefit plans, and shall remain subject to and comply with the Company’s code of
business conduct and other employment policies.]
2. Payment of Accrued Amounts. The Company shall pay to the Executive the portion of his or her annual salary that has accrued but is unpaid
as of the Termination Date and an additional amount representing the Executive’s accrued but unused vacation days as of the Termination Date, in each case not
later than the second payroll date after the Termination Date.
3. Severance Payments. The Company shall pay to the Executive:
(a)
cash severance payments in an aggregate amount equal to $ [2.0 for named executive officers; 1.25 - 2.0 for other officers] times the sum of
(i) $ which is equal to the product of (representing the Executive’s annual base salary) and (ii) $ (representing the Executive’s target annual incentive). For
named executive officers and other “specified employees” within the meaning of section 409A of the Code, payment shall commence in the form of a lump sum
payment of $ to be made as of the first payroll date occurring on or after the date that is six months after the Termination Date, followed by substantially equal
regular payroll installments of the remainder over a period of [eighteen for named executive officers; twelve to eighteen for other officers] months; for other
officers, payment shall commence not later than 45 days after the Termination Date in substantially equal payroll installments over a period of [15 - 24 months];
and
(b)
a pro-rated annual incentive award for [the year in which the Termination Date occurs] based on the number of days elapsed during such
year as of the Termination Date, the amount of which (if any) shall be determined based on business performance measures in a manner consistent with that
applied to active peer executives of Subsidiary (assuming a meaningful impact performance rating) and payable at the time such awards are paid to such
executives (but not later than [March 15 of the following year]), and each such payment shall be considered a separate short-term deferral for purposes of section
409A of the Internal Revenue Code (“Code”).
4. Tax Withholding. The Company shall deduct from the amounts payable to the Executive pursuant to this Agreement the amount of all
required federal, state and local withholding taxes in accordance with the Executive’s Form W-4 on file with the Company and all applicable social security and
Medicare taxes.
5. Outplacement Assistance and Financial Counseling Services. During the twelve-month period following the Termination Date, the Company
shall reimburse the Executive for reasonable fees incurred for services rendered to the Executive by a professional outplacement organization selected by the
Executive and reasonably acceptable to the Company to provide individual outplacement services, and Executive shall be eligible to receive financial counseling
services consistent with the terms and conditions applicable to active peer executives under Exelon’s executive perquisite policy. Executive may apply for
external positions via search firms which also recruit executives for the Company.
6. Long Term Incentive Awards.
(a)
Executive shall remain eligible to receive long-term [performance share awards for generation/business services company executives /or/
performance cash awards for utility executives] under Exelon’s long-term incentive program for the performance cycles commencing in the year in which the
Termination Date occurs and the two preceding years to the extent provided under the terms and conditions of the program in effect at the time of grant, and the
respective payout amounts (if any) of which shall be determined in a manner consistent with that used to determine the amounts of such awards payable to active
executives for such respective periods, and each such award shall be payable at the time or times such respective awards are paid to active executives and
considered a separate, short-term deferral for purposes of section 409A of the Code; and
(b)
Executive’s options to purchase common stock of Exelon granted by the Company shall, to the extent not exercised as of the Termination
Date, remain exercisable until the (i) the earlier of the respective expiration dates of such options and the date that is ninety days after the Termination Date with
respect to merger options other than those granted in 2012 if the Executive has not attained at least age 50 and completed at least 10 years of service, and (ii) until
the respective expiration dates of such options with respect to merger options granted in 2012 and other options if the Executive is at least age 50 and has
completed 10 or more years of service; and
(c)
the non-vested portions of Executive’s [restricted stock unit for generation and business services company executives /or/ restricted cash for
utility executives] awards under Exelon’s long term incentive program in effect on the date of grant shall vest to the extent provided under the terms and
conditions of the program as of the Termination Date [and, with respect to named executive officers and other “specified employees”, payable six months after
the Termination Date].
All such awards payable in shares shall be subject to the Company’s applicable resale restrictions, if any.
7. Supplemental Executive Retirement Benefits. The Executive shall be eligible for a retirement benefit under the Company’s applicable
supplemental non-qualified pension plan, if any (the “SERP”), in accordance with the terms and conditions thereof, except that in determining such benefit, the
Executive shall be subject to the Executive’s timely execution of the Waiver and Release, be credited with [24 months for named executive officers; 15 -24
months for other officers] additional service calculated as though he or she received the severance benefits specified in Section 3(a) as regular salary and
incentive pay over such period (and limited in its application to the amounts of such payments that exceed the compensation limitations applicable to qualified
pension plans under the Code) and any other service previously granted to such Executive. Such benefit shall be paid as provided in Section 8(c).
8. Employee and Other Benefits.
(a) During the period commencing on the Termination Date and ending [24 months for named executive officers; 15 - 24 months for other
officers] after the Termination Date (the “Severance Period”) and in satisfaction of COBRA continuation coverage during such period with respect to healthcare
benefits, (i) the Executive (and his or her participating dependents) shall be eligible to participate in, and shall receive benefits under Exelon’s welfare benefit
plans (including medical, dental and vision) in which the Executive (and his or her eligible dependents) were participating immediately prior to the Termination
Date, and (ii) the Executive shall be eligible to participate in the life insurance programs in which he or she was a participant immediately prior to the
Termination Date, in each case on the same basis as if the Executive had remained actively employed during the Severance Period.
(b)
Following the Severance Period, if the Executive has attained at least age 50 and has completed at least 10 years of service as of the end of
the Severance Period, the Executive (and his or her eligible dependents) shall be eligible for retiree benefits in accordance with and subject to the terms and
conditions of the Company’s applicable health care plans, as in effect for employees of his or her legacy business unit from time to time (including the
Company’s right to amend or terminate such plans at any time). Such benefits shall not duplicate any benefits that may then be available to the Executive from
any other employer and shall be secondary to Medicare.
The Company shall pay to the Executive, in the time and manner specified in the terms and conditions of such plans and any distribution
elections by the Executive in effect thereunder, his or her account balances (if any) under Exelon’s applicable deferred compensation plans, as adjusted by any
applicable earnings and losses on such account balances, and the Executive’s benefit under the supplemental executive retirement plan.
(c)
programs as determined by the Company. The Executive shall be responsible for payment of expenses incurred after the
(d)
The Executive shall be entitled to purchase the laptop computer furnished by the Company for his or her use, subject to removal of data and
Termination Date with respect to the Company-owned cellular phone furnished for his or her use.
(e)
If the Executive is entitled to any benefit under any employee benefit plan of the Company that is accrued and vested on the Termination
Date and that is not expressly referred to in this Agreement, such benefit shall be provided to the Executive in accordance with the terms of such employee
benefit plan.
(f) Notwithstanding Section 8(e) or anything else contained in this Agreement to the contrary, the Executive acknowledges and agrees that he
or she is not and shall not be entitled to benefits under any other severance or change in control plan, program, agreement or arrangement, and that the benefits
provided under this Agreement shall be the sole and exclusive benefits to which the Executive may become entitled upon his or her termination of employment.
In the event the Executive dies prior to executing the Waiver and Release, neither he or she, his or her estate, nor any other person shall be entitled to any further
compensation or benefits under this Agreement, unless and until the executor of the Executive’s estate (and/or such other heirs or representatives as may be
requested by the Company) executes upon Company request and does not revoke such a Waiver and Release.
9. Waiver and Release. Notwithstanding anything herein to the contrary, Executive’s right to the payments and benefits under this Agreement
shall be contingent upon (a) Executive having executed and delivered to the Company a waiver and general release agreement in the form attached hereto (the
“Waiver and Release”) not earlier than the Termination Date but in no event more than 21 days [45 days if a group termination] after the Termination Date (the
“Consideration Period”), (b) Executive not revoking such release in accordance with the terms of the release and (c) Executive not violating any of Executive’s
on-going obligations under this Agreement; provided, however, that the Company has the discretion to pay such benefits prior to receipt of the Waiver and
Release and/or the expiration of the revocation period; provided further that if Executive does not execute and deliver the Waiver and Release to the
Company prior to the expiration of the Consideration Period or if the Executive revokes the Waiver and Release in accordance with its terms, Executive shall pay
to the Company within 10 days following the expiration of the Consideration Period or the date such release was revoked, a lump sum payment of all payments
received by Executive to date hereunder.
10. Restrictive Covenants. The Executive acknowledges and agrees that he or she is bound by, and subject to, the Non-Solicitation and
Confidentiality Agreement dated as of (the “Restrictive Covenants”) and the
Waiver and Release. The Executive shall comply with, and observe, the Restrictive Covenants including, without limitation, the confidential information, non-
solicitation and intellectual property provisions and related covenants contained therein, all of which are hereby incorporated by reference. In the event that
Executive has breached any of the Restrictive Covenants or the Waiver and Release or has engaged in conduct during his or her employment with the Company
that would constitute grounds for termination for Cause (as defined in the Exelon Corporation Senior Management Severance Plan), benefits under this
Agreement shall terminate immediately, and Executive shall reimburse Exelon for any benefits received.
11. Certain Tax Matters.
(a)
If it is determined by Exelon’s independent auditors that any severance payment, benefit or enhancement provided to the Executive
pursuant to the terms of the this Agreement is or will become subject to any excise tax under section 4999 of the Code, or any similar tax payable under any
United States federal, state, local, foreign or other law (“Excise Taxes”), then such payment, benefit or enhancement shall be reduced to the largest amount which
would not cause any such Excise Tax to by payable be the Executive and not cause a loss of the related income tax deduction by the Company.
(b)
The parties intend for this Agreement to comply with section 409A of the Code. In the event the timing of any payment or benefit under
this Agreement would result in any tax or penalty under section 409A of the Code, the Company may reasonably adjust the timing of such payment or benefit if
doing so will eliminate or materially reduce such tax or penalty and amend this Agreement accordingly. Executive acknowledges that Executive has been advised
to consult Executive’s personal tax advisor concerning this Agreement, and has not relied on the Company for tax advice.
12.
Non-disparagement. The Executive shall not publish, comment upon or disseminate any public statements suggesting or accusing the
Company or any of its affiliates, employees, officers, directors or agents of any misconduct or unlawful behavior, or that brings the Company or any of its
affiliates or the employees, officers, directors or agents of the Company or any of its affiliates into disrepute, or tarnish any of their images or reputations. The
provisions of this Section 12 shall not apply to truthful testimony as a witness, compliance with other legal obligations, assertion of or defense against any claim
of breach of this Agreement, or any activity that otherwise may be required or permitted by the lawful order of a court or agency of competent jurisdiction, and
shall not require the Executive to make false statements or disclosures.
13.
Publicity. Executive shall not issue or cause the publication of any press release or other announcement with respect to the terms or
provisions of this Agreement, nor disclose the contents hereof to any third party (other than to members of his or her immediate family or to tax, financial and
legal advisors), without obtaining the consent of Exelon, except where such release, announcement or disclosure shall be required by applicable law or
administrative regulation or agency or other legal process.
14.
Other Employment; Other Plans. The Executive shall not be obligated to seek other employment or take any other action by way of
mitigation of the amounts payable to the Executive under any provision of this Agreement. The amounts payable hereunder shall not be reduced by any payments
received by the Executive from any other employer; provided, however, that any continued welfare benefits provided for by Section 8(a) shall not duplicate any
benefits that are provided to the Executive and his or her family by such other employer and shall be secondary to any coverage provided by Medicare.
15.
Cooperation by the Executive. During the Severance Period, the Executive shall (a) be reasonably available to the Company to respond to
requests by them for information pertaining to or relating to matters which may be within the knowledge of the Executive and (b) cooperate with the Company in
connection with any existing or future litigation or other proceedings brought by or against the Company, its subsidiaries or affiliates, to the extent Exelon
reasonably deems the Executive's cooperation necessary, including truthful testimony in any related proceeding.
16.
Successors; Binding Agreement. This Agreement shall inure to the benefit of and be binding upon the Company and its successors, and by
the Executive, his or her spouse, personal or legal representatives, executors, administrators and heirs. This Agreement, being personal, may not be assigned by
Executive.
17.
Governing Law; Validity. This Agreement shall be interpreted, construed and enforced in accordance with the terms of the Exelon
Corporation Senior Management Severance Plan, and the applicable provisions of the Employee Retirement Income Security Act of 1974, as amended
(“ERISA”) and section 409A of the Code.
Entire Agreement. This Agreement and the Waiver and Release constitute the entire agreement and understanding between the parties with
respect to the subject matter hereof and supersede and preempt any other understandings, agreements or representations by or between the parties, written or oral,
which may have related in any
18.
manner to the subject matter hereof. Executive acknowledges that the Company has made no representations regarding the tax consequences of payments under
this Agreement and has had the opportunity to consult Executive’s tax advisor.
together shall constitute one and the same instrument.
19.
Counterparts. This Agreement may be executed in two counterparts, each of which shall be deemed to be an original and both of which
20. Miscellaneous. No provision of this Agreement may be modified or waived unless such modification or
waiver is agreed to in writing and executed by the Executive and by a duly authorized officer of the Company. No waiver by either party hereto at any time of
any breach by the other party hereto of, or compliance with, any condition or provision of this Agreement to be performed by such other party shall be deemed a
waiver of similar or dissimilar provisions or conditions at the same or at any prior or subsequent time. Failure by the Executive or the Company to insist upon
strict compliance with any provision of this Agreement or to assert any right which the Executive or the Company may have hereunder shall not be deemed
to be a waiver of such provision or right or any other provision or right of this Agreement.
21.
Beneficiary. If the Executive dies prior to receiving all of the amounts payable hereunder (other than amounts payable under any plan
referenced in Section 8, which shall be governed by any beneficiary designation in effect thereunder) but after executing the Waiver and Release, such amounts
shall be paid, except as may be otherwise expressly provided herein or in the applicable plans, to the beneficiary (“Beneficiary”) designated with respect to this
Agreement by the Executive in writing to the Vice President, Corporate Compensation of the Company during his or her lifetime, which the Executive may
change from time to time by new designation filed in like manner without the consent of any Beneficiary; or if no such Beneficiary is designated, to his or her
surviving spouse, and if there be none, to his or her estate.
22.
Nonalienation of Benefits. Benefits payable under this Agreement shall not be subject in any manner to anticipation, alienation, sale,
transfer, assignment, pledge, encumbrance, charge, prior to actually being received by the Executive, and any such attempt to dispose of any right to benefits
payable hereunder shall be void.
23.
Severability. If all or any part of this Agreement is declared by any court or governmental authority to be unlawful or invalid, such
unlawfulness or invalidity shall not serve to invalidate any portion of this Agreement not declared to be unlawful or invalid, except that in the event a
determination is made that the Restrictive Covenants as applied to the Executive are invalid or unenforceable in whole or in part, then this Agreement shall be
void and the Company shall have no obligation to provide benefits hereunder. Any paragraph or part of a paragraph so declared to be unlawful or invalid shall, if
possible, be construed in a manner which will give effect to the terms of such paragraph or part of a paragraph to the fullest extent possible while remaining
lawful and valid.
24.
Communications. Nothing in this Agreement or the Waiver and Release shall be construed to prohibit or limit the Executive from filing a
charge with, or reporting possible violations of law or regulation to any governmental agency or entity, including but not limited to the National Labor Relations
Board, Nuclear Regulatory Commission, U.S. Equal Opportunity Commission, the Department of Labor, the Department of Justice, the Securities Exchange
Commission, the Congress, and any agency Inspector General, or making other disclosures that are protected under the whistleblower provisions of applicable
law or regulation, or taking any other action protected under section 211 of the Energy Reorganization Act. The Executive does not need the prior authorization
of the Company to make any such charges, reports or disclosures, and is not required to notify the Company that Executive has made such charges reports or
disclosures, and no such report or disclosure shall be considered a violation of Section 12 of this Agreement or the Waiver and Release. In addition, neither this
Agreement nor the Waiver and Release limits the Executive’s ability to receive a monetary award from a government-administered whistleblower award program
for providing any such reports or disclosures directly to a governmental agency. Executive acknowledges, however, that the Waiver and Release requires
Executive to specifically waive all rights to recover any monetary damages from the Company, including but not limited to lost wages and benefits, lost pay,
damages for emotional distress, punitive damages, reinstatement, and attorneys’ fees and costs.
25.
Sections. Except where otherwise indicated by the context, any reference to a “Section” shall be to a Section of this Agreement.
IN WITNESS WHEREOF, Exelon and Subsidiary have caused this Agreement to be executed by their duly authorized officers and the Executive has executed
this Agreement as of the day and year first above written.
EXELON CORPORATION
By:
Senior Vice President &
Chief Human Resource Officer
SUBSIDIARY
By:
Vice President, Human Resources
EXECUTIVE
WAIVER AND RELEASE UNDER
SEPARATION AGREEMENT
In consideration for the Executive’s receiving severance benefits under the Separation Agreement (as defined below), (the “Executive”) hereby agrees as follows:
1. Release. Except with respect to the Company’s obligations under the Separation Agreement by and between Exelon Corporation, [Executive’s
employing subsidiary] (collectively, the “Company”) and the Executive dated as of “Separation Agreement”), the Executive, on behalf of Executive and his or
her heirs, executors, assigns, agents, legal representatives and personal representatives, hereby releases, acquits and forever discharges the Company, its agents, ,
20 (the subsidiaries, affiliates, and their respective officers, directors, agents, servants, employees, attorneys, shareholders, successors, assigns and affiliates, of
and from any and all claims, liabilities, demands, causes of action, costs, expenses, attorneys fees, damages, indemnities and obligations of every kind and nature,
in law, equity, or otherwise, known and unknown, foreseen or unforeseen, disclosed and undisclosed, suspected and unsuspected, arising out of or in any way
related to agreements, events, acts or conduct at any time prior to the day of execution of this Waiver and Release, including but not limited to any and all such
claims and demands directly or indirectly arising out of or in any way connected with the Executive’s employment or other service with the Company, or any of
its Subsidiaries or affiliates; the Executive’s termination of employment and other service with the Company or any of its subsidiaries or affiliates; claims or
demands related to salary, bonuses, commissions, stock, stock options, restricted stock or any other ownership interests in the Company or any of its subsidiaries
and affiliates, vacation pay, fringe benefits, expense reimbursements, sabbatical benefits, severance, change in control or other separation benefits, or any other
form of compensation or equity; and claims pursuant to any federal, state, local law, statute, ordinance, common law or other cause of action including but not
limited to, the federal Civil Rights Act of 1964, as amended; the federal Age Discrimination in Employment Act of 1967, as amended; the federal Americans
with Disabilities Act of 1990; the Employee Retirement Income Security Act of 1974, as amended, tort law; contract law; wrongful discharge; discrimination;
fraud; defamation; harassment; emotional distress; or breach of the covenant of good faith and fair dealing. This Waiver and Release does not apply to (a) the
payment of any benefits to which the Executive may be entitled under the terms of a Company-sponsored tax qualified retirement or savings plan or (b)
Executive’s entitlement to indemnification, and coverage as an insured, with respect to his service as an officer, director, employee or agent in accordance with
the terms and conditions of Article VII of the Exelon Corporation Amended and Restated Bylaws.
2. No Inducement. The Executive agrees that no promise or inducement to enter into this Waiver or Release has been offered or made except as set forth
in this Waiver and Release and the Separation Agreement, that the Executive is entering into this Waiver and Release without any threat or coercion and without
reliance on any statement or representation made on behalf of the Company or any of its subsidiaries or affiliates, or by any person employed by or representing
the Company or any of its subsidiaries or affiliates, except for the written provisions and promises contained in this Waiver and Release and the Separation
Agreement.
3. Advice of Counsel; Time to Consider; Revocation. The Executive acknowledges the following:
(a) The Executive has read this Waiver and Release, and understands its legal and binding effect, including that by signing and not revoking
this Waiver and Release the Executive waives and releases any and all claims under the Age Discrimination in Employment Act of 1967, as amended,
including but not limited to the Older Workers Benefits Protection Act. The Executive is acting voluntarily and of the Executive’s own free will in
executing this Waiver and Release.
(b) The Executive has been advised to seek and has had the opportunity to seek legal counsel in connection with this Waiver and Release.
(c) The Executive was given at least [twenty-one (21) / forty-five (45)] days to consider the terms of this Waiver and Release before signing it.
(d) At the time Executive was given this Waiver and Release, Executive was informed that his or her termination was not part of a group
separation.
The Executive understands that, if the Executive signs the Waiver and Release, the Executive may revoke it within seven (7) days after signing it,
provided that Executive will not receive any severance benefits under the Separation Agreement. The Executive understands that this Waiver and
Release will not be effective until after the seven-day period has expired and no consideration will be due the Executive.
4. Severability. If all or any part of this Waiver and Release is declared by any court or governmental authority to be unlawful or invalid, such
unlawfulness or invalidity shall not invalidate any other portion of this Waiver and Release. Any Section or a part of a Section declared to be unlawful or invalid
shall, if possible, be construed in a manner which will give effect to the terms of the Section to the fullest extent possible while remaining lawful and valid.
5. Amendment. This Waiver and Release shall not be altered, amended, or modified except by written instrument executed by the Company and the
Executive. A waiver of any portion of this Waiver and Release shall not be deemed a waiver of any other portion of this Waiver and Release.
6. Applicable Law. The provisions of this Waiver and Release shall be interpreted and construed in accordance with the laws of the State of Illinois
without regard to its choice of law principles.
IN WITNESS WHEREOF, the Executive has executed this Waiver and Release as of the date specified below.
DATE: ____________________________________________________ EXECUTIVE ________________________________
EXELON CORPORATION
LONG-TERM INCENTIVE PROGRAM
(As in effect as of January 1, 2020)
1.
Purpose. The purpose of this Exelon Corporation Long-Term Incentive Program (the “Program”) is to set
forth certain provisions which shall be deemed a part of, and govern, equity compensation awards granted by Exelon Corporation, a
Pennsylvania corporation (the "Company"), on or after January 1, 2011 to executives, key managers and other select management
employees pursuant to the Exelon Corporation 2011 Long-Term Incentive Plan, as amended (the "Plan").
2. Certain Definitions.
Except as otherwise set forth herein, the defined terms used in this Program shall have the meanings set forth below
or in the Plan.
1
(a) “Administrator” shall have the meaning set forth in Section 14 below.
(b) “Award” shall mean an award granted under this Program.
(c) “Award Notice” shall mean a notice of a Participant’s Award, issued by the Company in written or
electronic form, which shall set forth the type of the Award, the number of shares or amount of cash (or target share or cash
opportunity that, together with the Program summary, sets forth the number of shares or amount of cash) of Common Stock
subject to such Award and any other terms of the Award not set forth in the Plan, this Program or the Program summary.
(d) “Board” shall mean the board of directors of the Company.
(e) “Transition Award” shall mean a Performance Share Unit Award granted on a one-time basis in 2013 (or
2014, in certain cases such as new hires, promotions or transfers) in order to transition from a one-year Performance Cycle to a
three-year Performance Cycle.
(f) “Committee” shall mean the compensation and leadership development committee of the Board.
(g) “Dividend Payment Date” shall mean each date on which the Company pays a regular cash dividend to
record owners of shares of Common Stock.
(h) “Earned Cash” shall be the dollar amount of cash subject to a Performance Cash Unit Award that have been
earned based on the achievement of the performance goals for the applicable Performance Cycle).
(i) “Earned Shares” shall mean shares of Common Stock (or cash representing shares, as applicable) subject to
a Performance Share Unit Award that have been earned based on the achie vement of the performance goals for the applicable
Performance Cycle (or portion thereof, in the case of Transition Awards).
(j) “Effective Date” shall mean January 1, 2011.
(k) “First Tranche” shall mean one-third of the Performance Share Units granted under a Transition Award.
2
(l) “Grant Date” shall mean the date on which an Award is granted, as set forth in the applicable Award Notice
(m) “LTPP” means a long-term performance program award, which is a Restricted Cash Award subject to a
performance condition or conditions in addition to a vesting requirement, and which is granted to key managers and executives
below the level of Senior Vice President of a Utility.
(n) “Option” shall mean a nonqualified option to purchase shares of Common Stock upon and subject to the
satisfaction of the vesting conditions set forth in Section 5 of this Program.
(o) “Participant” shall mean the recipient of an Award granted under this Program.
(p) “Performance Cycle” shall mean (A) for Performance Share Unit Awards granted prior to January 1, 2013,
the one-year period beginning on January 1 of the year in which the Award is granted (and any applicable look-back period),
(B) for the Transition Awards, the two-year period beginning on January 1, 2013 and (C) for Performance Share Unit Awards
granted on or after January 1, 2013 (other than Transition Awards) and Performance Cash Awards granted on or after January 1,
2014, the three-year period beginning on January 1of the year in which the Performance Share Unit Award is granted.
(q) “Performance Cash Unit” shall mean a right granted to a Participant employed in a Utility Company to
receive an amount of cash subject to the achievement of the applicable performance goals and the satisfaction of the vesting
conditions set forth in Section 3 of this Program.
(r) “Performance Share Unit” shall mean a right to receive shares of Common Stock or a cash equivalent (as
applicable) subject to the achievement of the applicable performance goals and the satisfaction of the vesting conditions set
forth in Section 3 of this Program.
(s) “Restricted Cash Award” shall mean a right to receive an amount in cash upon and subject to the
satisfaction of the vesting conditions set forth in Section 4 of this Program, which is granted to key managers of business units
other than a Utility.
(t) “Restricted Stock Unit” shall mean a right to receive shares of Common Stock upon and subject to the
satisfaction of the vesting conditions set forth in Section 4 of this Program.
(u) “Restrictive Covenants” shall mean any noncompetition, nonsolicitation, confidentiality, intellectual
property or other restrictive covenants to which a Participant is subject, required as a condition to receipt of an Award, or which
is contained in any other agreement between the Participant and the Company or any of its affiliates.
3
(v) “Retirement” shall mean a Participant’s termination of employment (other than a termination upon death,
disability or involuntary termination for cause) on or after the date as of which the Participant has attained age 55 (age 50 with
respect to Awards granted prior to January 1, 2013) and completed at least ten years of service with the Company and the
Subsidiaries. For purposes of this definition, the holder’s age and service shall be determined taking into account any deemed
age or service awarded to the holder for benefit accrual purposes under any nonqualified defined benefit retirement plan of the
Company in which the holder is a participant.
(w) “Second Tranche” shall mean two-thirds of the Performance Share Units granted under a Transition Award
(x) “Utility Company” shall mean Baltimore Gas & Electric Company, Commonwealth Edison Company,
PECO Energy Company, Pepco Holdings Company, and the Exelon Utility Group (which may include Transmission
Operations) within Exelon Business Services Company, LLC.
3. Long Term Performance Share Award and Performance Cash Award Program.
(a) Granting of Awards. Within the first 90 days (or later, with respect to a new hire or promotion) of each
Performance Cycle beginning on or after the Effective Date, the Committee may grant Performance Share Unit Awards to
employees who are employed in a Vice President or more senior position, including without limitation Nuclear Plant Managers,
as selected by the Committee in its sole discretion. Effective January 1, 2014, the Committee may grant Performance Cash Units
in lieu of Performance Share Unit Awards to such designated employees who are employed in a Utility Company. Performance
Share Unit Awards and Performance Cash Unit Awards shall be subject to the respective applicable terms and conditions set
forth in this Section 3, and shall contain such additional terms and conditions, not inconsistent with the terms of this Program, as
the Committee shall deem advisable and set forth in the applicable Program summary or Award Notice.
(b) Number of Shares (or Amount of Cash) and Other Terms. The number of shares of Common Stock
represented by a Performance Share Unit Award, and the amount of cash represented by a Performance Cash Award, for any
Performance Cycle shall be determined based on the achievement of performance goals established by the Committee and set
forth in the Program summary for such Performance Cycle and the administrative guidelines approved by the Committee. Each
performance goal shall be assigned a weighting and scored at the end of each calendar year within the Performance Cycle. For
Performance Cycles beginning on or after January 1, 2013, at the end of the Performance Cycle, the number of Earned Shares
(or the amount of Earned Cash) is determined based on the annual performance results determined by the Committee, subject to
adjustment as set forth in the Program summary and/or administrative guidelines. Notwithstanding the foregoing, the maximum
number of shares of Common Stock that may
4
become subject to Performance Share Unit Awards and Performance Cash Awards granted in any calendar year beginning prior
to January 1, 2019 to Participants the Company has determined as of the Grant Date may be “covered employees” (within the
meaning of Section 162(m)(3) of the Code) for such year or for any subsequent year in which such Award may be outstanding,
shall be equal to the lesser of (i) the number determined by (A) multiplying 1.5% of the Company’s Operating Income for such
year by the allocation percentage approved by Committee for such Participant within the first 90 days of the applicable
Performance Cycle and (B) dividing such dollar amount by the closing price of a share of Common Stock on the last trading day
of such year and (ii) the per person limit set forth in Section 1.6 of the Plan. For purposes of this Section 3(b), the “Operating
Income” of the Company for such year shall be as reported in the Company’s financial statements for such year according to
generally accepted accounting principles and as reviewed or accepted, as the case may be, by the Company’s independent public
accountants, and certified by the Committee in accordance with section 162(m) of the Code. The Committee reserves the right
in its sole discretion to determine that the number of Earned Shares for any Performance Cycle shall be zero in the event of
materially adverse business or financial circumstances as determined by the Committee.
(c) Vesting and Forfeiture.
(i)Awards Granted prior to January 1, 2013. Except as provided in Section 3(f)(i) of the Program, Earned Shares
granted prior to January 1, 2013 shall become vested (i) on the date of the first regular meeting of the
Committee held in the calendar year following the calendar year in which the Grant Date occurs with
respect to one-third of the number of Earned Shares, (ii) on the date of the first regular meeting of the
Committee held in the second calendar year following the calendar in which the Grant Date occurs with
respect to an additional one-third of the number of Earned Shares, and (iii) on the date of the first regular
meeting of the Committee held in the third calendar year following the calendar year in which the Grant
Date occurs with respect to the remaining Earned Shares (but, with respect to each such year, not later than
March 15), in each case subject to the Participant’s continuous employment with the Company through the
applicable vesting date.
(ii)Transition Awards. Except as provided in Section 3(f)(ii) of the Program, Performance Share Units subject to a
Transition Award shall be earned and become vested (i) with respect to the First Tranche, on the date of the
first regular meeting of the Committee held in 2014 and (ii) with respect to the Second Tranche, on the date
of the first regular meeting of the Committee held in 2015 (but, with respect to each such year, not later
than March 15), in each case subject to the Participant’s continuous employment with the Company
through the applicable vesting date.
5
(iii)Awards Granted on or after January 1, 2013 (Other than Transition Awards). Except as provided in Section 3(f)
(ii) of the Program, Performance Share Units and Performance Cash Units subject to an Award (other than
a Transition Award) and granted on or after January 1, 2013 shall be earned and become fully vested on
the date of the first regular meeting of the Committee held in the third calendar year following the calendar
year in which the Grant Date occurs (but, with respect to each such Performance Cycle, not later than
March 15 of such year), in each case subject to the Participant’s continuous employment with the
Company through the applicable vesting date.
(d) Dividend Equivalents. As of each Dividend Payment Date, the Company shall pay to the Participant a cash
payment (or, in the discretion of the Committee, reinvest in additional shares subject to such Award) in an amount equal to the
dollar amount of the cash dividend paid per share of Common Stock multiplied by the number of Earned Shares (if any) that are
subject to a Performance Share Unit Award immediately prior to the record date for such Dividend Payment Date, but that have
not been issued pursuant to Section 3(e) as of such record date.
(e) Settlement of Vested Awards. Subject to the withholding of taxes pursuant to Section 8 of the Program,
within 45 days after the vesting of a Performance Share Unit Award, in whole or in part (or at such later time as may be required
pursuant to this Section 3(e)), the Company shall issue or transfer to the Participant the number of Earned Shares that have
become vested. The Company may effect such transfer either by the delivery of one or more certificates of Common Stock to
the Participant or by an appropriate entry on the books of the Company or of a duly authorized transfer agent of the Company,
and in either case by issuing such shares in the Participant’s name or in such other name as is acceptable to the Company and
designated in writing by the Participant. All such Awards payable for 2012 or thereafter shall be paid 50% in Common Stock
and 50% in cash; provided, however, that effective for Awards granted on or after January 1, 2013 (including Transition
Awards), a Participant whose title is Executive Vice President or above and who has achieved 200% or more of his or her stock
ownership target by September 30 of the calendar year prior to payout of the Award shall be paid in cash. The Company shall
pay all original issue or transfer taxes and all fees and expenses incident to such delivery, except as otherwise provided in
Section 8 of the Program. Prior to the settlement of a Performance Share Unit Award, the holder of such Award shall have no
rights as a stockholder of the Company with respect to the shares of Common Stock subject to such Award. Performance Cash
Unit Awards shall be paid in cash within 45 days after vesting. Notwithstanding the foregoing, if a Participant is a “Specified
Employee,” within the meaning of section 409A of the Code, and such Participant is or will become eligible for Retirement
prior to the calendar year in which the Performance Share Unit Award is scheduled to become fully vested, then any Earned
Shares subject to the Award or payment under a Performance Cash Unit which become vested upon the Participant’s
termination of employment in accordance with Section 3(f) of this Program shall be issued to the
6
Participant as of the earlier to occur of the six-month anniversary of such Participant’s separation from service or the date of the
Participant’s death.
(f) Termination of Employment. Except as otherwise provided in this Program or the Plan:
(i)Retirement, Disability, Death or Involuntary Termination Without Cause – Awards Granted prior to January 1,
2013 and prior to January 1, 2020. If a Participant’s employment with the Company terminates by reason of
Retirement, Disability, death or an involuntary termination of employment by the Company for a reason
other than Cause, and such Participant has not breached his or her obligations to the Company or any of its
affiliates under any Restrictive Covenant, then all Earned Shares subject to such Participant’s Performance
Share Unit Award and earned cash subject to a Performance Cash Unit shall become fully vested as of the
effective date of the Participant’s termination of employment or date of death, as the case may be. To the
extent the Award has not been earned as of the date of the Participant’s termination of employment or death
(i.e. as to which the current Performance Cycle has not elapsed), the Participant shall become vested in a
pro-rated Award based on the number of elapsed days in the current Performance Cycle as of the
termination date (or fully vested with respect to such an Award for 2012 upon an involuntary termination
without Cause) and the extent to which the Company performance goals established under the Program for
such Performance Cycle are attained as of the last day of the year in which the termination date occurs, and
such Award shall be payable as of the date Awards for such Performance Cycle are payable to Participants
who remain actively employed with the Company.
(ii)Retirement, Disability, Death or Involuntary Termination Without Cause – Awards Granted on or after January 1,
2013 (Including Transition Awards) and prior to January 1, 2020. If a Participant’s employment with the
Company terminates by reason of Retirement, Disability, death or an involuntary termination of
employment by the Company for a reason other than Cause (subject to timely execution of a waiver and
release provided by the Company), and such Participant has not breached his or her obligations to the
Company or any of its affiliates under any Restrictive Covenant, then (A) if such event occurs within the
first 12 months of the Performance Cycle, then the Participant shall earn and become vested in a pro-rated
Award based on the number of elapsed days in such 12-month period as of the termination date (pro-ration
determined by dividing the number of elapsed days by 365) and the extent to which the performance goals
established under the Program for such Performance Cycle (or portion thereof, in the case of the Transition
Awards) are attained, and (B) if such event occurs after the first 12 months of the Performance Cycle,
7
then the Participant shall become fully vested in all Earned Shares (the number determined in accordance with
Section 3(b) above) or earned cash, as applicable. In either event, the Earned Shares or cash shall be payable
on the payout date applicable to Participants who remain actively employed with the Company.
(iii)Retirement, Disability or Death or Involuntary Termination Without Cause – Awards granted on or after January
1, 2020.
(A) If a Participant’s employment with the Company terminates by reason of Retirement, Disability or Death,
and such Participant has not breached his or her obligations to the Company or any of its affiliates under any
Restrictive Covenant, then (I) if such event occurs within the first 12 months of the Performance Cycle, then
the Participant shall earn and become vested in a pro-rated Award based on the number of elapsed days in
such 12-month period as of the termination date and the extent to which the performance goals established
under the Program for such Performance Cycle are attained and (II) if such event occurs after the first 12
months of the Performance Cycle, then the Participant shall become fully vested in all Earned Shares (the
number determined in accordance with Section 3(b) above) or earned cash, as applicable; and
(B) If a Participant’s employment with the Company terminates by reason of involuntary separation without
Cause, and such Participant has not breached his or her obligations to the Company or any of its affiliates
under any Restrictive Covenant, then, subject to such Participant’s timely execution of a waiver and release
provided by the Company, the Participant shall earn and become vested in a pro-rated Award based on the
number of elapsed days in such 36-month period as of the termination date and the extent to which the
performance goals established under the Program for such Performance Cycle are attained. In either event, the
Earned Shares or Earned Cash shall be payable on the next payout date applicable to Participants who remain
actively employed with the Company.
(iv)Termination for Other Reasons. If a Participant’s employment with the Company terminates for any reason other
than as described in clause (i), (ii) or (iii) of this Section 3(f) or if the Participant has breached his or her
obligations to the Company or any of its affiliates under any Restrictive Covenant or waiver and release,
the unvested portion of such Participant’s Award shall be forfeited and terminate as of the date of such
termination of employment.
(g) Restriction on Sale of Shares by Senior Officers. Shares of Common Stock issued under an Award pursuant
to Section 3(e) to a Participant who is employed as of the Grant Date in a position of, or more senior than, Senior Vice President
8
may not be sold or transferred by such Participant until the earlier to occur of (i) the date as of which the final third of such
Award is scheduled to become vested pursuant to Section 3(c) (even if such Award actually vests earlier pursuant to Section
3(f)) or (ii) the date of the Participant’s death, regardless of when such shares are issued or transferred to such Participant.
Effective January 1, 2013, this provision shall no longer be effective.
(h) Awards Granted to Employees of Commonwealth Edison Company Prior to 2014. If Performance Share
Unit Awards are granted to Participants who are employed by Commonwealth Edison Company, an Illinois corporation and
subsidiary of the Company (“ComEd”), then unless the Committee determines otherwise, (i) the number of such Participant’s
Earned Shares shall be determined based on the achievement of performance criteria established by the Board of Directors of
ComEd and ratified by the Committee, subject to the maximum number of Earned Shares that may be subject to a Performance
Share Unit Award, as set forth in Section 3(b), and (ii) such Performance Share Unit Awards for 2011 shall be settled (subject to
the vesting and other conditions herein) in a cash payment made by ComEd to the Participant in an amount equal to the Fair
Market Value of the number of such Participant’s Earned Shares, determined as of the applicable vesting date.
9
4. Restricted Stock Unit, Restricted Cash and Long-Term Performance Program Awards, and Constellation Short-
Term Incentives and Commissions Payable as Restricted Stock Units.
(a) Granting of Awards. The Committee may grant Restricted Stock Unit, Restricted Cash and LTPP Awards
to employees who are employed (i) in a Vice President or other executive position (including without limitation Nuclear Plant
Managers) and (ii) key managers and other select management employees, in each case as selected by the Committee in its sole
discretion and as provided herein.
(b) Terms of Awards. Awards shall be subject to the following terms and conditions and shall contain such
additional terms and conditions, not inconsistent with the terms of this Program, as the Committee shall deem advisable and set
forth in the applicable Award Notice.
(c) Number of Shares and Other Terms. The number of shares of Common Stock subject to a Restricted Stock
Unit Award, or the amount of cash subject to a Restricted Cash or LTPP Award, shall be determined by the Committee and set
forth in the applicable Program summary or Award Notice (which may reference a number of shares or cash value).
(d) Vesting and Forfeiture. Except to the extent an Award becomes immediately vested upon a termination of
the Participant’s employment pursuant to Section 4(g) of the Program, the shares subject to a Restricted Stock Unit Award or
the amount of cash subject to a Restricted Cash or LTPP Award, shall become vested (i) on the date of the first regular meeting
of the Committee in the calendar year following the calendar year in which the Grant Date occurs with respect to one-third of
the number of shares of Common Stock or amount of cash subject to the Award on the Grant Date, (ii) on the date of the first
regular meeting of the Committee in the second calendar year following the calendar year in which the Grant Date occurs with
respect to an additional one-third of the number of shares of Common Stock or amount of cash subject to the Award on the
Grant Date, and (iii) on the date of the first regular meeting of the Committee in the third calendar year following the calendar
year in which the Grant Date occurs with respect to the remaining shares of Common Stock or amount subject to the Award on
the Grant Date (but, with respect to each such year, not later than March 15), in each case subject to the Participant’s continuous
employment with the Company through the applicable vesting date and, in the case of an LTPP Award, achievement of
applicable performance goals.
(e) Dividend Equivalents. As of each Dividend Payment Date, the number of shares of Common Stock that are
subject to a Restricted Stock Unit Award shall be increased by (i) the product of the total number of shares of Common Stock
that are subject to such Restricted Stock Unit Award immediately prior to the record date for such Dividend Payment Date, but
that have not been issued pursuant to Section 4(f) as of such record date, multiplied by the dollar amount of the cash dividend
paid per share of Common Stock, divided by (ii) the Fair Market Value of a share of Common Stock on such Dividend
10
Payment Date. Such additional Restricted Stock Units shall be subject to all of the terms and conditions of the Award, including
the vesting conditions set forth in Section 4(d).
(f) Settlement of Vested Awards. Subject to the withholding of taxes pursuant to Section 8 of the Program,
within 45 days after the vesting of a Restricted Stock Unit Award, in whole or in part (or at such later time as may be required
pursuant to this Section 4(f)), the Company shall issue or transfer to the Participant the number of shares of Common Stock that
have become vested. The Company may effect such transfer either by the delivery of one or more certificates of Common Stock
to the Participant or by an appropriate entry on the books of the Company or of a duly authorized transfer agent of the
Company, and in either case by issuing such shares in the Participant’s name or in such other name as is acceptable to the
Company and designated in writing by the Participant. The Company shall pay all original issue or transfer taxes and all fees
and expenses incident to such delivery, except as otherwise provided in Section 8 of the Program. Prior to the settlement of a
Restricted Stock Unit Award, the holder of such Award shall have no rights as a stockholder of the Company with respect to the
shares of Common Stock subject to such Award. Notwithstanding the foregoing, if a Participant is a “Specified Employee,”
within the meaning of section 409A of the Code, and such Participant is or will become eligible for Retirement prior to the
calendar year in which the Restricted Stock Unit Award is scheduled to become fully vested, then any shares of Common Stock
subject to the Award which become vested upon the Participant’s termination of employment in accordance with Section 4(g) of
this Program shall be issued to the Participant as of the earlier to occur of the six-month anniversary of such Participant’s
separation from service or the date of the Participant’s death.
(g) Termination of Employment. Except as otherwise provided in this Program or the Plan:
(i)Retirement, Disability or Death. If a Participant’s employment with the Company terminates by reason of
Retirement, Disability or death, and such Participant has not breached his or her obligations to the Company
or any of its affiliates under any Restrictive Covenant, then all shares or cash subject to such Participant’s
Award shall become fully vested as of the effective date of the Participant’s termination of employment or
date of death, as the case may be.
(ii)Termination for Other Reasons. If a Participant’s employment with the Company terminates for any reason other
than as described in clause (i) of this Section 4(g) or the Participant’s breach of his or her obligations to the
Company or any of its affiliates under any Restrictive Covenant, then, subject to the Participant’s timely
execution of a waiver and release provided by the Company, the unvested portion of such Participant’s
Award granted prior to January 1, 2020 shall become fully vested upon an involuntary termination without
Cause, and an Award granted on or after January 1, 2020 shall become vested in the aggregate (if at all) on
a pro-
11
rated basis (taking into account for this purpose any portion of the Award which previously became vested)
based on the number of shares (plus any reinvested dividends) or amount of cash originally subject to such
Award and the number of elapsed days in a 36-month period from January 1 of the year of the grant date.
12
5. Stock Option Award Program.
(a) Granting of Awards. The Committee may grant Option Awards to employees who are employed in a Senior
Vice President or more senior position, as selected by the Committee in its sole discretion or, to the extent permitted by the Plan,
the Chief Executive Officer of the Company.
(b) Terms of Awards. Awards shall be subject to the following terms and conditions and shall contain such
additional terms and conditions, not inconsistent with the terms of this Program, as the Committee shall deem advisable and set
forth in the applicable Award Notice.
(c) Number of Shares. The number of shares of Common Stock subject to an Option Award shall be
determined by the Committee and set forth in the applicable Award Notice.
(d) Term of Option. Except to the extent earlier terminated or exercised, each Option shall expire on, and in no
event may any portion of such Option be exercised after, the tenth anniversary of the Grant Date (the “Expiration Date”).
(e) Vesting and Forfeiture. Except to the extent the Award becomes immediately vested upon a termination of the
Participant’s employment pursuant to Section 5(g) of the Program, the Option shall become vested and exercisable (i) on the first
anniversary of the Grant Date with respect to one-fourth of the number of shares of Common Stock subject to the Award on the
Grant Date, (ii) on the second anniversary of the Grant Date with respect to an additional one-fourth of the number of shares of
Common Stock subject to the Award on the Grant Date (iii) on the third anniversary of the Grant Date with respect to an additional
one-fourth of the number of shares of Common Stock subject to the Award on the Grant Date, and (iv) on the fourth anniversary of
the Grant Date with respect to the remaining shares of Common Stock subject to the award on the Grant Date, in each case subject to
the Participant’s continuous employment with the Company through the applicable vesting date.
(f) Method of Exercise. To the extent permitted by the Administrator, a Participant may exercise an Option (i) by
giving written notice to the Company (or its designated agent) specifying the number of whole shares of Common Stock to be
purchased and accompanying such notice with payment therefor in full, and without any extension of credit, either (A) in cash, (B)
by delivery (either actual delivery or by attestation procedures established by the Company) to the Company of previously owned
whole shares of Common Stock having a Fair Market Value, determined as of the date of exercise, equal to the aggregate purchase
price payable by reason of such exercise, (C) authorizing the Company to withhold whole shares of Common Stock which would
otherwise be delivered having an aggregate Fair Market Value, determined as of the date of exercise, equal to the amount necessary
to satisfy such obligation, provided that the Committee determines that such withholding of shares does not cause the Company to
recognize an increased compensation expense under applicable accounting principles, (D) except as may be prohibited by applicable
law, in cash by a broker-dealer acceptable to the Company to whom the Participant has submitted an irrevocable notice of
13
exercise or (E) a combination of (A), (B) and (C) and (ii) by executing such documents as the Company may reasonably request.
Any fraction of a share of Common Stock which would be required to pay such purchase price shall be disregarded and the
remaining amount due shall be paid in cash by the Participant. No shares of Common Stock shall be issued and no certificate
representing Common Stock shall be delivered until the full purchase price therefor and any withholding taxes thereon, as described
in Section 8, have been paid.
(g) Termination of Employment.
(i)Retirement or Disability. If the Company ceases to employ a Participant by reason of such Participant’s Retirement
or Disability, each Option held by such Participant shall be fully exercisable, and may thereafter be
exercised by such Participant (or such Participant’s legal representative or similar person) until and
including the earlier to occur of (i) the fifth anniversary of the effective date of such Participant’s
termination of employment and (ii) the Expiration Date.
(ii)Death. If the Company ceases to employ a Participant by reason of such Participant’s death, each Option held by
such Participant shall be fully exercisable, and may thereafter be exercised by such Participant’s executor,
administrator, legal representative, beneficiary or similar person until and including the earlier to occur of
(i) the third anniversary of the date of death and (ii) the Expiration Date.
(iii)Cause. If the Company ceases to employ a Participant due to a termination of employment by the Company for
Cause, each Option held by such Participant shall be cancelled and cease to be exercisable as of the earlier
to occur of (i) the effective date of such termination of employment and (ii) the date on which the
Participant first engaged in conduct giving rise to a termination for Cause, and the Company thereafter
may require the repayment of any amounts received by such Participant in connection with an exercise of
such Option following such cancellation date.
(iv)Other Termination. Subject to clauses (v), (vi) and (vii) below, if the Company ceases to employ a Participant for
any reason other than as described in clause (i), (ii) or (iii) above, then each Option held by such
Participant shall be exercisable only to the extent that such Option is exercisable on the effective date of
such Participant’s termination of employment, and may thereafter be exercised by such Participant (or
such Participant’s legal representative or similar person) until and including the earlier to occur of (i) the
date which is 90 days after the effective date of such Participant’s termination of employment and (ii) the
Expiration Date.
(v)Death Following Termination of Employment. If a Participant dies during the applicable post-termination exercise
period described in clause (iv), each Option held by such Participant shall be exercisable only to the
14
extent that such Option is exercisable on the date of such Participant’s death and may thereafter be exercised
by the Participant’s executor, administrator, legal representative, beneficiary or similar person until and
including the earlier to occur of (i) the first anniversary of the date of death and (ii) the expiration date of the
term of such Option.
(vi)Breach of Restrictive Covenant. Notwithstanding clauses (i) through (v), if a Participant breaches his or her
obligations to the Company or any of its affiliates under a Restrictive Covenant, each Option held by such
Participant shall be cancelled and cease to be exercisable as of the date on which the Participant first
breached such Restrictive Covenant, and the Company thereafter may require the repayment of any
amounts received by such Participant in connection with an exercise of such Option following such
cancellation date.
(h) Termination of Option. In no event may an Option be exercised after it terminates as set forth in this Section
5(h). An Option shall terminate, to the extent not earlier exercised or terminated pursuant to Section 5(g), on the Expiration Date.
Upon the termination of the Option, the Option and all rights thereunder shall immediately become null and void.
6. Employment. For purposes of this Program, references to employment with the Company shall include (i)
employment with an Affiliate of the Company and (ii) any period during which the Participant is on a leave of absence approved by
the Company.
7. Limited Transferability of Awards. Except as may otherwise be expressly provided in an Award Notice, an
Award may be transferred by the Participant only (1) by will, (2) the laws of descent and distribution or (3) pursuant to beneficiary
designation procedures approved by the Company. Except to the extent permitted by the foregoing, an Award may not be sold,
transferred, assigned, pledged, hypothecated, encumbered or otherwise disposed of (whether by operation of law or otherwise) or be
subject to execution, attachment or similar process or domestic relations order. Upon any attempt so to sell, transfer, assign, pledge,
hypothecate, encumber or otherwise dispose of an Award, such Award and all rights thereunder shall immediately become null and
void.
15
8. Withholding Taxes. The Company shall have the right to require, prior to the issuance or delivery of any shares
of Common Stock or the payment of any cash pursuant to an Award, or upon the vesting of any Award that is considered deferred
compensation, payment by the Participant of any federal, state, local or other taxes which may be required to be withheld or paid in
connection with such Award. The Company may withhold whole shares of Common Stock which would otherwise be delivered to a
Participant, having an aggregate Fair Market Value determined as of the Tax Date, or withhold an amount of cash which would
otherwise be payable to a Participant, in the amount necessary to satisfy any such obligation. The Participant may elect to satisfy any
such obligation by any of the following means, to the extent permitted by the Administrator: (A) a cash payment to the Company,
(B) authorizing the Company to withhold whole shares of Common Stock which would otherwise be delivered having an aggregate
Fair Market Value, determined as of the Tax Date, or withhold an amount of cash which would otherwise be payable to the
Participant, equal to the amount necessary to satisfy any such obligation, (C) in the case of the exercise of an Option and except as
may be prohibited by applicable law, a cash payment by a broker-dealer acceptable to the Company to whom the Participant has
submitted an irrevocable notice of exercise or (D) any combination of (A) and (B). Shares of Common Stock to be delivered or
withheld may not have an aggregate Fair Market Value in excess of the amount determined by applying the minimum statutory
withholding rate. Any fraction of a share of Common Stock which would be required to satisfy such an obligation shall be
disregarded and the remaining amount due shall be paid in cash by the Participant.
9. Adjustment; Change in Control or Corporate Transaction. The number and class of securities subject to an Award
shall be subject to adjustment as provided in Section 5.7 of the Plan. In the event of a Change in Control or Corporate Transaction,
Awards shall be subject to the terms of Section 5.8 of the Plan, as determined by the Committee. The decision of the Committee
regarding any such adjustment, Change in Control and/or Corporate Transaction shall be final, binding and conclusive.
10. Compliance with Applicable Law. Each Award is subject to the condition that if the listing, registration or
qualification of the shares subject to such Award upon any securities exchange or under any law, or the consent or approval of any
governmental body, or the taking of any other action is necessary or desirable as a condition of, or in connection with, the delivery of
shares hereunder, such Award may not be settled, in whole or in part, unless such listing, registration, qualification, consent or
approval shall have been effected or obtained, free of any conditions not acceptable to the Company.
16
11. Award Subject to the Plan and Claw-back Policy. Each Award is subject to the provisions of the Plan, and each
Award and this Program shall be interpreted in accordance therewith. Notwithstanding any provision of the Program to the contrary,
each Award shall be subject to a clawback pursuant to the Exelon Executive Officer Compensation Recoupment Policy contained in
the Exelon Corporation Board of Directors Corporate Governance Principles, as in effect from time to time, including any
amendments thereto or new clawback policies required under the Dodd-Frank Wall Street Reform and Consumer Protection Act and
implementing applicable stock exchange listing standards or rules and regulations thereunder, or as otherwise required by law or
regulation.
12. Investment Representation. By accepting an Award, the Participant represents and covenants that (a) any share
of Common Stock acquired upon the vesting of the Award will be acquired for investment and not with a view to the distribution
thereof within the meaning of the Securities Act of 1933, as amended (the “Securities Act”), unless such acquisition has been
registered under the Securities Act and any applicable state securities law; (b) any subsequent sale of any such shares shall be made
either pursuant to an effective registration statement under the Securities Act and any applicable state securities laws, or pursuant to
an exemption from registration under the Securities Act and such state securities laws; and (c) if requested by the Company, the
Participant shall submit a written statement, in form satisfactory to the Company, to the effect that such representation (x) is true and
correct as of the date of acquisition of any shares hereunder or (y) is true and correct as of the date of any sale of any such shares, as
applicable. As a further condition precedent to the delivery to the Participant of any shares subject to the Award, the Participant shall
comply with all regulations and requirements of any regulatory authority having control of or supervision over the issuance of the
shares and, in connection therewith, shall execute any documents which the Company shall in its sole discretion deem necessary or
advisable.
13. Award Confers No Rights to Continued Employment. In no event shall the granting of an Award or its
acceptance by a Participant give or be deemed to give the Participant any right to continued employment by the Company.
14. Administrator. This Program shall be administered by the Company’s Vice President, Corporate Compensation
(the “Administrator”). Except for authority reserved to the Board or the Committee, the Administrator shall have the right to
interpret the Program, make any determinations hereunder, and take any necessary or appropriate actions with respect to the
administration of the Program or in connection with each Award. Any such interpretation, determination or other action made or
taken by the regarding this Program or an Award shall be final, binding and conclusive. The Administrator may adopt such rules and
procedures as it deems appropriate for the administration of the Plan, including but not limited to rules and procedures governing the
administration and treatment (e.g., pro-ration, vesting, etc.) of Awards to Participants in situations involving transfers between
business units and eligible and ineligible positions, which may be set forth in the applicable Program summary or Award Notice.
15. Miscellaneous Provisions.
17
(a) Successors. This Program and each Award shall be binding upon and inure to the benefit of any successor
or successors of the Company and any person or persons who shall, upon the death of a Participant, acquire any rights under
such Award in accordance with this Program or the Plan.
(b) Notices. All notices, requests or other communications provided for in this Program (other than the exercise
of a stock option) shall be made, if to the Company, to Exelon Corporation, 10 South Dearborn Street, Chicago, Illinois 60603,
Attention: Vice President, Corporate Compensation, and if to the Participant, to his or her then current work location. All
notices, requests or other communications provided for in this Program shall be made in writing either (a) by personal delivery
to the party entitled thereto, (b) by facsimile with confirmation of receipt, (c) by mailing in the United States mails to the last
known address of the party entitled thereto or (d) by express courier service. The notice, request or other communication shall
be deemed to be received upon personal delivery, upon confirmation of receipt of facsimile transmission, or upon receipt by the
party entitled thereto if by United States mail or express courier service; provided, however, that if a notice, request or other
communication is not received during regular business hours, it shall be deemed to be received on the next succeeding business
day of the Company.
(c) Section 409A. This Program and the Awards granted hereunder are intended to comply with the
requirements of section 409A of the Code and shall be interpreted and construed consistently with such intent. Awards granted
pursuant to this Program are also intended to be exempt from Section 409A of the Code to the maximum extent possible as
short-term deferrals pursuant to Treasury regulation §1.409A-1(b)(4), and for this purpose each payment shall be considered a
separate payment. In the event the terms of an Award would subject a Participant to taxes or penalties under Section 409A of the
Code (“409A Penalties”), the Company may modify the terms of such Award to avoid such 409A Penalties, to the extent
possible; provided that in no event shall the Company be responsible for any 409A Penalties that arise in connection with any
Award. To the extent the timing of payment under an Award is determined by reference to a Participant’s “termination of
employment,” such term shall be deemed to refer to the Participant’s “separation from service,” within the meaning of section
409A of the Code. Notwithstanding any other provision in this Program, if a Participant is a “specified employee,” as defined in
Section 409A of the Code, as of the date of such Participant’s separation from service, then to the extent any amount payable to
the Participant (i) constitutes the payment of nonqualified deferred compensation, within the meaning of Section 409A of the
Code, (ii) is payable upon the Participant’s separation from service and (iii) under the terms of this Program would be payable
prior to the six-month anniversary of the Participant’s separation from service, such payment shall be delayed until the earlier to
occur of (A) the six-month anniversary of the separation from service and (B) the date of the Participant’s death.
(d) Amendment. The terms of this Program may be amended by the Committee or the Board (or their
respective delegates), provided that the Chief Human Resources Officer or the Vice President, Corporate Compensation, of the
Company may
18
amend the Program to comply with applicable law, to make administrative changes or to carry out directives of the Board or the
Committee.
(e) Governing Law. This Program and each Award granted thereunder, and all determinations made and
actions taken pursuant thereto, to the extent not governed by the laws of the United States, shall be governed by the laws of the
Commonwealth of Pennsylvania and construed in accordance therewith without giving effect to principles of conflicts of laws.
IN WITNESS WHEREOF, Exelon Corporation has caused this instrument to be executed by its Senior Vice President
& Chief Human Resources Officer, effective as of January 1, 2020.
EXELON CORPORATION
By:_______________________________
Senior Vice President &
Chief Human Resources Officer
19
Exhibit 21.1
Exelon Corporation (50% and Greater)
12/31/2019
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
Aerolab Enterprises, LLC
Albany Green Energy, LLC
AMP Funding, L.L.C.
Annova LNG Brownsville A, LLC
Annova LNG Brownsville B, LLC
Annova LNG Brownsville C, LLC
Annova LNG Common Infrastructure, LLC
Annova LNG, LLC
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
BC Energy 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.
Blue Ridge Renewable Energy, LLC
Bluestem Wind Energy Holdings, LLC
Bluestem Wind Energy Member Holdings, LLC
Bluestem Wind Energy Member, LLC
Bluestem Wind Energy, LLC
Breakerbox, LLC
Jurisdiction
Delaware
Delaware
Delaware
Delaware
Delaware
Pennsylvania
Delaware
Georgia
Delaware
Delaware
Delaware
Delaware
Delaware
Delaware
Delaware
New Jersey
Delaware
New Jersey
New Jersey
Delaware
Delaware
Maryland
Minnesota
Delaware
Delaware
Idaho
Delaware
Delaware
Oregon
Minnesota
Minnesota
Delaware
Delaware
Delaware
Delaware
Delaware
Pennsylvania
1
Exhibit 21.1
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
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
Oregon
Delaware
Delaware
Delaware
Maryland
Idaho
Idaho
Maryland
Delaware
Delaware
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
2
Exhibit 21.1
Colorado Bend Services, LLC
ComEd Financing III
Commonwealth Edison Company
Commonwealth Edison Company of Indiana, Inc.
Conectiv Communications, Inc.
Conectiv Energy Supply, Inc.
Conectiv North East, LLC
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
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
3
Delaware
Delaware
Illinois
Indiana
Delaware
Delaware
Delaware
Delaware
Delaware
Delaware
Delaware
Delaware
Delaware
Ontario
Delaware
Delaware
Maryland
Delaware
Delaware
Delaware
Maryland
Delaware
Delaware
Kentucky
Delaware
Delaware
Delaware
Maryland
Maryland
Delaware
Delaware
Delaware
Delaware
Delaware
Delaware
Delaware
Georgia
Delaware
Delaware
Delaware
Delaware
Exhibit 21.1
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 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
DE ESCO, LLC
Delaware Operating Services Company, LLC
Delmarva Power & Light Company
Denver Airport Solar, LLC
Distributed Generation Partners, LLC
Distrigas of Massachusetts LLC
E&W Development Corporation
EdiSun, LLC
Energy Performance Services, Inc.
ETT Canada, Inc.
Everett LNG LLC
Ewington Energy Systems LLC
Exelon AVSR Holding, LLC
Exelon AVSR, LLC
Exelon Business Services Company, LLC
Exelon Energy Delivery Company, LLC
Exelon Enterprises Company, LLC
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 & Virginia
Delaware
Delaware
Delaware
Florida
Delaware
Pennsylvania
New Brunswick
Delaware
Minnesota
Delaware
Delaware
Delaware
Delaware
Pennsylvania
4
Exhibit 21.1
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 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 II, 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.
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
Delaware
Delaware
Delaware
Delaware
Pennsylvania
Illinois
Delaware
United Kingdom
Delaware
Delaware
Delaware
Delaware
Delaware
Delaware
Delaware
Delaware
Pennsylvania
Delaware
Delaware
Delaware
Delaware
Delaware
Texas
Texas
Texas
Canada
Delaware
Delaware
Delaware
New York
Delaware
Mexico
Delaware
Delaware
Delaware
Delaware
Delaware
Delaware
Delaware
Delaware
Delaware
5
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
EZEV Enterprise, LLC
F & M Holdings Company, L.L.C.
Fair Wind Power Partners, LLC
Fauquier Landfill Gas, L.L.C.
Four Corners Windfarm, LLC
Four Mile Canyon Windfarm, LLC
Fourmile Wind Energy, LLC
Friendly Skies, Inc.
Gateway Solar LLC
Grande Prairie Generation, Inc.
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
K & D Energy LLC
KC Energy LLC
KSS Turbines LLC
Lake Houston Power, LLC
Loess Hills Wind Farm, 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
Nine Mile Point Nuclear Station, LLC
North Shore District Energy, LLC
Exhibit 21.1
Delaware
Delaware
Delaware
United Kingdom
United Kingdom
Delaware
Delaware
Delaware
Delaware
Delaware
Oregon
Oregon
Maryland
U.S. Virgin Islands
Delaware
Alberta
Delaware
Maryland
Delaware
Michigan
Idaho
Texas
Delaware
Idaho
Delaware
Japan
Minnesota
Minnesota
Minnesota
Delaware
Missouri
Delaware
Delaware
Delaware
Delaware
Wisconsin
Arizona
Maryland
Delaware
Delaware
Northwind Thermal Technologies Canada Inc.
New Brunswick
6
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 Energy Cogeneration LLC
Pepco Energy Solutions LLC
Pepco Government Services LLC
Pepco Holdings LLC
PFMG Construction, Ltd.
PFMG Solar Baldwin Park, LLC
PFMG Solar Etiwanda Falcon, LLC
PFMG Solar Long Beach, LLC
PFMG Solar PUSD, LLC
PFMG Solar San Diego, LLC
PFMG Solar, LLC
PH Holdco LLC
PHI Service Company
Pinedale Energy, LLC
POM Holdings, Inc.
Potomac Capital Investment Corporation
Potomac Delaware Leasing Corporation
Potomac Electric Power Company
Potomac Leasing Associates, L.P.
Potomac Power Resources, LLC
Prairie Wind Power LLC
R.E. Ginna Nuclear Power Plant, LLC
Ramp Investments, L.L.C.
Renewable Power Generation Holdings, LLC
Exhibit 21.1
Oregon
Oregon
Oregon
Delaware
Delaware
Delaware
Nevada
Delaware
Pennsylvania
Delaware
Delaware
Delaware
Delaware
Pennsylvania
Delaware
California
Delaware
Delaware
Delaware
Delaware
Delaware
California
Delaware
Delaware
Delaware
Delaware
Delaware
Delaware
Delaware
Delaware
Colorado
Delaware
Delaware
Delaware
District of Columbia & Virginia
Delaware
Delaware
Minnesota
Maryland
Delaware
Delaware
7
Exhibit 21.1
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
Series A of Annova LNG, LLC
Series B of Annova LNG, LLC
Series C of Annova LNG, LLC
Series Z of Annova LNG, LLC
Shooting Star Wind Project, LLC
Sky Valley, LLC
SolGen Holding, LLC
SolGen, LLC
Sugar Beet Wind, LLC
Sunnyside II, Inc.
Sunnyside II, L.P.
Sunnyside III, Inc.
Threemile Canyon Wind I, LLC
Titan STC, LLC
Tuana Springs Energy, LLC
UII, LLC
V.G. Investment Holdings, LLC
Vineland Cogeneration Limited Partnership
Vineland General, Inc.
Vineland Ltd., Inc.
Volta SPV CMX, LLC
Volta SPV NSC, LLC
Volta SPV NTR, 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
Whitetail Wind Energy, LLC
Delaware
Delaware
Illinois
Delaware
Delaware
Delaware
Oregon
Delaware
Delaware
Delaware
Delaware
Delaware
Delaware
Delaware
Delaware
Delaware
Delaware
Delaware
Delaware
Delaware
Delaware
Delaware
Delaware
Oregon
Delaware
Idaho
Illinois
Delaware
Delaware
Delaware
Delaware
Delaware
Delaware
Delaware
Delaware
Oregon
Delaware
Delaware
Oregon
Delaware
Delaware
8
Wildcat Finance, LLC
Wildcat Wind LLC
Wind Capital Holdings, LLC
Wolf Hollow II Power, LLC
Wolf Hollow Services, LLC
Delaware
New Mexico
Missouri
Delaware
Delaware
9
Exhibit 21.1
Exhibit 21.2
Exelon Generation Company, LLC (50% and Greater)
12/31/2019
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 Brownsville B, LLC
Annova LNG Brownsville C, LLC
Annova LNG Common Infrastructure, LLC
Annova LNG, LLC
APS Constellation, LLC
Atlantic Generation, Inc.
AV Solar Ranch 1, LLC
BC Energy 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.
Blue Ridge Renewable Energy, LLC
Bluestem Wind Energy Holdings, LLC
Bluestem Wind Energy Member Holdings, LLC
Bluestem Wind Energy Member, LLC
Bluestem Wind Energy, 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.
1
Jurisdiction
Delaware
Delaware
Delaware
Delaware
Delaware
Pennsylvania
Georgia
Delaware
Delaware
Delaware
Delaware
Delaware
Delaware
New Jersey
Delaware
Minnesota
Delaware
Delaware
Idaho
Delaware
Delaware
Oregon
Minnesota
Minnesota
Delaware
Delaware
Delaware
Delaware
Delaware
Pennsylvania
Oregon
Delaware
Delaware
Delaware
Maryland
Idaho
Idaho
Maryland
Exhibit 21.2
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
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 North East, 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
2
Delaware
Delaware
Maryland
Maryland
Maryland
Delaware
Delaware
Delaware
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
Delaware
Ontario
Delaware
Exhibit 21.2
Constellation Energy Gas Choice, LLC
Constellation Energy Nuclear Group, LLC
Constellation Energy Power Choice, LLC
Constellation Energy Resources, 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 Rhode Island, LLC
Constellation Solar Texas, LLC
Constellation Solar, LLC
Continental Wind Holding, LLC
Continental Wind, LLC
Delaware
Maryland
Delaware
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
3
Exhibit 21.2
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
DE ESCO, LLC
Delaware Operating Services Company, LLC
Denver Airport Solar, LLC
Distributed Generation Partners, LLC
Distrigas of Massachusetts LLC
Energy Performance Services, Inc.
Everett LNG LLC
Ewington Energy Systems 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
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 II, 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
Maryland
Maryland
Missouri
Maryland
Minnesota
Missouri
Delaware
Delaware
Delaware
Delaware
Delaware
Delaware
Delaware
Pennsylvania
Delaware
Minnesota
Delaware
Delaware
Delaware
Delaware
Delaware
Delaware
Illinois
Delaware
United Kingdom
Delaware
Delaware
Delaware
Delaware
Pennsylvania
Delaware
Delaware
Delaware
Texas
Texas
Texas
Canada
Delaware
Delaware
Mexico
Delaware
4
Exhibit 21.2
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.
Four Corners Windfarm, LLC
Four Mile Canyon Windfarm, LLC
Fourmile Wind Energy, LLC
Gateway Solar LLC
Grande Prairie Generation, Inc.
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
K & D Energy LLC
KC Energy LLC
KSS Turbines LLC
Lake Houston Power, LLC
Loess Hills Wind Farm, 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
Delaware
Delaware
Delaware
Delaware
Delaware
Delaware
Delaware
Delaware
Delaware
Delaware
Delaware
United Kingdom
United Kingdom
Delaware
Delaware
Oregon
Oregon
Maryland
Delaware
Alberta
Delaware
Maryland
Delaware
Michigan
Idaho
Texas
Delaware
Idaho
Delaware
Japan
Minnesota
Minnesota
Minnesota
Delaware
Missouri
Delaware
Delaware
Delaware
Wisconsin
Arizona
Maryland
5
Exhibit 21.2
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 Energy Cogeneration LLC
Pepco Energy Solutions LLC
Pepco Government Services LLC
Pepco Holdings LLC
PFMG Construction, Ltd.
PFMG Solar Baldwin Park, LLC
PFMG Solar Etiwanda Falcon, LLC
PFMG Solar Long Beach, LLC
PFMG Solar PUSD, LLC
PFMG Solar San Diego, LLC
PFMG Solar, LLC
Pinedale Energy, LLC
Potomac Power Resources, LLC
Prairie Wind Power 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
Series A of Annova LNG, LLC
Series B of Annova LNG, LLC
Series C of Annova LNG, LLC
Series Z of Annova LNG, LLC
Shooting Star Wind Project, LLC
Sky Valley, LLC
SolGen Holding, LLC
SolGen, LLC
Sugar Beet Wind, LLC
Sunnyside II, Inc.
Sunnyside II, L.P.
Delaware
Delaware
Oregon
Oregon
Oregon
Delaware
Delaware
California
Delaware
Delaware
Delaware
Delaware
Delaware
California
Delaware
Delaware
Delaware
Delaware
Delaware
Delaware
Colorado
Delaware
Minnesota
Maryland
Delaware
Delaware
Delaware
Delaware
Oregon
Delaware
Delaware
Delaware
Delaware
Delaware
Delaware
Delaware
Delaware
Delaware
Delaware
Delaware
Delaware
6
Exhibit 21.2
Sunnyside III, Inc.
Threemile Canyon Wind I, LLC
Titan STC, LLC
Tuana Springs Energy, LLC
V.G. Investment Holdings, LLC
Vineland Cogeneration Limited Partnership
Vineland General, Inc.
Vineland Ltd., Inc.
W&D Gas Partners, LLC
Wagon Trail, LLC
Ward Butte Windfarm, LLC
Water & Energy Savings Company, 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
Oregon
Delaware
Idaho
Delaware
Delaware
Delaware
Delaware
Delaware
Oregon
Oregon
Delaware
Delaware
Delaware
New Mexico
Missouri
Delaware
Delaware
7
Exhibit 21.3
Commonwealth Edison Company (50% and Greater)
12/31/2019
Subsidiary
Commonwealth Edison Company of Indiana, Inc.
ComEd Financing III
EdiSun, LLC
RITELine Illinois, LLC
Jurisdiction
Indiana
Delaware
Delaware
Illinois
PECO Energy Company (50% and Greater)
12/31/2019
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
Exhibit 21.4
Jurisdiction
Delaware
Delaware
Pennsylvania
Delaware
Delaware
Delaware
Delaware
Delaware
Baltimore Gas and Electric Company (50% and Greater)
12/31/2019
Subsidiary
None
Jurisdiction
Exhibit 21.5
Pepco Holdings LLC (50% and Greater)
12/31/2019
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
POM Holdings, Inc.
Exhibit 21.6
Jurisdiction
New Jersey
Delaware
Delaware & Virginia
Delaware
Delaware
District of Columbia & Virginia
Delaware
Potomac Electric Power Company (50% and Greater)
12/31/2019
Subsidiary
POM Holdings, Inc.
Jurisdiction
Delaware
Exhibit 21.7
Delmarva Power & Light Company
12/31/2019
Subsidiary
None
Exhibit 21.8
Jurisdiction
Atlantic City Electric Company (50% and Greater)
12/31/2019
Subsidiary
Atlantic City Electric Transition Funding LLC
Jurisdiction
New Jersey
Exhibit 21.9
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. 333-219037, 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 11, 2020 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 11, 2020
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 11, 2020 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 11, 2020
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 11, 2020 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 11, 2020
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 11, 2020 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 11, 2020
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 11, 2020 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 11, 2020
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 11, 2020 relating to the financial statements and financial statement schedule, which appears in this
Form 10-K.
Exhibit 23.6
/s/ PricewaterhouseCoopers LLP
Washington, DC
February 11, 2020
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 11, 2020 relating to the financial statements and financial statement schedule, which appears in this
Form 10-K.
Exhibit 23.7
/s/ PricewaterhouseCoopers LLP
Washington, DC
February 11, 2020
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 11, 2020 relating to the financial statements and financial statement schedule, which appears in this
Form 10-K.
Exhibit 23.8
/s/ PricewaterhouseCoopers LLP
Washington, DC
February 11, 2020
KNOW ALL MEN BY THESE PRESENTS that I, Anthony K. Anderson, do hereby appoint Christopher M. Crane and Thomas S. O'Neill, or either of them,
attorney for me and in my name and on my behalf to sign the annual Securities and Exchange Commission report on Form 10-K for 2019 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: January 28, 2020
POWER OF ATTORNEY
Exhibit 24.2
KNOW ALL MEN BY THESE PRESENTS that I, Ann C. Berzin, do hereby appoint Christopher M. Crane and Thomas S. O'Neill, or either of them, attorney for
me and in my name and on my behalf to sign the annual Securities and Exchange Commission report on Form 10-K for 2019 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: January 28, 2020
POWER OF ATTORNEY
Exhibit 24.3
KNOW ALL MEN BY THESE PRESENTS that I, Laurie Brlas, do hereby appoint Christopher M. Crane and Thomas S. O'Neill, or either of them, attorney for
me and in my name and on my behalf to sign the annual Securities and Exchange Commission report on Form 10-K for 2019 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: January 28, 2020
POWER OF ATTORNEY
Exhibit 24.4
KNOW ALL MEN BY THESE PRESENTS that I, Christopher M. Crane, do hereby appoint Thomas S. O'Neill 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 2019 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: January 15, 2020
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 Thomas S. O'Neill, or either of them,
attorney for me and in my name and on my behalf to sign the annual Securities and Exchange Commission report on Form 10-K for 2019 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: January 28, 2020
POWER OF ATTORNEY
Exhibit 24.6
KNOW ALL MEN BY THESE PRESENTS that I, Nicholas DeBenedictis, do hereby appoint Christopher M. Crane and Thomas S. O'Neill, or either of them,
attorney for me and in my name and on my behalf to sign the annual Securities and Exchange Commission report on Form 10-K for 2019 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: January 22, 2020
POWER OF ATTORNEY
Exhibit 24.7
KNOW ALL MEN BY THESE PRESENTS that I, Linda P. Jojo, do hereby appoint Christopher M. Crane and Thomas S. O'Neill, or either of them, attorney for
me and in my name and on my behalf to sign the annual Securities and Exchange Commission report on Form 10-K for 2019 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: January 28, 2020
POWER OF ATTORNEY
Exhibit 24.8
KNOW ALL MEN BY THESE PRESENTS that I, Paul Joskow, do hereby appoint Christopher M. Crane and Thomas S. O'Neill, or either of them, attorney for
me and in my name and on my behalf to sign the annual Securities and Exchange Commission report on Form 10-K for 2019 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: January 28, 2020
POWER OF ATTORNEY
Exhibit 24.9
KNOW ALL MEN BY THESE PRESENTS that I, Robert J. Lawless, do hereby appoint Christopher M. Crane and Thomas S. O'Neill, or either of them, attorney
for me and in my name and on my behalf to sign the annual Securities and Exchange Commission report on Form 10-K for 2019 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: January 28, 2020
POWER OF ATTORNEY
Exhibit 24.10
KNOW ALL MEN BY THESE PRESENTS that I, Richard W. Mies, do hereby appoint Christopher M. Crane and Thomas S. O'Neill, or either of them, attorney
for me and in my name and on my behalf to sign the annual Securities and Exchange Commission report on Form 10-K for 2019 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/ RICHARD W. MIES
Richard W. Mies
DATE: January 28, 2020
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 Thomas S. O'Neill, or either of them,
attorney for me and in my name and on my behalf to sign the annual Securities and Exchange Commission report on Form 10-K for 2019 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: January 28, 2020
KNOW ALL MEN BY THESE PRESENTS that I, Stephen D. Steinour, do hereby appoint Christopher M. Crane and Thomas S. O'Neill, or either of them,
attorney for me and in my name and on my behalf to sign the annual Securities and Exchange Commission report on Form 10-K for 2019 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 24.13
/s/ STEPHEN D. STEINOUR
Stephen D. Steinour
DATE: January 28, 2020
POWER OF ATTORNEY
Exhibit 24.14
KNOW ALL MEN BY THESE PRESENTS that I, John F. Young, do hereby appoint Christopher M. Crane and Thomas O'Neill, or either of them, attorney for
me and in my name and on my behalf to sign the annual Securities and Exchange Commission report on Form 10-K for 2019 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: January 28, 2020
POWER OF ATTORNEY
Exhibit 24.15
KNOW ALL MEN BY THESE PRESENTS that I, John Richardson, do hereby appoint Christopher M. Crane and Thomas O'Neill, or either of them, attorney for
me and in my name and on my behalf to sign the annual Securities and Exchange Commission report on Form 10-K for 2019 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: January 28, 2020
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 2019 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: January 30, 2020
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 2019 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: January 15, 2020
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 2019 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: January 30, 2020
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 2019 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: January 22, 2020
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 2019 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: January 15, 2020
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 2019 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: January 30, 2020
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 2019 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 10, 2020
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 2019 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: January 15, 2020
POWER OF ATTORNEY
Exhibit 24.24
KNOW ALL MEN BY THESE PRESENTS that I, Juan Ochoa, 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 2019 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/ JUAN OCHOA
Juan Ochoa
DATE: January 30, 2020
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 2019 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: January 15, 2020
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 2019 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: January 22, 2020
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 2019 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: January 23, 2020
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 2019 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: January 23, 2020
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 2019 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 5, 2020
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 2019 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: January 15, 2020
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 2019 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: January 30, 2020
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 2019 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: January 15, 2020
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 2019 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: January 28, 2020
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 2019 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: January 15, 2020
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 2019 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: January 15, 2020
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 2019 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: January 23, 2020
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 2019 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: January 27, 2020
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 2019 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: January 30, 2020
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 2019 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: January 15, 2020
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 2019 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: January 27, 2020
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 2019 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: January 28, 2020
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 2019 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: January 15, 2020
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 2019 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, 2020
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 2019 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: January 23, 2020
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 2019 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: January 23, 2020
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 2019 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 3, 2020
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 2019 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: January 25, 2020
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 2019 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: January 15, 2020
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 2019 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: January 15, 2020
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 2019 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: January 16, 2020
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 2019 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: January 15, 2020
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 2019 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: January 15, 2020
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 2019 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: January 15, 2020
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 2019 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: January 15, 2020
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 2019 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: January 15, 2020
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 2019 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: January 15, 2020
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 2019 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: January 15, 2020
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 2019 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: January 15, 2020
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 11, 2020
/s/ CHRISTOPHER M. CRANE
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 31.2
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 11, 2020
/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, Kenneth W. Cornew, certify that:
1.
I have reviewed this annual report on Form 10-K of Exelon Generation Company, LLC;
2. Based on my knowledge, this report does not contain any untrue statement of a material fact or omit to state a material fact necessary 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 11, 2020
/s/ KENNETH W. CORNEW
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 31.4
I, Bryan P. Wright, certify that:
1.
I have reviewed this annual report on Form 10-K of Exelon Generation Company, LLC;
2. Based on my knowledge, this report does not contain any untrue statement of a material fact or omit to state a material fact necessary 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 11, 2020
/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 11, 2020
/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 11, 2020
/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:
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 11, 2020
/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 11, 2020
/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 11, 2020
/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 11, 2020
/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 11, 2020
/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 11, 2020
/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 11, 2020
/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 11, 2020
/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 11, 2020
/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 11, 2020
/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 11, 2020
/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 11, 2020
/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, 2019, 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 11, 2020
/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, 2019, 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 11, 2020
/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, 2019, 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 11, 2020
/s/ KENNETH W. CORNEW
Kenneth W. Cornew
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 Generation Company, LLC for the year ended December 31, 2019, 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 11, 2020
/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, 2019, 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 11, 2020
/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, 2019, 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 11, 2020
/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, 2019, 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 11, 2020
/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, 2019, 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 11, 2020
/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, 2019,
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
Date: February 11, 2020
/s/ CARIM V. KHOUZAMI
Carim V. Khouzami
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 Baltimore Gas and Electric Company for the year ended December 31, 2019,
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 11, 2020
/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, 2019, 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 11, 2020
/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, 2019, 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 11, 2020
/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, 2019, 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 11, 2020
/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, 2019, 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 11, 2020
/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, 2019, 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 11, 2020
/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, 2019, 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 11, 2020
/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, 2019, 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 11, 2020
/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, 2019, 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 11, 2020
/s/ PHILLIP S. BARNETT
Phillip S. Barnett
Senior Vice President, Chief Financial Officer and Treasurer