UNITED STATES SECURITIES AND EXCHANGE COMMISSION
WASHINGTON, D.C. 20549
FORM 10-K
ý
¨
ANNUAL REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934
For the Fiscal Year Ended December 31, 2018
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
1-16169
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
1-1839
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
1-1910
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
EXELON CORPORATION:
Common Stock, without par value
Series A Junior Subordinated Debentures
Corporate Units
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
Securities registered pursuant to Section 12(g) of the Act:
Name of Each Exchange on Which
Registered
New York and Chicago
New York
New York
New York
Title of Each Class
COMMONWEALTH EDISON COMPANY:
Common Stock Purchase Warrants, 1971 Warrants and Series B Warrants
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
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 x
Yes x
Yes x
Yes x
Yes x
Yes o
Yes o
Yes o
Yes o
Yes o
Yes o
Yes o
Yes o
Yes o
Yes o
Yes o
Yes o
No o
No o
No o
No o
No o
No o
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 and posted on its corporate web site, if any, every Interactive Data File required to be submitted
and posted pursuant to Rule 405 of Regulation S-T (§232.405 of this chapter) during the preceding 12 months (or for such shorter period that the registrant was required to
submit and post such files). Yes ý
No ¨
Indicate by check mark if disclosure of delinquent filers pursuant to Item 405 of Regulation S-K is not contained herein, and will not be contained, to the best of registrants’
knowledge, in definitive proxy or information statements incorporated by reference in Part III of this Form 10-K or any amendment to this Form 10-K. ý
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
Smaller Reporting
Company
Emerging Growth
Company
x
x
x
x
x
x
x
x
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 o
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, 2018 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, 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 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
$41,118,095,431
Not applicable
No established market
None
None
Not applicable
None
None
None
969,745,933
Not applicable
127,021,331
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
Commonwealth Edison Company
PECO Energy Company
Baltimore Gas and Electric Company
Potomac Electric Power Company
Delmarva Power & Light Company
Atlantic City Electric Company
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
17
21
21
26
31
49
50
50
55
55
56
57
58
59
60
60
61
65
65
66
66
67
68
68
69
70
70
ITEM 7.
MANAGEMENT’S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS
Exelon Corporation
Executive Overview
Financial Results of Operations
Significant 2018 Transactions and Recent Developments
Exelon's Strategy and Outlook for 2019 and Beyond
Liquidity Considerations
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.
72
72
72
73
78
83
85
85
91
102
103
111
115
119
122
124
128
133
136
156
163
163
171
173
175
177
179
181
183
185
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. Variable Interest Entities
3. Revenue from Contracts with Customers
4. Regulatory Matters
5. Mergers, Acquisitions and Dispositions
6. Property, Plant and Equipment
7. Impairment of Long-Lived Assets and Intangibles
8. Early Plant Retirements
9. Jointly Owned Electric Utility Plant
10. Intangible Assets
11. Fair Value of Financial Assets and Liabilities
12. Derivative Financial Instruments
13. Debt and Credit Agreements
14. Income Taxes
15. Asset Retirement Obligations
16. Retirement Benefits
17. Severance
18. Shareholders' Equity
19. Stock-Based Compensation Plans
20. Earnings Per Share
21. Changes in Accumulated Other Comprehensive Income
22. Commitments and Contingencies
23. Supplemental Financial Information
24. Segment Information
25. Related Party Transactions
26. Quarterly Data
27. Subsequent Events
ITEM 9.
ITEM 9A.
ITEM 9B.
CHANGES IN AND DISAGREEMENTS WITH ACCOUNTANTS ON ACCOUNTING AND FINANCIAL DISCLOSURE
CONTROLS AND PROCEDURES
OTHER INFORMATION
Page No.
187
212
217
222
227
232
237
242
247
252
257
258
272
279
283
302
309
315
317
321
322
326
347
360
374
387
392
410
412
413
418
419
423
436
450
463
475
478
479
479
479
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.
480
481
482
483
484
485
541
542
542
543
544
545
546
547
548
549
550
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
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
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
AEC
AESO
AFUDC
AGE
AMI
AMP
AOCI
ARC
ARO
ARP
ASA
BGS
CAISO
CAP
CCGTs
CERCLA
CES
Clean Air Act
Clean Water Act
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
EPA
GLOSSARY OF TERMS AND ABBREVIATIONS
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
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
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
United States Environmental Protection Agency
2
Table of Contents
Other Terms and Abbreviations
EPSA
ERCOT
ERISA
EROA
FASB
FEJA
FERC
FRCC
GAAP
GCR
GHG
GSA
GWh
IBEW
ICC
ICE
IIP
GLOSSARY OF TERMS AND ABBREVIATIONS
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
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
ISO-NY
kV
kW
kWh
LIBOR
LLRW
LNG
LTIP
MAPP
MATS
MBR
MDE
MDPSC
MGP
MISO
mmcf
Moody’s
Integrys Energy Services, Inc.
Illinois Power Agency
Internal Revenue Code
Internal Revenue Service
Independent System Operator
ISO New England Inc.
ISO New York
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.
Million Cubic Feet
Moody’s Investor Service
3
Table of Contents
Other Terms and Abbreviations
MOPR
MRV
MW
MWh
n.m.
NAAQS
NAV
NDT
NEIL
NERC
NGS
NJBPU
NJDEP
NLRB
GLOSSARY OF TERMS AND ABBREVIATIONS
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
NRC
NSPS
NWPA
NYMEX
NYPSC
OCI
OIESO
OPC
OPEB
PA DEP
PAPUC
PCB
PGC
PJM
POLR
POR
PPA
Nuclear Operating Services Agreement
National Pollutant Discharge Elimination System
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
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
PRP
PSEG
PV
RCRA
stock, par value $0.01 per share
Potentially Responsible Parties
Public Service Enterprise Group Incorporated
Photovoltaic
Resource Conservation and Recovery Act of 1976, as amended
4
Table of Contents
Other Terms and Abbreviations
REC
Regulatory Agreement Units
GLOSSARY OF TERMS AND ABBREVIATIONS
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
RES
RFP
Rider
RGGI
RMC
RNF
ROE
RPM
RPS
RSSA
RTEP
RTO
S&P
SEC
SERC
SGIG
SILO
SNF
SOS
SPFPA
SPP
TCJA
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
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
FILING FORMAT
This combined Annual Report on Form 10-K is being filed separately by Exelon Corporation, Exelon Generation Company, LLC, Commonwealth Edison
Company, PECO Energy Company, Baltimore Gas and Electric Company, Pepco Holdings LLC, Potomac Electric Power Company, Delmarva Power & Light
Company and Atlantic City Electric Company (Registrants). Information contained herein relating to any individual Registrant is filed by such Registrant on its
own behalf. No Registrant makes any representation as to information relating to any other Registrant.
CAUTIONARY STATEMENTS REGARDING FORWARD-LOOKING INFORMATION
This Report contains certain forward-looking statements within the meaning of the Private Securities Litigation Reform Act of 1995 that are subject to risks and
uncertainties. 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) ITEM 1A. Risk Factors, (b) ITEM 7. Management’s
Discussion and Analysis of Financial Condition and Results of Operations and (c) ITEM 8. Financial Statements and Supplementary Data: Note 22 ,
Commitments and Contingencies; and (d) other factors discussed in filings with the SEC by the Registrants. Readers are cautioned not to place undue reliance
on these forward-looking statements, which apply only as of the date of this Report. None of the Registrants undertakes any obligation to publicly release any
revision to its forward-looking statements to reflect events or circumstances after the date of this Report.
WHERE TO FIND MORE INFORMATION
The SEC maintains an Internet site at www.sec.gov that contains reports, proxy and information statements, and other information that the Registrants file
electronically with the SEC. These documents are also available to the public from commercial document retrieval services and the Registrants’ website at
www.exeloncorp.com. Information contained on the Registrants’ website shall not be deemed incorporated into, or to be a part of, this Report.
6
Table of Contents
ITEM 1.
BUSINESS
General
PART I
Corporate Structure and Business and Other Information
Exelon, incorporated in Pennsylvania in February 1999, is a utility services holding company engaged, through Generation, in the energy generation business,
and through ComEd, PECO, BGE, PHI, Pepco, DPL and ACE in the energy delivery businesses discussed below. Exelon’s principal executive offices are
located at 10 South Dearborn Street, Chicago, Illinois 60603.
Name of Registrant
Exelon Generation
Company, LLC
State/Jurisdiction and
Year of Incorporation
Pennsylvania (2000)
Business
Generation, physical delivery and marketing of power
across multiple geographical regions through its
customer-facing business, Constellation, which sells
electricity to both wholesale and retail customers.
Generation also sells natural gas, renewable energy
and other energy-related products and services.
Service
Territories
Address of Principal
Executive Offices
Six reportable segments: Mid-Atlantic,
Midwest, New England, New York,
ERCOT and Other Power Regions
300 Exelon Way,
Kennett Square, Pennsylvania 19348
Commonwealth Edison
Company
Illinois (1913)
Purchase and regulated retail sale of electricity
Northern Illinois, including the City of
Chicago
440 South LaSalle Street,
Chicago, Illinois 60605
Transmission and distribution of electricity to retail
customers
PECO Energy Company
Pennsylvania (1929)
Purchase and regulated retail sale of electricity and
natural gas
Southeastern Pennsylvania, including the
City of Philadelphia (electricity)
2301 Market Street,
Philadelphia, Pennsylvania 19103
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
Maryland (1906)
Purchase and regulated retail sale of electricity and
natural gas
Central Maryland, including the City of
Baltimore (electricity and natural gas)
110 West Fayette Street,
Baltimore, Maryland 21201
Transmission and distribution of electricity and
distribution of natural gas to retail customers
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
701 Ninth Street, N.W.,
Washington, D.C. 20068
Potomac Electric
Power Company
District of Columbia
Purchase and regulated retail sale of electricity
District of Columbia and Major portions of
701 Ninth Street, N.W.,
(1896)
Virginia (1949)
Montgomery and Prince George’s
Counties, Maryland
Washington, D.C. 20068
Transmission and distribution of electricity to retail
customers
Delmarva Power & Light
Company
Delaware (1909)
Virginia (1979)
Purchase and regulated retail sale of electricity and
natural gas
Portions of Delaware and Maryland
(electricity)
500 North Wakefield Drive,
Newark, Delaware 19702
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
New Jersey (1924)
Purchase and regulated retail sale of electricity
Portions of Southern New Jersey
500 North Wakefield Drive,
Newark, Delaware 19702
Transmission and distribution of electricity to retail
customers
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Business Services
Through its business services subsidiary BSC, Exelon provides its operating subsidiaries with a variety of corporate governance support services including
corporate strategy and development, legal, human resources, information technology, finance, real estate, security, corporate communications and supply at
cost. The costs of these services are directly charged or allocated to the applicable operating segments. The services are provided pursuant to service
agreements. Additionally, the results of Exelon’s corporate operations include interest costs and income from various investment and financing activities.
PHISCO, a wholly owned subsidiary of PHI, provides a variety of support services at cost, including legal, finance, engineering, distribution and transmission
planning, asset management, system operations, and power procurement, to PHI and its operating subsidiaries. These services are directly charged or allocated
pursuant to service agreements among PHISCO and the participating operating subsidiaries.
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. See Note 5 — Mergers, Acquisitions and Dispositions of the Combined Notes to Consolidated Financial Statements for additional
information.
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 ISO-NY 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.
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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.
CENG
Generation owns a 50.01% interest in CENG, a joint venture with EDF. CENG is governed by a board of ten directors, five of which are appointed by Generation
and five by EDF. CENG owns a total of five nuclear generating facilities on three sites, Calvert Cliffs, R.E. Ginna (Ginna) and Nine Mile Point. CENG’s ownership
share in the total capacity of these units is 4,041 MW. See ITEM 2. PROPERTIES for additional information on these sites.
Generation and EDF entered into a Put Option Agreement on April 1, 2014, pursuant to which EDF has the option, exercisable beginning on January 1, 2016
and thereafter until June 30, 2022, to sell its 49.99% interest in CENG to Generation for a fair market value price determined by agreement of the parties, or
absent agreement, a third-party arbitration process. The appraisers determining fair market value of EDF’s 49.99% interest in CENG under the Put Option
Agreement are instructed to take into account all rights and obligations under the CENG Operating Agreement, including Generation’s rights with respect to any
unpaid aggregate preferred distributions and the related return, and the value of Generation’s rights to other distributions. In addition, under limited
circumstances, the period for exercise of the put option may be extended for 18 months. In order to exercise its option, EDF must give 60-days advance written
notice to Generation stating that it is exercising its option. To date, EDF has not given notice to Generation that it is exercising its option.
Exelon and Generation record all assets, liabilities and EDF’s noncontrolling interests in CENG on a fully consolidated basis in Exelon’s and Generation’s
Consolidated Balance Sheets. See Note 2 — Variable Interest Entities of the Combined Notes to Consolidated Financial Statements for additional information
regarding the CENG consolidation.
Acquisitions
Handley Generating Station
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. See EGTP in the Dispositions section below for additional information on EGTP's November 7, 2017 bankruptcy filing.
FitzPatrick
On March 31, 2017, Generation acquired the 838 MW 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.
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.
Integrys Energy Services, Inc.
On November 1, 2014, Generation acquired the competitive retail electric and natural gas business activities of Integrys Energy Group, Inc. through the
purchase of all of the stock of its wholly owned subsidiary, Integrys Energy Services, Inc. (Integrys) for a purchase price of $ 332 million , including net working
capital. The generation and solar asset businesses of Integrys were excluded from the transaction.
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Dispositions
EGTP
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.
Asset Dispositions
During 2015 and 2014, Generation sold certain generating assets with total pre-tax proceeds of $ 1.8 billion (after-tax proceeds of approximately $1.4 billion ).
Proceeds were used primarily to finance a portion of the acquisition of PHI.
See Note 5 — Mergers, Acquisitions and Dispositions and Note 7 — Impairment of Long-Lived Assets and Intangibles of the Combined Notes to Consolidated
Financial Statements for additional information on acquisitions and dispositions.
Generating Resources
At December 31, 2018 , 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
Long-term power purchase contracts (d)
Total generating resources
MW
19,713
9,547
3,203
32,463
5,184
37,647
__________
(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 generating assets.
Generation has six reportable segments, Mid-Atlantic, Midwest, New England, New York, ERCOT and Other Power Regions, representing the different
geographical areas in which Generation’s generating resources are located and Generation's customer-facing activities are conducted.
• Mid-Atlantic represents operations in the eastern half of PJM, which includes Pennsylvania, New Jersey, Maryland, Virginia, West Virginia, Delaware, the
District of Columbia and parts of North Carolina (approximately 34% of capacity).
• Midwest represents operations in the western half of PJM and the United States footprint of MISO, excluding MISO’s Southern Region (approximately
37% of capacity).
•
•
•
•
New England represents operations within ISO-NE (approximately 7% of capacity).
New York represents operations within ISO-NY (approximately 6% of capacity).
ERCOT represents operations within Electric Reliability Council of Texas (approximately 11% of capacity).
Other Power Regions represents Canada, South and West (approximately 5% of capacity).
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During the first quarter of 2019, due to a change in economics in our New England region, Generation is changing 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. As a result,
beginning in the first quarter of 2019, Generation will disclose five reportable segments consisting of Mid-Atlantic, Midwest, New York, ERCOT and Other Power
Regions. See Note 24 - Segment Information of the Combined Notes to Consolidated Financial Statements for additional information.
Nuclear Facilities
Generation has ownership interests in fourteen nuclear generating stations currently in service, consisting of 24 units with an aggregate of 19,713 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, which owns Calvert Cliffs, Nine Mile Point
[excluding Long Island Power Authority's 18% undivided ownership interest in Nine Mile Point Unit 2] and Ginna nuclear stations. CENG is 100% consolidated in
Exelon's and Generation’s financial statements.
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 2018 , 2017 and 2016 electric supply (in GWh) generated from the nuclear generating
facilities was 68% , 69% and 67% , 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 2018 , 2017 and 2016 , the nuclear generating facilities operated by Generation achieved capacity factors of 94.6% , 94.1% and 94.6% , respectively.
The capacity factors reflect ownership percentage of stations operated by Generation and include CENG. 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, except for Peach Bottom Units 2 and 3, are categorized by the NRC in the Licensee Response Column, which is the highest of five performance
bands. As of January 29, 2019, the NRC categorized Peach Bottom Units 2 and 3 in the Regulatory Response Column, which is the second 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 under such Act or the
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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
2026
2029
2031
2034
2042
2043
2044
2049
2029
2046
2033
2034
2032
2032
2029
2036
2040
Three Mile Island (d)
__________
(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 advised the NRC that any license renewal application would not
2034
1974
1
be filed until the first quarter of 2021.
(c) On July 10, 2018, Generation submitted a second 20-year license renewal application to NRC for Peach Bottom Units 2 and 3.
(d) On May 30, 2017, Exelon announced that Generation will permanently cease generation operations at TMI on or about September 30, 2019 and has notified the NRC.
See Note 8 — Early Plant Retirements 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
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stations, which reflect the actual renewal of operating licenses for all of Generation’s operating nuclear generating stations except for TMI and Clinton. Beginning
in 2017, TMI depreciation provisions are based on its 2019 expected shutdown date. Beginning in 2016, Clinton depreciation provisions are based on an
estimated useful life of 2027 which is the last year of the Illinois Zero Emissions Standard. See Note 4 - Regulatory Matters of the Combined Notes to
Consolidated Financial Statements for additional information on FEJA and Note 8 — 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, 2018 , Generation had approximately 87,100 SNF assemblies ( 21,400 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 Oyster Creek, which is no longer operational. See the Decommissioning section below for additional information regarding Zion Station and
Oyster Creek. All currently operating Generation-owned nuclear sites have on-site dry cask storage, except for TMI, where such 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 22 — 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 Oyster Creek and 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 any of its nuclear stations, including the CENG nuclear
stations. Generation has reduced its financial exposure to these risks through insurance and other industry risk-sharing provisions. See “Nuclear Insurance”
within Note 22 — 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. The NDTs are
recorded in Exelon’s and Generation’s Consolidated Balance Sheets at December 31, 2018 at fair value of approximately $12.7 billion and have an estimated
targeted annual pre-tax return of 5% to 6.2% , while the Nuclear AROs are recorded in Exelon’s and Generation’s Consolidated Balance Sheets at
December 31, 2018 at approximately $10.0 billion and have an estimated 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. The NDTs and AROs include Oyster Creek balances classified as Assets held for sale
and Liabilities held for sale, respectively, in Exelon's and Generation's Consolidated Balance Sheets at December 31, 2018. 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 4 — Regulatory Matters , Note 5 -
Mergers, Acquisitions and Dispositions , Note 11 — Fair Value of Financial Assets and Liabilities and Note 15 — Asset Retirement Obligations of the Combined
Notes to Consolidated Financial Statements for additional information regarding Generation’s NDT funds and its decommissioning obligations.
Oyster Creek Generating Station . 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. On
September 17, 2018, Oyster Creek permanently ceased generation operations. See Note 5 - Mergers, Acquisitions and Dispositions and Note 15 — Asset
Retirement Obligations of the Combined Notes to Consolidated Financial Statements for additional information regarding the sale of Oyster Creek.
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.
Generation transferred to ZionSolutions substantially all of the assets (other than land) associated with Zion Station, including assets held in related NDT funds.
In consideration for Generation’s transfer of those assets, ZionSolutions assumed decommissioning and other liabilities, excluding the obligation to dispose of
SNF, associated with Zion Station. Pursuant to the ASA, ZionSolutions will periodically request reimbursement from the Zion Station-related NDT funds for costs
incurred related to the decommissioning efforts at Zion Station. However, ZionSolutions is subject to certain restrictions on its ability to request reimbursement;
specifically, if certain milestones as defined in the ASA are not met, all or a portion of requested reimbursements will be deferred until such milestones are met.
See Note 15 — Asset Retirement Obligations of the Combined Notes to Consolidated Financial Statements for additional information regarding Zion Station
decommissioning and Note 2 — Variable Interest Entities of the Combined Notes to Consolidated Financial Statements for a discussion of variable interest entity
considerations related to ZionSolutions.
Fossil and Renewable Facilities (including Hydroelectric)
At December 31, 2018 , Generation had ownership interests in 12,750 MW of capacity in generating facilities currently in service, consisting of 9,547 MW of
natural gas and oil, and 3,203 MW of renewables (wind, hydroelectric, solar and biomass). 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 2 — Variable Interest Entities of the Combined Notes to Consolidated Financial Statements for additional information
regarding certain of these entities which are VIEs. 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 2018 , 2017 and 2016 , electric supply (in GWh) generated from owned fossil and renewable generating facilities
was 11% , 12% and 10% , 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 — Exelon Generation
Company, LLC and ITEM 7. MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS — Exelon
Corporation , Executive Overview for additional information on Generation Renewable Development.
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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 46-year
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 includes actual and anticipated license renewal periods. See Note 4 — 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 13 — 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 .
Long-Term Power Purchase Contracts
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, 2018 :
Region
Mid-Atlantic
Midwest
New England
ERCOT
Other Power Regions
Total
Capacity Expiring (MW)
Number of
Agreements
Expiration
Dates
Capacity (MW)
14
2019 - 2032
2019 - 2026
2019 - 2021
2020 - 2031
2019 - 2030
4
7
5
11
41
237
834
40
1,524
2,549
5,184
2019
673
2020
1,020
2021
2022
2023
Thereafter
Total
826
298
167
2,200
5,184
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Fuel
The following table shows sources of electric supply in GWh for 2018 and 2017 :
Nuclear (a)
Purchases — non-trading portfolio
Fossil (primarily natural gas and oil)
Renewable (b)
Total supply
Source of Electric Supply
2018
2017
185,020
59,154
21,015
8,469
273,658
182,843
51,595
22,546
7,848
264,832
__________
(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 2018 and 2017 includes physical volumes of 35,100 GWh and 34,761 GWh, respectively, for CENG.
Includes wind, hydroelectric, solar and biomass generating assets.
(b)
The fuel costs per MWh for nuclear generation are less than those for fossil-fuel generation. Consequently, nuclear generation is generally the most cost-
effective way for Generation to meet its wholesale and retail load servicing requirements.
The cycle of production and utilization of nuclear fuel includes the mining and milling of uranium ore into uranium concentrates, 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 12 — 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
generating assets and power purchase agreements in multiple geographic regions. Power purchase agreements, including tolling arrangements, are
commitments related to power generation of specific generation plants and/or dispatch similar to an owned asset depending on the type of underlying asset. The
commodity risks associated with the output from generating assets and PPAs are 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 2019 and beyond for portions of its electricity portfolio
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that are unhedged. As of December 31, 2018 , the percentage of expected generation hedged for the Mid-Atlantic, Midwest, New York and ERCOT reportable
segments is 89% - 92% , 56% - 59% and 32% - 35% for 2019 , 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 generating facilities 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 ComEd, PECO, BGE, Pepco, DPL and ACE 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 2019 are approximately $2.0 billion , which includes Generation's share of the investment in the co-owned Salem plant and the total
capital expenditures for the fully consolidated CENG nuclear plants.
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, 2018 :
Service Territories
(in square miles)
Service Territory Population
Number of Customers
(in millions)
(in millions)
Total
Electric
Natural gas
Total
Electric
Natural gas
Total
Electric
Natural gas
11,400
11,400
2,100
3,250
640
5,400
2,800
1,900
2,300
640
5,400
2,800
n/a
1,900
3,050
n/a
275
n/a
9.5 (a)
4.0 (b)
3.1 (c)
2.4 (d)
1.4 (e)
1.1 (f)
9.5
4.0
3.0
2.4
1.4
1.1
n/a
2.5
2.9
n/a
0.6
n/a
4.0
1.7
1.3
0.9
0.5
0.6
4.0
1.6
1.3
0.9
0.5
0.6
n/a
0.5
0.7
n/a
0.1
n/a
ComEd
PECO
BGE
Pepco
DPL
ACE
__________
(a)
(b)
(c)
(d)
(e)
(f)
Includes approximately 2.7 million in the city of Chicago.
Includes approximately 1.6 million in the city of Philadelphia.
Includes approximately 0.6 million in the city of Baltimore.
Includes approximately 0.7 million in the District of Columbia.
Includes approximately 0.1 million in the city of Wilmington.
Includes approximately 0.1 million in the city of Atlantic City.
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) and ACE's rights are generally non-exclusive;
while PECO's, BGE's (electric) Pepco'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.
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Utility Regulations
State utility commissions regulate the Utility Registrants' electric and gas distribution rates and service, issuances of certain securities, and certain other aspects
of the business. The following table outlines the state commissions responsible for utility oversight.
Registrant
ComEd
PECO
BGE
Pepco
DPL
ACE
Commission
ICC
PAPUC
MDPSC
DCPSC/MDPSC
DPSC/MDPSC
NJBPU
The Utility Registrants are public utilities under the Federal Power Act subject to regulation by FERC related to transmission rates and certain other aspects of
the utilities' business. The U.S. Department of Transportation also regulates pipeline safety and other areas of gas operations for PECO, BGE and DPL.
Additionally, the Utility Registrants are subject to NERC mandatory reliability standards, which protect the nation's bulk power system against potential
disruptions from cyber and physical security breaches.
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 and 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 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
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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 4 — 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 the ICC, PAPUC, MDPSC, DCPSC, DPSC and
NJBPU. The Utility Registrants procure electricity supply from various approved bidders, including Generation. RTO spot market purchases and sales are
utilized to balance the utility electric load and supply as required. Charges incurred for electric supply procured through contracts with Generation are included in
Purchased power from affiliates on the Utility Registrants' Statements of Operations and Comprehensive Income.
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, 128,000 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% , 54% and 34% of PECO's, BGE’s and DPL's 2018 - 2019 heating season planned supplies,
3,800
257
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, for additional information regarding Utility
Registrants' contracts to procure electric supply and natural gas.
Energy Efficiency Programs
The Utility Registrants are allowed to recover costs associated with energy efficiency and demand response programs. 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.
The Utility Registrants are allowed to earn a return on their energy efficiency costs. See Note 4 — Regulatory Matters of the Combined Notes to Consolidated
Financial Statements for additional information.
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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. ComEd's, PECO's, BGE's, Pepco's, DPL's
and ACE's most recent estimates of capital expenditures for plant additions and improvements for 2019 are as follows:
(in millions)
ComEd
PECO
BGE
Pepco
DPL
ACE
Transmission Services
Transmission
Distribution
Gas
Total
Projected 2019 Capital Expenditure Spending
325
125
225
75
100
150
1,550
600
475
650
200
150
N/A
250
400
N/A
50
N/A
1,875
975
1,100
725
350
300
Under FERC’s open access transmission policy, the Utility Registrants, as owners of transmission facilities, are required to provide open access to their
transmission facilities under filed tariffs at cost-based rates approved by FERC. The Utility Registrants and their affiliates are required to comply with FERC’s
Standards of Conduct regulation governing the communication of non-public transmission information between the transmission owner’s employees and
wholesale merchant employees.
PJM is the regional grid operator and operates pursuant to FERC-approved tariffs. PJM is the transmission provider under, and the administrator of, the PJM
Open Access Transmission Tariff (PJM Tariff). PJM operates the PJM energy, capacity and other markets, and, through central dispatch, controls the day-to-day
operations of the bulk power system for the region. The Utility Registrants are members of PJM and provide regional transmission service pursuant to the PJM
Tariff. The Utility Registrants and the other transmission owners in PJM have turned over control of 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.
ComEd's transmission rates are established based on a formula that was approved by FERC in January 2008. BGE's, Pepco's, DPL's and ACE's transmission
rates are established based on a formula that was approved by FERC in April 2006. FERC’s orders establish the agreed-upon treatment of costs and revenues
in the determination of transmission rates and the process for updating the formula rate calculation on an annual basis.
On May 1, 2017, PECO filed a request with FERC seeking approval to update its transmission rate and change the manner in which PECO’s transmission rate is
determined from a fixed rate to a formula rate. The new formula was accepted by FERC effective as of December 1, 2017, subject to refund and set the matter
for hearing and settlement judge procedures. On May 4, 2018, the Chief Administrative Law Judge terminated settlement judge procedures and designated a
new presiding judge.
See Note 4 — Regulatory Matters of the Combined Notes to Consolidated Financial Statements for additional information regarding the PECO transmission
formula rate and transmission services.
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Employees
As of December 31, 2018 , Exelon and its subsidiaries had 33,383 employees in the following companies, of which 11,372 or 34% were covered by collective
bargaining agreements (CBAs):
Generation (c)
ComEd
PECO
BGE (d)
PHI (e)
Pepco (e)
DPL (e)
ACE (e)
Other (g)
Total
IBEW
Local 15 (a)
IBEW
Local 614 (b)
Other CBAs
Total
Employees
Covered by
CBAs
Total
Employees
1,568
3,378
—
—
—
—
—
—
62
84
—
1,381
—
—
—
—
—
—
5,008
1,465
2,485
—
—
—
277
1,023
684
386
44
4,899
4,137
3,378
1,381
—
277
1,023
684
386
106
11,372
14,110
6,152
2,708
3,025
1,258
1,423
940
612
3,155
33,383
__________
(a) A separate CBA between ComEd and IBEW Local 15 covers approximately 73 employees in ComEd’s System Services Group and will expire in 2020. Generation’s and
ComEd’s separate CBAs with IBEW Local 15 will expire in 2022.
(b) PECO craft and call center employees in the Philadelphia service territory are covered by CBAs with IBEW Local 614, both expiring in 2021. Additionally, Exelon Power,
an operating unit of Generation, has an agreement covering 84 employees, which expires in 2019.
(c) During 2018, Generation acquired and finalized its CBA with Distrigas Local 369, which will expire in 2020, and additionally, finalized a first collective bargaining
agreement, expiring in 2021, with a small unit of employees represented by IUOE Local 501 at Exelon's Hyperion Solutions facility. Also in 2018, Generation finalized a
three-year agreement with the Security Officer union at Braidwood and that CBA will expire in 2021. During 2017, Generation finalized CBAs with the Security Officer
unions at LaSalle, Limerick and Quad Cities, which all will expire in 2020 and Dresden expiring in 2021. Additionally, during 2017, Generation acquired and combined two
CBAs at FitzPatrick into one CBA covering both craft and security employees, which will expire in 2023. During 2016, Generation finalized its CBA with the Security Officer
union at Oyster Creek, expiring in 2022 and New Energy IUOE Local 95-95A, which will expire in 2021. Also, during 2016, Generation finalized a 5-year agreement with
the New England ENEH, UWUA Local 369, which will expire in 2022. During 2015, Generation finalized its CBA with Clinton Local 51 which will expire in 2020; its two
CBAs with Local 369 at Mystic 7 and Mystic 8/9, both expiring in 2020; and three Security Officer unions at Byron, Clinton and TMI, all expiring between 2019 and 2021,
respectively. During 2014, Generation finalized CBAs with TMI Local 777 and Oyster Creek Local 1289, expiring in 2019 and 2021, respectively. Also in 2014, CENG
finalized its CBA with Nine Mile Point which will expire in 2020.
In January 2017, an election was held at BGE which resulted in union representation for certain employees, who numbered 1,284 at the end of 2018. BGE and IBEW
Local 410 are negotiating an initial agreement which could result in some modifications to wages, hours and other terms and conditions of employment. No agreement has
been finalized to date and management cannot predict the outcome of such negotiations.
(d)
(e) PHI’s utility subsidiaries are parties to five CBAs with four local unions. CBAs are generally renegotiated every three to five years. All these CBAs were renegotiated in
2014 and were extended through various dates ranging from October 2018 through June 2020. During 2018, ACE finalized a five-year agreement with Local 210, expiring
in 2023.
(f) Other includes shared services employees at BSC.
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
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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 Generation, ComEd, PECO, BGE, PHI, Pepco, DPL and ACE. 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 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 ComEd, PECO, BGE, Pepco,
DPL and ACE 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, the 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.
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Pursuant to discussions with the NJDEP in 2010 regarding the application of Section 316(b) to Oyster Creek, Generation agreed to permanently cease
generation operations at Oyster Creek before the expiration of its operating license in 2029. On September 17, 2018, Oyster Creek permanently ceased
generation operations, and its cooling water intake system is no longer subject to Section 316(b). See Note 8 - Early Plant Retirements of the Combined Notes
to Consolidated Financial Statements for additional information about the sale and decommissioning of Oyster Creek.
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 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, ComEd, PECO, BGE, Pepco, DPL and ACE 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 22 — Commitments and Contingencies of the Combined Notes to Consolidated Financial Statements for additional information regarding solid and
hazardous waste regulation and legislation.
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 2019 for compliance with environmental remediation related to contamination at former MGP sites and other gas purification sites is expected to
total $ 46 million , consisting of $ 36 million , $ 6 million and $4 million at ComEd, PECO and BGE respectively. The Utility Registrants also have contingent
liabilities for
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environmental remediation of non-MGP contaminants (e.g., PCBs). As of December 31, 2018 , 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, ComEd, PECO, BGE, Pepco, DPL and ACE may be required to make significant additional expenditures not presently determinable for
other environmental remediation costs.
See Note 4 — Regulatory Matters and Note 22 — 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
greenhouse gas (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 (CO 2 e) emitted per unit of electricity generated, is among the lowest in the industry. As of
December 31, 2018 , fossil fuel generation represented approximately 29% of Exelon's owned generating capacity, while fossil fuel-fired generation during 2018
represented less than 11% of Exelon's overall generation on a MWh basis. 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 information regarding the market and
financial, regulatory and legislative, and operational risks associated with climate change.
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 21 st 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.
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 proposed and finalized regulations for fossil fuel-fired power plants, referred to as the Clean Power Plan, which are
currently being litigated. Under the Trump Administration, on October
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16, 2017 the EPA proposed 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. Subsequently, on August 31, 2018, EPA proposed its Affordable Clean Energy Rule
(ACE), which would 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.
Given litigation uncertainty and the absence of a final ACE rule, Exelon and Generation cannot at this time predict the impacts of regulation of existing power
plants, or individual state responses to developments related to final resolution of the CPP and ACE regulations, 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 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 CO 2 emissions.
Non-emitting resources do not have to purchase or hold these allowances.
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 CO 2 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 ACE 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 4 — Regulatory Matters of the Combined Notes to Consolidated Financial Statements for additional information on renewable portfolio standards.
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Executive Officers of the Registrants as of February 8, 2019
Exelon
Name
Crane, Christopher M.
Age Position
60 Chief Executive Officer, Exelon;
Chairman, ComEd, PECO & BGE
Chairman, PHI
President, Exelon
President, Generation
Cornew, Kenneth W.
53 Senior Executive Vice President and Chief Commercial Officer, Exelon;
President and CEO, Generation
Executive Vice President and Chief Commercial Officer, Exelon
President and Chief Executive Officer, Constellation
Pramaggiore, Anne R.
60
Senior Executive Vice President, Exelon; Chief Executive Officer, Exelon
Utilities
Chief Executive Officer, ComEd
President, ComEd
Dominguez, Joseph
56 Chief Executive Officer, ComEd
Executive Vice President, Governmental & Regulatory Affairs and Public
Policy, Exelon
Period
2012 - Present
2012 - Present
2016 - Present
2008 - Present
2008 - 2013
2013 - Present
2013 - Present
2012 - 2013
2012 - 2013
2018 - Present
2012 - 2018
2009 - 2018
2018 - Present
2015 - 2018
Senior Vice President, Governmental & Regulatory Affairs and Public Policy,
Exelon
2012 - 2015
Innocenzo, Michael A.
53 President and Chief Executive Officer, PECO
Senior Vice President and Chief Operations Officer, PECO
Butler, Calvin G.
49 Chief Executive Officer, BGE
Senior Vice President, Regulatory and External Affairs, BGE
Senior Vice President, Corporate Affairs, Exelon
Velazquez, David M.
59 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
2014 - Present
2013 - 2014
2011 - 2013
2016 - Present
2009 - Present
2009 - 2016
Von Hoene Jr., William A.
65 Senior Executive Vice President and Chief Strategy Officer, Exelon
2012 - Present
Nigro, Joseph
54 Senior Executive Vice President and Chief Financial Officer, Exelon
2018 - Present
Executive Vice President, Exelon; Chief Executive Officer, Constellation
2013 - 2018
Aliabadi, Paymon
56 Executive Vice President and Chief Risk Officer, Exelon
Managing Director, Gleam Capital Management
2013 - Present
2012 - 2013
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Name
Souza, Fabian E.
Generation
Age Position
48 Senior Vice President and Corporate Controller, Exelon
Senior Vice President and Deputy Controller, Exelon
Period
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
Deputy Corporate Controller, The AES Corporation
2014 - 2014
Assistant Corporate Controller, Global Controllership, The AES Corporation
2013 - 2014
Controller, Global Utilities, The AES Corporation
2011 - 2013
Name
Cornew, Kenneth W.
Age Position
53 Senior Executive Vice President and Chief Commercial Officer, Exelon;
President and CEO, Generation
Executive Vice President and Chief Commercial Officer, Exelon
President and Chief Executive Officer, Constellation
Period
2013 - Present
2013 - Present
2012 - 2013
2012 - 2013
Pacilio, Michael J.
58 Executive Vice President and Chief Operating Officer, Exelon Generation
2015 - Present
President, Exelon Nuclear; Senior Vice President
2010 - 2015
and Chief Nuclear Officer, Generation
Hanson, Bryan C
53
President and Chief Nuclear Officer, Exelon Nuclear; Senior Vice President,
Exelon Generation
2015 - Present
McHugh, James
47 Executive Vice President, Exelon; Chief Executive Officer, Constellation
2018 - Present
Senior Vice President, Portfolio Management & Strategy, Constellation
Vice President, Portfolio Management, Constellation
Barnes, John
55 Senior Vice President, Generation; President, Exelon Power
Senior Vice President, Generation, Senior Vice President and Chief Operating
Officer, Exelon Power
Wright, Bryan P.
52 Senior Vice President and Chief Financial Officer, Generation
Senior Vice President, Corporate Finance, Exelon
Bauer, Matthew N.
42 Vice President and Controller, Generation
Vice President and Controller, BGE
Vice President of Power Finance, Exelon Power
27
2016 - 2018
2012 - 2016
2018 - Present
2012 - 2018
2013 - Present
2012 - 2013
2016 - Present
2014 - 2016
2012 - 2014
Table of Contents
ComEd
Name
Dominguez, Joseph
Age Position
56 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.
58 President and Chief Operating Officer, ComEd
Executive Vice President and Chief Operating Officer, ComEd
2018 - Present
2012 - 2018
Jones, Jeanne M.
39 Senior Vice President, Chief Financial Officer and Treasurer, ComEd
2018 - Present
Vice President, Finance, Exelon Nuclear
Director, Finance, Exelon Nuclear
Park, Jane
46 Senior Vice President, Customer Operations, ComEd
Vice President, Regulatory Policy & Strategy, ComEd
Director, Business Strategy & Technology, ComEd
Chief of Staff to President and Chief Executive Officer, ComEd
Gomez, Veronica
49
Senior Vice President, Regulatory and Energy Policy and General Counsel,
ComEd
2014 - 2018
2013 - 2014
2018 - Present
2016 - 2018
2014 - 2016
2012 - 2014
2017 - Present
Vice President and Deputy General Counsel, Litigation, Exelon
2012 - 2017
Marquez Jr., Fidel
57 Senior Vice President, Governmental and External Affairs, ComEd
2012 - Present
McGuire, Timothy M.
60 Senior Vice President, Distribution Operations, ComEd
Vice President, Transmission and Substations, ComEd
Kozel, Gerald J.
46 Vice President, Controller, ComEd
Assistant Corporate Controller, Exelon
2016 - Present
2010 - 2016
2013 - Present
2012 - 2013
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PECO
Name
Innocenzo, Michael A.
Age
Position
53 President and Chief Executive Officer, PECO
Senior Vice President and Chief Operations Officer, PECO
McDonald, John
61 Senior Vice President and Chief Operations Officer, PECO
Vice President, Integration, Pepco Holdings
Vice President, Technical Services
Period
2018 - Present
2012 - 2018
2018 - Present
2016 - 2018
2006 - 2016
Stefani, Robert J.
44 Senior Vice President, Chief Financial Officer and Treasurer, PECO
2018 - Present
Vice President, Corporate Development, Exelon
Director, Corporate Development, Exelon
Murphy, Elizabeth A.
59 Senior Vice President, Governmental and External Affairs, PECO
Vice President, Governmental and External Affairs, PECO
Webster Jr., Richard G.
57 Vice President, Regulatory Policy and Strategy, PECO
Feldhake, Lauren
53 Vice President, Customer Operations, PECO
Diaz Jr., Romulo L.
Bailey, Scott A.
Director, Customer Care, PECO
Director, Customer Financial Operations, PECO
72 Vice President and General Counsel, PECO
42 Vice President and Controller, PECO
29
2015 - 2018
2012 - 2015
2016 - Present
2012 - 2016
2012 - Present
2017 - Present
2014 - 2017
2009 - 2014
2012 - Present
2012 - Present
Table of Contents
BGE
Name
Butler, Calvin G.
Age
Position
49 Chief Executive Officer, BGE
Senior Vice President, Regulatory and External Affairs, BGE
Senior Vice President, Corporate Affairs, Exelon
Woerner, Stephen J.
51 President, BGE
Chief Operating Officer, BGE
Senior Vice President, BGE
Period
2014 - Present
2013 - 2014
2011 - 2013
2014 - Present
2012 - Present
2009 - 2014
Vahos, David M.
46 Senior Vice President, Chief Financial Officer and Treasurer, BGE
2016 - Present
Núñez, Alexander G.
47 Senior Vice President, Regulatory and External Affairs, BGE
Vice President, Chief Financial Officer and Treasurer, BGE
Vice President and Controller, BGE
Case, Mark D.
Oddoye, Rodney
Corse, John
Vice President, Governmental and External Affairs, BGE
Director, State Affairs, BGE
57 Vice President, Strategy and Regulatory Affairs, BGE
42 Vice President, Customer Operations, BGE
Director, Northeast Regional Electric Operations, BGE
Director, Financial Operations, BGE
Manager, Distribution Operations, BGE
58 Vice President and General Counsel, BGE
Associate General Counsel, Exelon
Holmes, Andrew W.
50 Vice President and Controller, BGE
Director, Generation Accounting, Exelon
Director, Derivatives and Technical Accounting, Exelon
30
2014 - 2016
2012 - 2014
2016 - Present
2013 - 2016
2012 - 2013
2012 - Present
2018 - Present
2016 - 2018
2015 - 2016
2013 - 2015
2018 - Present
2012 - 2018
2016 - Present
2013 - 2016
2008 - 2013
Table of Contents
PHI, Pepco, DPL and ACE
Name
Velazquez, David M.
Age
Position
59 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
54 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
55
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
49
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.
46
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 - Present
McGowan, Kevin M.
57 Vice President, Regulatory Policy and Strategy, PHI, Pepco, DPL and ACE
2016 - Present
Aiken, Robert
52 Vice President and Controller, PHI, Pepco, DPL and ACE
Vice President and Controller, Generation
Vice President, Regulatory Affairs, Pepco Holdings, Inc.
2012 - 2016
2016 - Present
2012 - 2016
ITEM 1A.
RISK FACTORS
Each of the Registrants operates in a market and regulatory environment that poses significant risks, many of which are beyond that Registrant’s control.
Management of each Registrant regularly meets with the Chief Risk Officer and the Registrant's Risk Management Committee (RMC), which comprises officers
of the Registrant, to identify and evaluate the most significant risks of the Registrant's business and the appropriate steps to manage and mitigate those risks.
The Chief Risk Officer and senior executives of the Registrants discuss those risks with the Finance and Risk Committee and Audit Committee of the Exelon
Board of Directors and the ComEd, PECO, BGE and PHI Boards of Directors. In addition, the Generation Oversight Committee of the Exelon Board of Directors
evaluates risks related to the generation business. The risk factors discussed below could adversely affect one or more of the Registrants’ consolidated financial
statements and the market prices of their publicly traded securities. Each of the Registrants has disclosed the known material risks that affect its business at this
time. However, there may be further risks and uncertainties that are not presently known or that are not currently believed by a Registrant to be material that
could adversely affect its performance or financial condition in the future.
Exelon's consolidated financial statements are affected to a significant degree by: (1) Generation’s position as a predominantly nuclear generator selling power
into competitive energy markets with a concentration in select regions
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and (2) the role of the Utility Registrants as operators of electric transmission and distribution systems in six of the largest metropolitan areas in the United
States. Factors that affect the consolidated financial statements of the Registrants fall primarily under the following categories, all of which are discussed in
further detail below:
• Market and Financial Factors. Exelon’s and Generation’s results of operations are affected by price fluctuations in the energy markets. Power prices
are a function of supply and demand, which in turn are driven by factors such as (1) the price of fuels, in particular the price of natural gas, which affects
the prices that Generation can obtain for the output of its power plants, (2) the presence of other generation resources in the markets in which
Generation’s output is sold, (3) the demand for electricity in the markets where the Registrants conduct their business, (4) the impacts of on-going
competition in the retail channel and (5) emerging technologies and business models.
•
•
Regulatory and Legislative Factors. The regulatory and legislative factors that affect the Registrants include changes to the laws and regulations that
govern competitive markets and utility regulatory business model cost recovery, tax policy, zero emission credit programs and environmental policy. In
particular, Exelon’s and Generation’s financial performance could be affected by changes in the design of competitive wholesale power markets or
Generation’s ability to sell power in those markets. In addition, potential regulation and legislation, including regulation or legislation regarding climate
change and renewable portfolio standards (RPS), could have significant effects on the Registrants. Also, returns for the Utility Registrants are influenced
significantly by state regulation and regulatory proceedings.
Operational Factors. The Registrants’ operational performance is subject to those factors inherent in running the nation’s largest fleet of nuclear power
reactors and large electric and gas distribution systems. The safe, secure and effective operation of the nuclear facilities and the ability to effectively
manage the associated decommissioning obligations as well as the ability to maintain the availability, reliability, safety and security of its energy delivery
systems are fundamental to Exelon’s ability to achieve value-added growth for customers, communities and shareholders. Additionally, the operating
costs of the Registrants and the opinions of their customers, regulators and shareholders are affected by those companies’ ability to maintain the
reliability, safety and efficiency of their energy delivery systems.
A discussion of each of these risk categories and other risk factors is included below.
Market and Financial Factors
Generation is exposed to depressed prices in the wholesale and retail power markets, which could negatively affect its consolidated
financial statements (Exelon and Generation).
Generation is exposed to commodity price risk for the unhedged portion of its electricity generation supply portfolio. Generation’s earnings and cash flows are
therefore exposed to variability of spot and forward market prices in the markets in which it operates.
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Price of Fuels. The spot market price of electricity for each hour is generally determined by the marginal cost of supplying the next unit of electricity to the
market during that hour. Thus, the market price of power is affected by the market price of the marginal fuel used to generate the electricity unit.
Demand and Supply. The market price for electricity is also affected by changes in the demand for electricity and the available supply of electricity. Unfavorable
economic conditions, milder than normal weather, and the growth of energy efficiency and demand response programs could each depress demand. In addition,
in some markets, the supply of electricity could often exceed demand during some hours of the day, resulting in loss of revenue for base-load generating plants
such as Exelon'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 natural gas and power prices and low market volatility, retail competitors can aggressively pursue
market share because the barriers to entry can be low and wholesale generators (including Generation) use their retail operations to hedge generation
output. Increased or more aggressive competition could adversely affect overall gross margins and profitability in Generation’s retail operations.
Sustained low market prices or depressed demand and over-supply could adversely affect Exelon’s and Generation’s consolidated financial statements and
such impacts 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 Exelon’s and 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 Exelon's and Generation's result of operations through accelerated depreciation expense, impairment charges
related to inventory that cannot be used at other nuclear units and cancellation of in-flight capital projects, accelerated amortization of plant specific nuclear fuel
costs, severance costs, accelerated asset retirement obligation expense related to future decommissioning activities, and additional funding of decommissioning
costs, which can be offset in whole or in part by reduced operating and maintenance expenses. See Note 8 — Early Plant Retirements of the Combined Notes to
Consolidated Financial Statements for additional information.
In addition to price fluctuations, Generation is exposed to other risks in the power markets that are beyond its control and could
negatively affect its results of operations (Exelon and Generation).
Credit Risk. In the bilateral markets, Generation is exposed to the risk that counterparties that owe Generation money, or are obligated 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, 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, the purpose of which is to spread such risk across all market participants. 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.
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, including
technologies related to energy generation, distribution and consumption (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
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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 materially affect the
Registrants’ consolidated financial statements through, among other things, reduced operating revenues, increased operating and maintenance expenses, and
increased capital expenditures, as well as 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. If future increases in pension and other
postretirement costs as a result of reduced plan assets or other factors cannot be recovered, or cannot be recovered in a timely manner, from the Utility
Registrants' customers, the consolidated financial statements of the Utility Registrants could be negatively affected. Ultimately, if the Registrants are unable to
manage the investments within the NDT funds and benefit plan assets and are unable to manage the related benefit plan liabilities and the related asset
retirement obligations, their consolidated financial statements could be negatively impacted.
Unstable capital and credit markets and increased volatility in commodity markets could adversely affect the Registrants’ businesses in
several ways, including the availability and cost of short-term funds for liquidity requirements, the Registrants’ ability to meet long-term
commitments, Generation’s ability to hedge effectively its generation portfolio, and the competitiveness and liquidity of energy markets;
each could negatively impact the Registrants’ consolidated financial statements (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 if internal funds are not available from the Registrants’ respective operations. Disruptions in the capital and credit
markets in the United States or abroad could adversely affect the Registrants’ ability to access the capital markets or draw on their respective bank revolving
credit facilities. The Registrants’ access to funds under their credit facilities depends on the ability of the banks that are parties to the facilities to meet their
funding commitments. Those 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 from the Registrants and other borrowers 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, 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, 2018 , approximately 19% , or $1.8 billion ,
19% , or $1.8 billion , and 18% , or $1.7 billion of the Registrants’ available credit facilities were with European, Canadian and Asian banks, respectively. The
credit facilities include $9.7 billion (including bilateral credit facilities and credit facilities for project
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finance) in aggregate total commitments of which $8.0 billion was available as of December 31, 2018 . As of December 31, 2018 , there were no borrowings
under Generation's bilateral credit facilities. See Note 13 — 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 adversely 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, which could have a material adverse effect on Exelon’s and Generation’s consolidated financial statements.
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. Generation could experience a downgrade in
its ratings if any of the credit rating agencies concludes that the level of business or financial risk and overall creditworthiness of the power generation industry in
general, or Generation in particular, has deteriorated. 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 on such arrangements may be a significant
assumption in performing impairment assessments of the 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. Given the relationship to forward market prices, contract collateral
requirements can be volatile. In addition, if the Utility Registrants were downgraded, they could experience higher borrowing costs as a result of the downgrade.
A Utility Registrant could experience a downgrade in its ratings if any of the credit rating agencies concludes that the level of business or financial risk and
overall creditworthiness of the utility industry in general, or a Utility Registrant in particular, has deteriorated. A Utility Registrant could experience a downgrade if
its current regulatory environment becomes less predictable by materially lowering returns for the Utility Registrant or adopting other measures to limit utility
rates. Additionally, the ratings for a Utility Registrant could be downgraded if its financial results are weakened from current levels due to weaker operating
performance or due to a failure to properly manage its capital structure. In addition, changes in ratings methodologies by the agencies could also have a
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 financial performance could be negatively affected by price volatility, availability and other risk factors associated with the
procurement of nuclear and fossil fuel (Exelon and Generation).
Generation depends on nuclear fuel and fossil fuels to operate most of its generating facilities. Nuclear fuel is obtained predominantly through long-term uranium
supply contracts, contracted conversion services, contracted enrichment services, or a combination thereof, and contracted fuel fabrication services. Natural gas
and oil are procured for generating plants through annual, short-term and spot-market purchases. The supply markets for nuclear fuel, natural gas and oil are
subject to price fluctuations, availability restrictions and counterparty default that could negatively affect the consolidated financial statements for Generation.
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 business or consolidated financial statements.
Financial performance and load requirements could be adversely affected if Generation is unable to effectively manage its power portfolio
(Exelon and Generation).
A significant portion of Generation’s power portfolio is used to provide power under procurement contracts with the Utility Registrants and other customers. To
the extent portions of the power portfolio are not needed for that purpose, Generation’s output is sold in the wholesale power markets. To the extent its power
portfolio is not sufficient to meet the requirements of its customers under the related agreements, Generation must purchase power in the wholesale power
markets. Generation’s financial results could be negatively affected if it is unable to cost-effectively meet the load requirements of its customers, manage its
power portfolio or effectively address the changes in the wholesale power markets.
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Challenges to tax positions taken by the Registrants as well as tax law changes and the inherent difficulty in quantifying potential tax
effects of business decisions, could impact the Registrants’ consolidated financial statements. (All Registrants).
Corporate Tax Reform. On December 22, 2017, President Trump signed into law the TCJA. See Note 14 - Income Taxes of the Combined Notes to
Consolidated Financial Statements for additional information.
While the Registrants’ current tax accounting and future expectations are based on management’s present understanding of the provisions under the TCJA,
further interpretive guidance of the TCJA’s provisions could result in further adjustments that could have a material impact to the Registrants’ future consolidated
financial statements.
The Utility Registrants have made their best estimate regarding the probability and timing of settlements of net regulatory liabilities established pursuant to the
TCJA. However, the amount and timing of the settlements may change based on decisions and actions by the rate regulators, which could have a material
impact on the Utility Registrants’ future consolidated financial statements.
Tax reserves. The Registrants are required to make judgments in order to estimate their obligations to taxing authorities. These tax obligations include income,
real estate, sales and use and employment-related taxes and ongoing appeal issues related to these tax matters. These judgments include reserves established
for potential adverse outcomes regarding tax positions that have been taken that could be subject to challenge by the tax authorities. See Note 1 — Significant
Accounting Policies and Note 14 — Income Taxes of the Combined Notes to Consolidated Financial Statements for additional information.
Increases in customer rates, including increases in the cost of purchased power and increases in natural gas prices for the Utility
Registrants, and the impact of economic downturns could lead to greater expense for uncollectible customer balances. Additionally,
increased rates could lead to decreased volumes delivered. Both of these factors could decrease Generation’s and the Utility Registrants'
results from operations, cash flows or financial positions (All Registrants).
The impacts of economic downturns on the Utility Registrants' customers, such as unemployment for residential customers and 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', which would negatively affect the Utility Registrants' consolidated financial statements. Generation's customer-
facing energy delivery activities face similar economic downturn risks, such as lower volumes sold and increased expense for uncollectible customer balances
which could negatively affect Generation's consolidated financial statements. See ITEM 7A. QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT
MARKET RISK for additional information of the Registrants’ credit risk.
The Utility Registrants' current procurement plans include purchasing power through contracted suppliers and in the spot market. ComEd’s, PECO’s and ACE's
costs of purchased power are charged to customers without a return or profit component. BGE's, Pepco's and DPL's SOS rates charged to customers recover
their wholesale power supply costs and include a return component. For PECO and DPL, purchased natural gas costs are charged to customers with no return
or profit component. For BGE, purchased natural gas costs are charged to customers using a MBR mechanism that compares the actual cost of gas to a market
index. The difference between the actual cost and the market index is shared equally between shareholders and customers. Purchased power and natural gas
prices fluctuate based on their relevant supply and demand. Significantly higher rates related to purchased power and natural gas could result in declines in
customer usage, lower revenues and potentially additional uncollectible accounts expense for the Utility Registrants. In addition, any challenges by the
regulators or the Utility Registrants as to the recoverability of these costs could have a material adverse effect in the Registrants’ consolidated financial
statements. Also, the Utility Registrants' cash flows could be adversely affected by differences between the time period when electricity and natural gas are
purchased and the ultimate recovery from customers.
The effects of weather could impact the Registrants’ consolidated financial statements (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
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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.
Pursuant to the Future Energy Jobs Act (FEJA), beginning in 2017, customer rates for ComEd 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. These extreme
conditions could have detrimental effects in the Utility Registrants' consolidated financial statements. 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 have an adverse effect by causing 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.
Certain long-lived assets and other assets recorded on the Registrants’ statements of financial position could become
impaired, which would result in write-offs of the impaired amounts (All Registrants).
Long-lived assets represent the single largest asset class on the Registrants’ statements of financial position. In addition, Exelon and Generation have significant
balances related to unamortized energy contracts, as further disclosed in Note 10 — Intangible Assets of the Combined Notes to Consolidated Financial
Statements. 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 when evaluating long-lived assets for potential impairment. An impairment would require
the Registrants to reduce the carrying value of the long-lived asset to fair value through a non-cash charge to expense by the amount of the impairment, and
such an impairment could have a material adverse impact in the Registrants’ consolidated financial statements.
As of December 31, 2018 , Exelon's $6.7 billion carrying amount of goodwill primarily consists of $2.6 billion at ComEd relating to the acquisition of ComEd in
2000 upon the formation of Exelon and $4.0 billion at PHI primarily resulting from Exelon's acquisition of PHI in the first quarter of 2016. Under GAAP, goodwill
remains at its recorded amount unless it is determined to be impaired, which is generally based upon an annual analysis that compares the implied fair value of
the goodwill to its carrying value. If an impairment occurs, the amount of the impaired goodwill will be written-off to expense, which will also reduce equity. The
actual timing and amounts of any goodwill impairments will depend on many sensitive, interrelated and uncertain variables. Such an impairment would result in a
non-cash charge to expense, which could have a material adverse impact on Exelon's, ComEd's, and PHI's results of operations.
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, which could be material.
See ITEM 7. MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS — Critical Accounting Policies
and Estimates, Note 6 — Property, Plant and Equipment, Note 7 — Impairment of Long-Lived Assets and Intangibles and Note 10 — Intangible Assets of the
Combined Notes to the Consolidated Financial Statements for additional information on long-lived asset and goodwill impairments.
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Exelon and its subsidiaries at times guarantee the performance of third parties, which could result in substantial costs in the event of
non-performance by such third parties. In addition, the Registrants could have rights under agreements which obligate third parties to
indemnify the Registrants for various obligations, and the Registrants could incur substantial costs in the event that the applicable
Registrant is unable to enforce those agreements or the applicable third-party is otherwise unable to perform. The Registrants could also
incur substantial costs in the event that third parties are entitled to indemnification related to environmental or other risks in connection
with the acquisition and divestiture of assets (All Registrants).
Some of the Registrants have issued guarantees of the performance of third parties, which obligate the Registrant or its subsidiaries 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. Such performance guarantees could have a material impact in the consolidated financial statements of the Registrant. Some of 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 and such costs could adversely affect a Registrant’s consolidated financial
statements.
Some of 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, which could adversely impact
that Registrant’s consolidated financial statements. Each of the Utility Registrants has transferred its former generation business to a third party and in each
case the transferee may have 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 may 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, which could impact that Utility Registrant's consolidated financial statements. In addition, the Utility Registrants may have
residual liability under certain laws in connection with their former generation facilities.
Regulatory and Legislative Factors
The Registrants’ generation and energy delivery businesses are highly regulated and could be subject to regulatory and legislative
actions that adversely affect their consolidated financial statements. Fundamental changes in regulation or legislation or violation of
tariffs or market rules and anti-manipulation laws, could disrupt the Registrants’ business plans and adversely affect their operations,
cash flows or financial results (All Registrants).
Substantially all aspects of the businesses of the Registrants are subject to comprehensive Federal or state regulation and legislation. Further, Exelon’s and
Generation’s consolidated financial statements are significantly affected by Generation's sales and purchases of commodities at market-based rates, as
opposed to cost-based or other similarly regulated rates, and Exelon’s and 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. Similarly, there is risk
that financial market regulations could increase the Registrants’ compliance costs and limit their ability to engage in certain transactions. In the planning and
management of operations, the Registrants must address the effects of regulation on their businesses and changes in the regulatory framework, including
initiatives by Federal and state legislatures, RTOs, exchanges, ratemaking agencies and taxing authorities. Additionally, the Registrants need to be cognizant
and understand rule changes or Registrant actions that could result in potential violation of tariffs, market rules and anti-manipulation laws. Fundamental
changes in regulations or other adverse legislative actions affecting the Registrants’ businesses would require changes in their business planning models and
operations and could negatively impact their respective consolidated financial statements.
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State and federal regulatory and legislative developments related to emissions, climate change, tax reform, capacity market mitigation, energy price information,
resilience, fuel diversity and RPS could also significantly affect Exelon’s and Generation’s consolidated financial statements. The Registrants cannot predict
when or whether legislative and regulatory proposals could become law or what their effect will be on the Registrants.
Legislative and regulatory efforts in Illinois, New York and New Jersey to preserve the environmental attributes and reliability benefits of zero-emission nuclear-
powered generating facilities through zero emission credit programs are subject to legal challenges and, if overturned, could negatively impact Exelon’s and
Generation’s consolidated financial statements and result in the early retirement of certain of Generation’s nuclear plants.
Generation could be negatively affected by possible Federal or state legislative or regulatory actions that could affect the scope and
functioning of the wholesale markets (Exelon and Generation).
Approximately 63% 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 will depend on (1) FERC’s continued adherence to and support for, policies that favor
the preservation of competitive wholesale power markets and recognize the value of zero-carbon electricity and resiliency and (2) the absence of material
changes to market structures that would limit or otherwise negatively affect market competition. Generation could also be adversely affected by state laws,
regulations or initiatives designed to reduce wholesale prices artificially below competitive levels or to subsidize existing or new generation.
FERC’s requirements for market-based rate authority, established in Order 697 and 816 and related subsequent orders, could pose a risk that Generation may
no longer satisfy FERC’s tests for market-based rates. Since Order 697 became final in June 2007, Generation has obtained orders affirming Generation’s
authority to sell at market-based rates and none denying that authority.
The Dodd-Frank Wall Street Reform and Consumer Protection Act (the Act) was enacted in July 2010. The part of the Act that affects Exelon most significantly
is Title VII, which is known as the Dodd-Frank Wall Street Transparency and Accountability Act (Dodd-Frank). Dodd-Frank requires a new regulatory regime
for over-the-counter swaps (swaps), including mandatory clearing for certain categories of swaps, incentives to shift swap activity to exchange trading, margin
and capital requirements, and other obligations designed to promote transparency. The primary aim of Dodd-Frank is to regulate the key intermediaries in the
swaps market, which entities are swap dealers (SDs), major swap participants (MSPs), or certain other financial entities, but the law also applies to a lesser
degree to end-users of swaps. The CFTC’s Dodd-Frank regulations generally preserved the ability of end users in the energy industry to hedge their risks using
swaps without being subject to mandatory clearing, and many of the other substantive regulations that apply to SDs, MSPs, and other financial entities.
Generation manages, and expects to be able to continue to manage, its commercial activity to ensure that it does not have to register as an SD or MSP or other
type of covered financial entity.
There are some rulemaking proceedings that have not yet been finalized, in particular, proposed rules on position limits that would apply to both Exchange-
traded futures contracts and economically-equivalent over-the-counter swaps. Although the company would incur some costs associated with monitoring and
compliance with such rules, it does not expect the rules to have a material impact on its business operations.
The Utility Registrants could also be subject to some Dodd-Frank requirements to the extent they were to enter into swaps. However, at this time, management
of the Utility Registrants continue to expect that their companies will not be materially affected by Dodd-Frank.
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
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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 and contributions to rate-relief packages.
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. The Registrants have incurred and expect to incur significant costs related to environmental compliance, site remediation
and clean-up. 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 Note 22 — Commitments and Contingencies of the Combined Notes to Consolidated Financial Statements for additional
information.
Additionally, Generation is subject to exposure for asbestos-related personal injury liability alleged at certain current and formerly owned generation
facilities. Future legislative action could require Generation to make a material contribution to a fund to settle lawsuits for alleged asbestos-related disease and
exposure.
In some cases, a third-party who has acquired assets from a Registrant has assumed the liability the Registrant could otherwise have for environmental matters
related to the transferred property. If the transferee is unable, or fails, to discharge the assumed liability, a regulatory authority or injured person could attempt to
hold the Registrant responsible, and the Registrant’s remedies against the transferee could be limited by the financial resources of the transferee. See Note 22
— Commitments and Contingencies of the Combined Notes to Consolidated Financial Statements for additional information.
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. The proceedings generally have
timelines that may not be limited by statute. 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.
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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 Utility Registrants cannot predict the ultimate outcomes of any settlements or the actions by Illinois, Pennsylvania, Maryland, the District of Columbia,
Delaware, New Jersey or Federal regulators in establishing rates, including the extent, if any, to which certain costs such as significant capital projects will be
recovered or what rates of return will be allowed. Nevertheless, the expectation is that the Utility Registrants will continue to be obligated to deliver electricity to
customers in their respective service territories and will also retain significant default service obligations, referred to as POLR, DSP, SOS and BGS, to provide
electricity and natural gas to certain groups of customers in their respective service areas who do not choose an alternative supplier. The ultimate outcome and
timing of regulatory rate proceedings have a significant effect on the ability of the Utility Registrants, as applicable, to recover their costs or earn an adequate
return and could have a material adverse effect in the Utility Registrants' consolidated financial statements. See Note 4 — Regulatory Matters of the Combined
Notes to the Consolidated Financial Statements for additional information regarding rate proceedings.
Federal or additional state RPS and/or energy conservation legislation, along with energy conservation by customers, could negatively
affect the consolidated financial statements of Generation and the Utility Registrants (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, have increased capital expenditures and could significantly impact the Utility Registrants 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 Exelon, Generation and the Utility Registrants. For additional information, see ITEM 1.
BUSINESS — Environmental Regulation — Renewable and Alternative Energy Portfolio Standards.
The impact of not meeting the criteria of the FASB guidance for accounting for the effects of certain types of regulation could be material
to Exelon and the Utility Registrants (Exelon and the Utility Registrants).
As of December 31, 2018 , Exelon and the Utility Registrants have concluded that the operations of the Utility Registrants meet the criteria of the authoritative
guidance for accounting for the effects of certain types of regulation. If it is concluded in a future period that a separable portion of their businesses no longer
meets the criteria, Exelon, and the Utility Registrants would be required to eliminate the financial statement effects of regulation for that part of their business.
That action would include the elimination of any or all regulatory assets and liabilities that had been recorded in their Consolidated Balance Sheets and the
recognition of a one-time charge in their Consolidated Statements of Operations and Comprehensive Income. The impact of not meeting the criteria of the
authoritative guidance could be material to the financial statements of Exelon and the Utility Registrants. The impacts and resolution of the above items could
lead to an impairment of ComEd's or PHI’s goodwill, which could be significant and at least partially offset the gains at ComEd discussed above. A significant
decrease in equity as a result of any changes could limit the ability of the Utility Registrants to pay dividends under Federal and state law and no longer meeting
the regulatory accounting criteria could cause significant volatility in future results of operations. See Note 1 — Significant Accounting Policies , Note 4 —
Regulatory Matters and Note 10 — Intangible Assets of the Combined Notes to Consolidated Financial Statements for additional information regarding
accounting for the effects of regulation, regulatory matters and ComEd’s and PHI's goodwill, respectively.
Exelon and Generation could incur material costs of compliance if Federal and/or state regulation or legislation is adopted to address
climate change (Exelon and Generation).
Various stakeholders, including legislators and regulators, shareholders and non-governmental organizations, as well as other companies in many business
sectors, including utilities, are considering ways to address the effect of GHG emissions on climate change. If carbon reduction regulation or legislation becomes
effective, Exelon and Generation could incur costs either to limit further the GHG emissions from their operations or to procure emission
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allowance credits. See ITEM 1. BUSINESS — Global Climate Change and Note 22 — Commitments and Contingencies of the Combined Notes to Consolidated
Financial Statements for additional information regarding climate change.
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).
As a result of the Energy Policy Act of 2005, 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. 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 mandatory reliability standards, they could be subject to remediation costs as well as sanctions, which could include substantial monetary
penalties.
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.
See Note 4 — Regulatory Matters and Note 22 — Commitments and Contingencies of the Combined Notes to Consolidated Financial Statements for additional
information.
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 have large consumer customer bases and as a result could be the subject of public criticism focused on the operability of their assets and
infrastructure and quality of their service. Adverse publicity of this nature could render legislatures and other governing bodies, public service commissions and
other regulatory authorities, and government officials 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). The imposition of any of the foregoing could have a material negative
impact on the Registrants' business or consolidated financial statements.
The Registrants cannot predict the outcome of the legal proceedings relating to their business activities. An adverse determination could
negatively impact their consolidated financial statements (All Registrants).
The Registrants are involved in legal proceedings, claims and litigation arising out of their business operations, the most significant of which are summarized in
Note 22 — 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, any of which could have a material adverse effect in the Registrants’
consolidated financial statements.
Generation could be negatively affected by possible Nuclear Regulatory Commission actions that could affect the operations and
profitability of its nuclear generating fleet (Exelon and Generation).
Regulatory risk. A change in the Atomic Energy Act or the applicable regulations or licenses could require a substantial increase in capital expenditures or
could result in increased operating or decommissioning costs and significantly affect Generation’s consolidated financial statements. Events at nuclear plants
owned by others, as well as those owned by Generation, could cause the NRC to initiate such actions.
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Spent nuclear fuel storage. The approval of a national repository for the storage of SNF, such as the one previously considered at Yucca Mountain, Nevada,
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. The NRC’s temporary storage rule (also referred to as the “waste confidence decision”) recognizes that licensees can
safely store SNF at nuclear power plants for up to 60 years beyond the original and renewed licensed operating life of the plants.
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. Through May 15, 2014, in accordance with the NWPA and Generation’s contract with the DOE, Generation paid the DOE a fee per kWh of net nuclear
generation for the cost of SNF disposal. This fee was discontinued effective May 16, 2014. Until such time as a new fee structure is in effect, Exelon and
Generation will not accrue any further costs related to SNF disposal fees. Generation cannot predict what, if any, fee will be established in the future for SNF
disposal. However, such a fee could be material to Generation's consolidated financial statements. See Note 22 — Commitments and Contingencies of the
Combined Notes to Consolidated Financial Statements for additional information on the SNF obligation.
Operational Factors
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 their 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.
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, such as seismic
activity, fires resulting from natural causes such as lightning, extreme weather events, changes in temperature and precipitation patterns, changes to ground and
surface water availability, sea level rise and other related phenomena. Severe weather or other natural disasters could be destructive, 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. Additionally, natural disasters and other events that
have an adverse effect on the economy in general could adversely affect the Registrants’ consolidated financial statements and their ability to raise capital.
The impact that potential terrorist attacks could have on the industry and on Exelon is uncertain. As owner-operators of infrastructure facilities, such as nuclear,
fossil and hydroelectric generation facilities and electric and gas transmission and distribution facilities, 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 cyber security 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, which could adversely affect the Registrants’ consolidated financial statements and their ability to raise
capital. In addition, the implementation of security guidelines and measures has resulted in and is expected to continue to result in increased costs.
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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, resulting in decreased service levels and increased costs.
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.
Generation’s financial performance could be negatively affected by matters arising from its ownership and operation of nuclear facilities
(Exelon and Generation).
Nuclear capacity factors. Capacity factors for generating units, particularly capacity factors for nuclear generating units, significantly affect Generation’s results
of operations. Nuclear plant operations involve substantial fixed operating costs but produce electricity at low variable costs due to nuclear fuel costs typically
being lower than fossil fuel costs. Consequently, to be successful, Generation must consistently operate its nuclear facilities at high capacity factors. Lower
capacity factors increase Generation’s 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 has to shutdown 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 nuclear plants not owned by Generation could result in increased regulation and reduced public
support for nuclear-fueled energy, which could significantly affect Generation’s consolidated financial statements. 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. Although the safety record of nuclear reactors generally has been very good, accidents and other unforeseen problems have
occurred both in the United States and abroad. 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. Uninsured losses and other expenses, to the extent not recovered from insurers or the nuclear industry, could be
borne by Generation and could have a material adverse effect in Generation’s consolidated financial statements. 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 and significantly adversely affect Generation’s consolidated financial statements.
Nuclear insurance. 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
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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 $14.1 billion limit for a single incident.
Generation is a member of an industry mutual insurance company, NEIL, which provides property and business interruption insurance for Generation’s nuclear
operations. In previous years, NEIL has made distributions to its members but Generation cannot predict the level of future distributions or if they will occur at all.
See Note 22 — 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 is required to provide to the NRC
a biennial report by unit (annually for units that have been retired and units that are within five years of retirement) addressing Generation’s ability to meet the
NRC-estimated funding levels including scheduled contributions to and earnings on the NDT funds. The NRC funding levels are based upon the assumption that
decommissioning will commence after the end of the current licensed life of each unit.
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. No assurance can be given that the costs of such decommissioning will not 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.
The performance of capital markets could significantly affect the value of the trust funds. Currently, Generation is making 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 and Exelon’s and Generation’s consolidated financial statements could be
significantly affected. See Note 15 — Asset Retirement Obligations of the Combined Notes to Consolidated Financial Statements for additional information.
Forecasting trust fund investment earnings and costs to decommission nuclear generating stations requires significant judgment, and actual results could differ
significantly from current estimates. Ultimately, 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. As a result, Generation’s consolidated financial statements could be significantly adversely affected. Additionally, if the
pledged assets are not sufficient to fund the Zion Station decommissioning activities under the Asset Sale Agreement (ASA), Generation could have to seek
remedies available under the ASA to reduce the risk of default by ZionSolutions and its parent. See Note 15 — Asset Retirement Obligations of the Combined
Notes to Consolidated Financial Statements for additional information.
For nuclear units that are subject to regulatory agreements with either the ICC or the PAPUC, decommissioning-related activities are generally offset within
Exelon’s and Generation’s Consolidated Statements of Operations and Comprehensive Income. The offset of decommissioning-related activities within the
Consolidated Statements 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 a corresponding regulatory liability.
If the expected value in the NDT funds for any nuclear unit subject to the regulatory agreements with the ICC is expected to not exceed the total
decommissioning obligation for that unit, the accounting to offset decommissioning-
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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
consolidated financial statements could be material. For the nuclear units subject to the regulatory agreements with the PAPUC, 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 consolidated financial statements could be material. If the accounting to
offset decommissioning-related activities is discontinued, any remaining balances in noncurrent payables to affiliates at Generation and ComEd's or PECO’s
noncurrent affiliate receivable from Generation and corresponding regulatory liability may need to be reversed and could have a material impact in Generation’s
Consolidated Statement of Operations and Comprehensive Income.
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. The license for the Muddy Run Pumped Storage Project expires on December 1, 2055. The license for the Conowingo Hydroelectric Project expired
on September 1, 2014. FERC issued an annual license, effective as of the expiration of the previous license. If FERC does not issue a license prior to the
expiration of the annual license, the annual license renews automatically. 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 and significantly affect Generation’s consolidated financial statements. 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.
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. These operational systems and infrastructure have been in service for many years. 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’ respective consolidated financial statements could be adversely affected if they were unable to
effectively manage their capital projects or raise the necessary capital. Furthermore, operational failure of electric or gas systems, generation facilities or
infrastructure could result in potential liability if such failure results in damage to property or injury to individuals. See ITEM 1. BUSINESS for additional
information regarding the Registrants’ potential future capital expenditures.
The Utility Registrants' operating costs, and customers’ and regulators’ opinions of the Utility Registrants 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, including information systems, used in the Utility Registrants' delivery systems could interrupt the electric transmission and
electric and natural gas delivery, which could negatively impact related revenues, and increase 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, the Utility Registrants' consolidated financial statements could be negatively impacted. Furthermore, if
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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. If an employee or third party causes the operational systems to fail, either as a result of inadvertent error or by deliberately tampering with
or manipulating the operational systems, the Utility Registrants' financial results could also 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.
The aforementioned failures or those of other utilities, including prolonged or repeated failures, could affect customer satisfaction and the level of regulatory
oversight and the Utility Registrants' maintenance and capital expenditures. 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, and those
damages could be material to ComEd’s consolidated financial statements.
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 with consequent effects on operating costs, revenues and results of operations. 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.
The electricity transmission facilities of the Utility Registrants are interconnected with the transmission facilities of neighboring utilities and are part of the
interstate power transmission grid that is operated by PJM RTO. Although 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, there can be no assurance that
service interruptions at other utilities will not cause interruptions in the Utility Registrants’ service areas. If the Utility Registrants were to suffer such a service
interruption, it could have a negative impact in their and Exelon’s consolidated financial statements.
The Registrants are subject to physical security and cybersecurity risks (All Registrants).
The Registrants face physical security and cybersecurity risks as the owner-operators of generation, transmission and distribution facilities and as participants in
commodities trading. 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 Exelon or another Registrant and its
customer supply activities could be adversely affected, customer confidence in the Registrants or others in the industry could be diminished, or Exelon and its
subsidiaries could be subject to legal claims, loss of revenues, increased costs, operations shutdown, etc., any of which could contribute to the loss of customers
and have a negative impact on the business and/or consolidated financial statements. 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
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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.
Failure to attract and retain an appropriately qualified workforce could negatively impact the Registrants’ consolidated financial
statements (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. If the Registrants are unable to successfully attract and retain an appropriately qualified workforce, their consolidated financial statements
could be negatively impacted.
The Registrants could make investments in new business initiatives, including initiatives mandated by regulators, and markets that may
not be successful, and acquisitions could not 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 liquefied natural gas. Such initiatives could involve significant risks and
uncertainties, including distraction of management from current operations, inadequate return on capital, and unidentified issues not discovered in the diligence
performed prior to launching an initiative or entering a market. As these markets mature, there could be new market entrants or expansion by established
competitors that increase competition for customers and resources. 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 Smart Grid and utility of the future initiatives and other non-regulatory mandated
initiatives. These risks include, but are not limited to, cost recovery, regulatory concerns, cybersecurity and obsolescence of technology. Due to these risks, no
assurance can be given that such initiatives will be successful and will not have a material adverse effect in the Utility Registrants' consolidated financial
statements.
The Registrants may not realize or achieve the anticipated cost savings through the cost management efforts which could impact the
Registrants’ results of operations (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 describes Generation’s interests in net electric generating capacity by station at December 31, 2018 :
Station (a)
Region
Location
No. of
Units
Percent
Owned (b)
Primary
Fuel Type
Primary
Dispatch
Type (c)
Net Generation
Capacity (MW) (d)
Braidwood
Byron
LaSalle
Dresden
Quad Cities
Clinton
Michigan Wind 2
Beebe
Michigan Wind 1
Harvest 2
Harvest
Beebe 1B
Ewington
Marshall
City Solar
Solar Ohio
Blue Breezes
CP Windfarm
Southeast Chicago
Clinton Battery Storage
Total Midwest
Limerick
Peach Bottom
Salem
Calvert Cliffs
Three Mile Island
Conowingo
Criterion
Midwest
Midwest
Midwest
Midwest
Midwest
Midwest
Midwest
Midwest
Midwest
Midwest
Midwest
Midwest
Midwest
Midwest
Midwest
Midwest
Midwest
Midwest
Midwest
Midwest
Mid-Atlantic
Mid-Atlantic
Mid-Atlantic
Mid-Atlantic
Mid-Atlantic
Mid-Atlantic
Mid-Atlantic
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
Lyon 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
9
1
2
2
2
8
1
75
51
51
51
51
51
51
99
99
51
Sanatoga, PA
2
Delta, PA
Lower Alloways
Creek Township, NJ
Lusby, MD
Middletown, PA
Darlington, MD
Oakland, MD
50
42.59
50.01
51
2
2
2
1
11
28
50
Uranium
Uranium
Uranium
Uranium
Uranium
Uranium
Wind
Wind
Wind
Wind
Wind
Wind
Wind
Wind
Solar
Solar
Wind
Wind
Gas
Energy Storage
Uranium
Uranium
Uranium
Uranium
Uranium
Hydroelectric
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
Peaking
Peaking
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)(g)
42 (e)(h)
35 (e)(g)
30 (e)(g)
27 (e)(g)
26 (e)(g)
20 (e)
19 (e)
9
4
3
2 (e)(g)
296 (k)
10
11,939
2,317
1,324 (e)
1,002 (e)
895 (e)(f)
837 (j)
572
36 (e)(g)
Table of Contents
Station (a)
Region
Location
No. of
Units
Percent
Owned (b)
Primary
Fuel Type
Primary
Dispatch
Type (c)
Net Generation
Capacity (MW) (d)
Fair Wind
Solar Maryland MC
Fourmile
Solar New Jersey 1
Solar New Jersey 2
Solar Horizons
Solar Maryland
Solar Maryland 2
Mid-Atlantic
Mid-Atlantic
Mid-Atlantic
Mid-Atlantic
Mid-Atlantic
Mid-Atlantic
Mid-Atlantic
Mid-Atlantic
Garrett County, MD
Various, MD
Garrett County, MD
Various, NJ
Various, NJ
Emmitsburg, MD
12
40
16
5
2
1
Various, MD
11
Various, MD
Constellation New Energy
Mid-Atlantic
Gaithersburg, MD
Solar Federal
Solar New Jersey 3
Solar DC
Muddy Run
Eddystone 3, 4
Perryman
Croydon
Handsome Lake
Notch Cliff
Westport
Richmond
Gould Street
Philadelphia Road
Eddystone
Fairless Hills
Delaware
Mid-Atlantic
Mid-Atlantic
Mid-Atlantic
Mid-Atlantic
Mid-Atlantic
Mid-Atlantic
Mid-Atlantic
Mid-Atlantic
Mid-Atlantic
Mid-Atlantic
Mid-Atlantic
Mid-Atlantic
Mid-Atlantic
Mid-Atlantic
Mid-Atlantic
Mid-Atlantic
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
Baltimore, MD
Eddystone, PA
Fairless Hills, PA
Philadelphia, PA
3
1
1
5
1
8
2
5
8
5
8
1
2
1
4
4
2
4
51
51
51
51
Wind
Solar
Wind
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
Base-load
30
36
20 (e)(g)
18
11
8 (e)(g)
8
8
5
5
1 (e)(g)
1
Hydroelectric
Intermediate
1,070
Oil/Gas
Oil/Gas
Oil
Gas
Gas
Gas
Oil
Gas
Oil
Oil
Landfill Gas
Oil
Intermediate
Peaking
Peaking
Peaking
Peaking
Peaking
Peaking
Peaking
Peaking
Peaking
Peaking
Peaking
760
404
391
268
117 (k)
116 (k)
98
97 (k)
61
60
60 (k)
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Station (a)
Region
Location
No. of
Units
Percent
Owned (b)
Primary
Fuel Type
Primary
Dispatch
Type (c)
Net Generation
Capacity (MW) (d)
Southwark
Falls
Moser
Riverside
Chester
Schuylkill
Salem
Pennsbury
Bethlehem
Eastern
Total Mid-Atlantic
Whitetail
Sendero
Constellation Solar Texas
Colorado Bend II
Wolf Hollow II
Handley 3
Handley 4, 5
Total ERCOT
Solar
Massachusetts
Holyoke Solar
Solar Net Metering
Solar Connecticut
Mystic 8, 9
Mystic 7
Wyman
West Medway
Mid-Atlantic
Mid-Atlantic
Philadelphia, PA
Morrisville, PA
Mid-Atlantic Lower PottsgroveTwp., PA
Mid-Atlantic
Mid-Atlantic
Mid-Atlantic
Mid-Atlantic
Mid-Atlantic
Mid-Atlantic
Mid-Atlantic
Baltimore, MD
Chester, PA
Philadelphia, PA
Lower Alloways
Creek Township, NJ
Morrisville, PA
Bethlehem, PA
Bethlehem, PA
ERCOT
Webb County, TX
Jim Hogg and Zapata
County, TX
4
3
3
2
3
2
1
2
1
3
42.59
57
39
51
51
ERCOT
Other
ERCOT
ERCOT
ERCOT
ERCOT
New England
New England
New England
New England
New England
New England
New England
New England
Various, TX
11
Wharton, TX
Granbury, TX
Fort Worth, TX
Fort Worth, TX
3
3
1
2
Various, MA
10
Various, MA
Uxbridge, MA
Various, CT
Charlestown, MA
Charlestown, MA
Yarmouth, ME
West Medway, MA
2
1
1
6
1
1
3
52
5.9
Oil
Oil
Oil
Oil
Oil
Oil
Oil
Landfill Gas
Landfill Gas
Landfill Gas
Wind
Wind
Solar
Gas
Gas
Gas
Gas
Solar
Solar
Solar
Solar
Gas
Oil/Gas
Oil
Oil
Peaking
Peaking
Peaking
Peaking
Peaking
Peaking
Peaking
Peaking
Peaking
Peaking
52
51
51
39 (k)(l)
39
30
16 (e)
4 (e)
4 (k)
4 (k)
10,982
Base-load
46 (e)(g)
Base-load
Base-load
Intermediate
Intermediate
Intermediate
Peaking
Base-load
Base-load
Base-load
Base-load
Intermediate
Intermediate
Intermediate
Peaking
40 (e)(g)
13
1,088
1,064
395
870
3,516
7
5
2
1
1,417
573 (m)
35 (e)
123
Table of Contents
Station (a)
Region
Location
No. of
Units
Percent
Owned (b)
Primary
Fuel Type
Primary
Dispatch
Type (c)
Net Generation
Capacity (MW) (d)
Framingham
Mystic Jet
Total New England
Nine Mile Point
FitzPatrick
Ginna
Solar New York
Total New York
Antelope Valley
Bluestem
Exelon Wind 4
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
Exelon Wind 5
Exelon Wind 6
Exelon Wind 7
Exelon Wind 8
Exelon Wind 9
Exelon Wind 10
Exelon Wind 11
New England
New England
Framingham, MA
Charlestown, MA
New York
New York
New York
New York
Scriba, NY
Scriba, NY
Ontario, NY
Bethlehem, NY
3
1
2
1
1
1
1
60
38
65
1
Lancaster, CA
Beaver County, OK
Gruver, TX
Kiowa County, KS
Albany, GA
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
Texhoma, TX
Texhoma, TX
Sunray, TX
Sunray, TX
Sunray, TX
Dumas, TX
Dumas, TX
27
89
24
24
25
53
20
19
21
4
14
13
10
8
8
8
8
8
8
8
53
50.01
50.01
51
51
99
51
51
51
51
51
50.49
51
51
51
51
Oil
Oil
Peaking
Peaking
Uranium
Uranium
Uranium
Solar
Solar
Wind
Wind
Wind
Biomass
Solar
Wind
Solar
Wind
Wind
Solar
Solar
Wind
Wind
Wind
Solar
Wind
Wind
Wind
Wind
Wind
Wind
Wind
Wind
Wind
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
31
9 (m)
2,203
838 (e)(f)
842
288 (e)(f)
3
1,971
242
101 (e)(g)(h)
80
53 (e)(g)
52 (i)
46
29 (e)(g)
27
26 (e)(g)
26 (e)(g)
23
21
21 (e)(g)
20 (e)(g)
17 (e)(g)
15 (e)(g)
15 (e)(g)
14 (e)(g)
10 (e)(g)
10
10
10
10
10
10
10
Other
Other
Other
Other
Other
Other
Other
Other
Other
Other
Other
Other
Other
Other
Other
Other
Other
Other
Other
Other
Other
Other
Other
Other
Other
Other
Table of Contents
Station (a)
Region
Location
No. of
Units
Percent
Owned (b)
Primary
Fuel Type
Primary
Dispatch
Type (c)
Net Generation
Capacity (MW) (d)
High Plains
Solar Georgia 2
Tuana Springs
Solar Georgia
Greensburg
Outback Solar
Echo 3
Three Mile Canyon
Loess Hills
California PV Energy 3
Mohave Sunrise Solar
Denver Airport
Solar
Hillabee
Grande Prairie
SEGS 4, 5, 6
Total Other
Total
Other
Other
Other
Other
Other
Other
Other
Other
Other
Other
Other
Other
Other
Other
Other
Panhandle, TX
Various, GA
Hagerman, ID
Various, GA
Greensburg, KS
Christmas Valley, OR
Echo, OR
Boardman, OR
Rock Port, MO
Various, CA
Fort Mohave, AZ
Denver, CO
Alexander City, AL
Alberta, Canada
99.5
51
51
50.49
51
51
8
8
8
10
10
1
6
6
4
10
1
1
3
1
Boron, CA
3
4.2-12.2
Wind
Solar
Wind
Solar
Wind
Solar
Wind
Wind
Wind
Solar
Solar
Solar
Gas
Gas
Solar
Base-load
Base-load
Base-load
Base-load
Base-load
Base-load
Base-load
Base-load
Base-load
Base-load
Base-load
Base-load
Intermediate
Peaking
Peaking
10 (e)
10
9 (e)(g)
8
7 (e)(g)
6
5 (e)(g)
5 (e)(g)
5
5
5
2 (e)(g)
753
105
9 (e)
1,852
32,463
__________
(a) All nuclear stations are boiling water reactors except Braidwood, Byron, Calvert Cliffs, Ginna, Salem and Three Mile Island, which are pressurized water reactors.
(b) 100%, unless otherwise indicated.
(c) Base-load units are plants that normally operate to take all or part of the minimum continuous load of a system and, consequently, produce electricity at an essentially
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 50.01% interest in CENG, a joint venture with EDF. For Nine Mile Point, the co-owner owns 18% of Unit 2. Thus, Exelon’s ownership is 50.01% of
82% of Nine Mile Point Unit 2.
(g) Reflects the sale of 49% of EGRP to a third party on July 6, 2017. See Note 2 — 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 announced it will permanently cease generation operations at TMI on or about September 30, 2019. See Note 8 — Early Plant Retirements of the
Combined Notes to Consolidated Financial Statements for additional information.
(k) Generation has agreed to retire and cease generation operations at the Gould Street, Fairless Hills, Eastern, Bethlehem, Southeast Chicago, Notch Cliff, Riverside (unit
8), Westport and Pennsbury units on or before June 1, 2020.
(l) Generation plans to retire and cease generation operation at Riverside (unit 7) on or about March 14, 2019.
(m) Generation plans to retire and cease generation operation at the Mystic 7 and Mystic Jet units on or about June 1, 2022.
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.
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Generation maintains property insurance against loss or damage to its principal plants and properties by fire or other perils, subject to certain exceptions. For
additional information regarding nuclear insurance of generating facilities, see ITEM 1. BUSINESS — Exelon Generation Company, LLC . For its insured losses,
Generation is self-insured to the extent that any losses are within the policy deductible or exceed the amount of insurance maintained. Any such losses could
have a material adverse effect in Generation’s consolidated financial condition or results of operations.
ComEd
ComEd’s electric substations and a portion of its transmission rights of way are located on property that ComEd owns. A significant portion of its electric
transmission and distribution facilities is located above or underneath highways, streets, other public places or property that others own. ComEd believes that it
has satisfactory rights to use those places or property in the form of permits, grants, easements, licenses and franchise rights; however, it has not necessarily
undertaken to examine the underlying title to the land upon which the rights rest.
Transmission and Distribution
ComEd’s high voltage electric transmission lines owned and in service at December 31, 2018 were as follows:
Voltage (Volts)
765,000
345,000
138,000
Circuit Miles
90
2,716
2,209
ComEd’s electric distribution system includes 35,398 circuit miles of overhead lines and 32,010 circuit miles of underground lines.
First Mortgage and Insurance
The principal properties of ComEd are subject to the lien of ComEd’s Mortgage dated July 1, 1923, as amended and supplemented, under which ComEd’s First
Mortgage Bonds are issued.
ComEd maintains property insurance against loss or damage to its properties by fire or other perils, subject to certain exceptions. For its insured losses, ComEd
is self-insured to the extent that any losses are within the policy deductible or exceed the amount of insurance maintained. Any such losses could have a
material adverse effect in the consolidated financial condition or results of operations of ComEd.
PECO
PECO’s electric substations and a significant portion of its transmission lines are located on property that PECO owns. A significant portion of its electric
transmission and distribution facilities is located above or underneath highways, streets, other public places or property that others own. PECO believes that it
has satisfactory rights to use those places or property in the form of permits, grants, easements and licenses; however, it has not necessarily undertaken to
examine the underlying title to the land upon which the rights rest.
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Table of Contents
Transmission and Distribution
PECO’s high voltage electric transmission lines owned and in service at December 31, 2018 were as follows:
Voltage (Volts)
500,000
230,000
138,000
69,000
Circuit Miles
188
549
135
181
(a)
__________
(a)
In addition, PECO has a 22.00% ownership interest in 127 miles of 500 kV lines located in Pennsylvania and a 42.55% ownership interest in 131 miles of 500 kV lines
located in Delaware and New Jersey.
PECO’s electric distribution system includes 12,957 circuit miles of overhead lines and 9,367 circuit miles of underground lines.
Gas
The following table sets forth PECO’s natural gas pipeline miles at December 31, 2018 :
Transmission
Distribution
Service piping
Total
Pipeline Miles
9
6,912
6,377
13,298
PECO has an LNG facility located in West Conshohocken, Pennsylvania that has a storage capacity of 1,200 mmcf and a send-out capacity of 160 mmcf/day
and a propane-air plant located in Chester, Pennsylvania, with a tank storage capacity of 105 mmcf and a peaking capability of 25 mmcf/day. In addition, PECO
owns 30 natural gas city gate stations and direct pipeline customer delivery points at various locations throughout its gas service territory.
First Mortgage and Insurance
The principal properties of PECO are subject to the lien of PECO’s Mortgage dated May 1, 1923, as amended and supplemented, under which PECO’s first and
refunding mortgage bonds are issued.
PECO maintains property insurance against loss or damage to its properties by fire or other perils, subject to certain exceptions. For its insured losses, PECO is
self-insured to the extent that any losses are within the policy deductible or exceed the amount of insurance maintained. Any such losses could have a material
adverse effect in the consolidated financial condition or results of operations of PECO.
BGE
BGE’s electric substations and a significant portion of its transmission lines are located on property that BGE owns. A significant portion of its electric
transmission and distribution facilities is located above or underneath highways, streets, other public places or property that others own. BGE believes that it has
satisfactory rights to use those places or property in the form of permits, grants, easements and licenses; however, it has not necessarily undertaken to examine
the underlying title to the land upon which the rights rest.
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Table of Contents
Transmission and Distribution
BGE’s high voltage electric transmission lines owned and in service at December 31, 2018 were as follows:
Voltage (Volts)
500,000
230,000
138,000
115,000
Circuit Miles
218
358
55
706
BGE’s electric distribution system includes 9,191 circuit miles of overhead lines and 17,295 circuit miles of underground lines.
Gas
The following table sets forth BGE’s natural gas pipeline miles at December 31, 2018 :
Transmission
Distribution
Service piping
Total
Pipeline Miles
161
7,348
6,305
13,814
BGE has an LNG facility located in Baltimore, Maryland that has a storage capacity of 1,056 mmcf and a send-out capacity of 332 mmcf/day and a propane-air
plant located in Baltimore, Maryland, with a storage capacity of 550 mmcf and a send-out capacity of 85 mmcf/day. In addition, BGE owns 12 natural gas city
gate stations and 20 direct pipeline customer delivery points at various locations throughout its gas service territory.
Property Insurance
BGE owns its principal headquarters building located in downtown Baltimore. BGE maintains property insurance against loss or damage to its properties by fire
or other perils, subject to certain exceptions. For its insured losses, BGE 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 the consolidated financial condition or results of operations of
BGE.
Pepco
Pepco’s electric substations and a significant portion of its transmission lines are located on property that Pepco owns. A significant portion of its electric
transmission and distribution facilities is located above or underneath highways, streets, other public places or property that others own. Pepco believes that it
has satisfactory rights to use those places or property in the form of permits, grants, easements and licenses; however, it has not necessarily undertaken to
examine the underlying title to the land upon which the rights rest.
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Table of Contents
Transmission and Distribution
Pepco’s high voltage electric transmission lines owned and in service at December 31, 2018 were as follows:
Voltage (Volts)
500,000
230,000
138,000
115,000
Circuit Miles
142
767
61
38
Pepco’s electric distribution system includes approximately 4,127 circuit miles of overhead lines and 7,039 circuit miles of underground lines. Pepco also
operates a distribution system control center in Bethesda, Maryland. The computer equipment and systems contained in Pepco’s control center are financed
through a sale and leaseback transaction.
First Mortgage and Insurance
The principal properties of Pepco are subject to the lien of Pepco’s mortgage dated July 1, 1935, as amended and supplemented, under which Pepco First
Mortgage Bonds are issued.
Pepco maintains property insurance against loss or damage to its properties by fire or other perils, subject to certain exceptions. For its insured losses, Pepco 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 the consolidated financial condition or results of operations of Pepco.
DPL
DPL’s electric substations and a significant portion of its transmission lines are located on property that DPL owns. A significant portion of its electric
transmission and distribution facilities is located above or underneath highways, streets, other public places or property that others own. DPL believes that it has
satisfactory rights to use those places or property in the form of permits, grants, easements and licenses; however, it has not necessarily undertaken to examine
the underlying title to the land upon which the rights rest.
Transmission and Distribution
DPL’s high voltage electric transmission lines owned and in service at December 31, 2018 were as follows:
Voltage (Volts)
500,000
230,000
138,000
69,000
Circuit Miles
16
471
586
569
DPL’s electric distribution system includes approximately 6,031 circuit miles of overhead lines and 6,298 circuit miles of underground lines. DPL also owns and
operates a distribution system control center in New Castle, Delaware.
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Gas
The following table sets forth DPL’s natural gas pipeline miles at December 31, 2018 :
Transmission (a)
Distribution
Service piping
Total
Pipeline Miles
8
2,065
1,398
3,471
___________
(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.
DPL owns a liquefied natural gas facility located in Wilmington, Delaware, with a storage capacity of approximately 250 mmcf and an emergency sendout
capability of 36 mmcf/day. DPL owns 4 natural gas city gate stations at various locations in New Castle County, Delaware. These stations have a total primary
delivery point contractual entitlement of 158 mmcf/day.
First Mortgage and Insurance
The principal properties of DPL are subject to the lien of DPL’s mortgage dated October 1, 1947, as amended and supplemented, under which DPL First
Mortgage Bonds are issued.
DPL maintains property insurance against loss or damage to its properties by fire or other perils, subject to certain exceptions. For its insured losses, DPL 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 the consolidated financial condition or results of operations of DPL.
ACE
ACE’s electric substations and a significant portion of its transmission lines are located on property that ACE owns. A significant portion of its electric
transmission and distribution facilities is located above or underneath highways, streets, other public places or property that others own. ACE believes that it has
satisfactory rights to use those places or property in the form of permits, grants, easements and licenses; however, it has not necessarily undertaken to examine
the underlying title to the land upon which the rights rest.
Transmission and Distribution
ACE’s high voltage electric transmission lines owned and in service at December 31, 2018 were as follows:
Voltage (Volts)
500,000
230,000
138,000
69,000
Circuit Miles
—
221
239
663
ACE’s electric distribution system includes approximately 7,378 circuit miles of overhead lines and 2,927 circuit miles of underground lines. ACE also owns and
operates a distribution system control center in Mays Landing, New Jersey.
First Mortgage and Insurance
The principal properties of ACE are subject to the lien of ACE’s mortgage dated January 15, 1937, as amended and supplemented, under which ACE First
Mortgage Bonds are issued.
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Table of Contents
ACE maintains property insurance against loss or damage to its properties by fire or other perils, subject to certain exceptions. For its insured losses, ACE 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 the consolidated financial condition or results of operations of ACE.
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 4 — Regulatory Matters and Note 22 — Commitments and Contingencies of the Combined Notes to Consolidated
Financial Statements. Such descriptions are incorporated herein by these references.
ITEM 4.
MINE SAFETY DISCLOSURES
All Registrants
Not Applicable to the Registrants.
60
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 New York Stock Exchange (trading symbol: EXC). As of January 31, 2019 , there were 969,745,933 shares of common
stock outstanding and approximately 99,857 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 2014 through 2018 .
This performance chart assumes:
•
•
$100 invested on December 31, 2013 in Exelon common stock, in the S&P 500 Stock Index and in the S&P Utility Index; and
All dividends are reinvested.
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Table of Contents
Value of Investment at December 31,
2013
$100
$100
$100
2014
$140.61
$113.68
$128.98
2015
$109.44
$115.24
$122.73
2016
$145.34
$129.02
$142.72
2017
$167.22
$157.17
$160.00
2018
$197.86
$150.27
$166.57
Exelon Corporation
S&P 500
S&P Utilities
Generation
As of January 31, 2019 , Exelon indirectly held the entire membership interest in Generation.
ComEd
As of January 31, 2019 , there were 127,021,331 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, 2019 , in addition to Exelon, there were 294 record holders of ComEd common stock. There is no established market
for shares of the common stock of ComEd.
PECO
As of January 31, 2019 , there were 170,478,507 outstanding shares of common stock, without par value, of PECO, all of which were indirectly held by Exelon.
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BGE
As of January 31, 2019 , 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, 2019 , Exelon indirectly held the entire membership interest in PHI.
Pepco
As of January 31, 2019 , 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, 2019 , 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, 2019 , 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, 2018 , Exelon had retained earnings of $14,766 million , including Generation’s undistributed earnings of $3,724 million , ComEd’s retained
earnings of $1,337 million consisting of retained earnings appropriated for future dividends of $2,976 million , partially offset by $1,639 million of unappropriated
accumulated deficits, PECO’s retained earnings of $1,242 million , BGE’s retained earnings of $1,640 million , and PHI's undistributed earnings of $62 million .
The following table sets forth Exelon’s quarterly cash dividends per share paid during 2018 and 2017 :
(per share)
Exelon
Fourth
Quarter
Third
Quarter
Second
Quarter
First
Quarter
Fourth
Quarter
Third
Quarter
Second
Quarter
First
Quarter
0.345
0.345
0.345
0.345
0.328
0.328
0.328
0.328
2018
2017
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
2018
2017
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
165 $
106
72
50
44
—
30
15
164 $
105
72
49
136
75
28
31
166 $
106
72
50
62
28
24
12
164
105
72
49
69
30
30
10
First Quarter 2019 Dividend
On February 5, 2019 , the Exelon Board of Directors declared a first quarter 2019 regular quarterly dividend of $0.3625 per share on Exelon’s common stock
payable on March 8, 2019 , to shareholders of record of Exelon at the end of the day on February 20, 2019 .
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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
2018
2017 (c, d)
2016 (a, c, d)
2015 (c)
2014 (b,c)
For the Years Ended December 31,
$
$
$
35,985 $
33,565 $
31,366 $
29,447 $
3,898
2,084
2,010
2.07 $
1.38 $
4,395
3,876
3,786
3.99 $
1.31 $
3,212
1,196
1,121
1.21 $
1.26 $
4,554
2,250
2,269
2.54 $
1.24 $
27,429
3,210
1,820
1,623
1.88
1.24
__________
(a) The 2016 financial results include the activity of PHI from the merger effective date of March 24, 2016 through December 31, 2016.
(b) On April 1, 2014, Generation assumed operational control of CENG’s nuclear fleet. As a result, the 2014 financial results include CENG’s results of operations on a fully
consolidated basis.
(c) Amounts have been recasted to reflect the Improving the Presentation of Net Periodic Pension Cost and Net Periodic Postretirement Benefit Cost guidance adopted as of
January 1, 2018. See Note 1 — Significant Accounting Policies of the Combined Notes to Consolidated Financial Statements for additional information.
(d) Amounts for 2017 and 2016 have been recasted to reflect the Revenue from Contracts with Customers guidance adopted as of January 1, 2018. See Note 1 — Significant
Accounting Policies of the Combined Notes to Consolidated Financial Statements for additional information. The 2015 and 2014 balances are not recasted for this
guidance and are not comparative.
(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
2018
2017 (a)
2016 (a)
2015 (a)
2014 (a)
December 31,
$
13,360 $
76,707
119,666
11,404
11,896 $
74,202
116,770
10,798
12,451 $
71,555
114,952
13,463
15,334 $
57,439
95,384
9,118
34,465
32,565
32,216
24,286
11,853
52,170
86,416
8,762
19,853
Shareholders’ equity
(a) Amounts for 2017 and 2016 have been recasted to reflect the Revenue from Contracts with Customers guidance adopted as of January 1, 2018. See Note 1 — Significant
Accounting Policies of the Combined Notes to Consolidated Financial Statements for additional information. The 2015 and 2014 balances are not recasted for this
guidance and are not comparative.
29,896
30,764
25,860
25,793
22,608
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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
2018
2017 (b)
2016 (b)
2015
2014 (a)
For the Years Ended December 31,
$
20,437 $
18,500 $
17,757 $
975
947
820
19,135 $
2,275
17,393
1,176
Net income
__________
(a) On April 1, 2014, Generation assumed operational control of CENG’s nuclear fleet. As a result, the 2014 financial results include CENG’s results of operations on a fully
2,798
1,340
443
550
1,019
consolidated basis.
(b) Amounts for 2017 and 2016 have been recasted to reflect the Revenue from Contracts with Customers guidance adopted as of January 1, 2018. See Note 1 — Significant
Accounting Policies of the Combined Notes to Consolidated Financial Statements for additional information. The 2015 and 2014 balances are not recasted for this
guidance and are not comparative.
(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
2018
2017 (a)
2016 (a)
2015
2014
December 31,
$
8,433 $
6,882 $
6,567 $
6,342 $
23,981
47,556
5,769
24,906
48,457
4,191
25,585
47,022
5,689
25,843
46,529
4,933
7,887
8,644
8,124
8,869
7,311
23,028
44,951
4,459
7,582
Member’s equity
(a) Amounts for 2017 and 2016 have been recasted to reflect the Revenue from Contracts with Customers guidance adopted as of January 1, 2018. See Note 1 — Significant
Accounting Policies of the Combined Notes to Consolidated Financial Statements for additional information. The 2015 and 2014 balances are not recasted for this
guidance and are not comparative.
13,669
13,204
11,505
11,635
12,718
ComEd
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)
2018
2017
2016
2015
2014
For the Years Ended December 31,
Statement of Operations data:
Operating revenues
Operating income
Net income
$
5,882 $
1,146
664
5,536 $
1,323
567
5,254 $
1,205
378
4,905 $
1,017
426
4,564
980
408
66
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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
Shareholders’ equity
PECO
2018
2017
2016
2015
2014
December 31,
$
1,570 $
1,364 $
1,554 $
1,518 $
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
17,502
26,532
2,766
6,049
8,243
1,723
15,793
25,358
1,923
5,870
7,907
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)
2018
2017
2016
2015
2014
For the Years Ended December 31,
Statement of Operations data:
Operating revenues
Operating income
Net income
$
3,038 $
2,870 $
2,994 $
3,032 $
587
460
655
434
702
438
630
378
(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
2018
2017
2016
2015
2014
December 31,
$
782 $
822 $
757 $
842 $
8,610
10,642
809
3,268
3,820
8,053
10,170
1,267
2,587
3,577
67
7,565
10,831
727
2,764
3,415
7,141
10,367
944
2,464
3,236
3,094
572
352
645
6,801
9,860
653
2,416
3,121
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BGE
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)
2018
2017
2016
2015
2014
For the Years Ended December 31,
Statement of Operations data:
Operating revenues
Operating income
Net income
$
3,169 $
3,176 $
3,233 $
3,135 $
474
313
614
307
550
294
558
288
(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
2018
2017
2016
2015
2014
December 31,
$
786 $
811 $
842 $
845 $
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
6,597
8,295
1,134
1,732
2,687
3,165
439
211
951
6,204
8,056
794
2,109
2,563
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 .
(In millions)
2018
2017
2016
2016
2015
2014
Successor
Predecessor
For the Years Ended
December 31,
March 24 to December
31
January 1 to
March 23,
For the Years Ended
December 31,
Statement of Operations data (a) :
Operating revenues
Operating income
Net income (loss) from continuing operations
Net income (loss)
$
4,805 $
4,679 $
3,643 $
650
398
398
769
362
362
68
93
(61)
(61)
1,153
105
19
19
$4,935 $
4,808
673
318
327
605
242
242
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(In millions)
Balance Sheet data (a) :
Current assets
Property, plant and equipment, net
Total assets
Current liabilities
Long-term debt
Preferred Stock
Successor
December 31,
Predecessor
December 31,
2018
2017
2016
2015
$
1,533 $
1,551 $
1,838 $
13,446
21,984
1,592
6,134
—
12,498
21,247
1,931
5,478
—
11,598
21,025
2,284
5,645
—
8,016
Member’s equity/Shareholders' equity
__________
(a) As a result of the PHI Merger in 2016, Exelon has elected to present PHI's selected financial data for the periods reflected above.
9,282
8,825
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 Consolidated Financial Statements and ITEM 7. MANAGEMENT'S DISCUSSION AND
ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS .
(In millions)
Statement of Operations data (a) :
Operating revenues
Operating income
Net income
(In millions)
Balance Sheet data (a) :
Current assets
Property, plant and equipment, net
Total assets
Current liabilities
Long-term debt
2018
2017
2016
2015
2014
For the Years Ended December 31,
$
2,239 $
2,158 $
2,186 $
2,129 $
320
210
399
205
174
42
385
187
2018
2017
2016
2015
December 31,
$
760 $
710 $
684 $
6,460
8,299
628
2,704
6,001
7,832
550
2,521
5,571
7,335
596
2,333
2,300
Shareholder's equity
__________
(a) As a result of the PHI Merger in 2016, Exelon has elected to present Pepco's selected financial data for the periods reflected above.
2,740
2,533
69
1,474
10,864
16,188
2,327
4,823
183
4,413
2,055
349
171
726
5,162
6,908
455
2,340
2,240
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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 Consolidated Financial Statements and ITEM 7. MANAGEMENT'S DISCUSSION AND ANALYSIS OF
FINANCIAL CONDITION AND RESULTS OF OPERATIONS .
(In millions)
Statement of Operations data (a) :
Operating revenues
Operating income
Net income (loss)
(In millions)
Balance Sheet data (a) :
Current assets
Property, plant and equipment, net
Total assets
Current liabilities
Long-term debt
2018
2017
2016
2015
2014
For the Years Ended December 31,
$
1,332 $
1,300 $
1,277 $
1,302 $
190
120
229
121
50
(9)
165
76
2018
2017
2016
2015
December 31,
$
336 $
325 $
370 $
3,821
4,588
375
1,403
3,579
4,357
547
1,217
3,273
4,153
381
1,221
1,326
1,282
207
104
388
3,070
3,969
564
1,061
1,237
Shareholder's equity
__________
(a) As a result of the PHI Merger in 2016, Exelon has elected to present DPL's selected financial data for the periods reflected above.
1,509
1,335
ACE
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 Consolidated Financial Statements and ITEM 7. MANAGEMENT'S DISCUSSION AND ANALYSIS
OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS .
(In millions)
Statement of Operations data (a) :
Operating revenues
Operating income
Net income (loss)
2018
2017
2016
2015
2014
For the Years Ended December 31,
$
1,236 $
1,186 $
1,257 $
1,295 $
149
75
157
77
7
(42)
134
40
1,210
137
46
70
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(In millions)
Balance Sheet data (a) :
Current assets
Property, plant and equipment, net
Total assets
Current liabilities
Long-term debt
2018
2017
2016
2015
December 31,
$
240 $
258 $
2,966
3,699
422
1,170
2,706
3,445
619
840
399 $
2,521
3,457 $
320 $
1,120
1,034
546
2,322
3,387
297
1,153
1,000
Shareholder's equity
__________
(a) As a result of the PHI Merger in 2016, Exelon has elected to present ACE's selected financial data for the periods reflected above.
1,126
1,043
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Item 7.
MANAGEMENT’S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS
Exelon
Executive Overview
Exelon is a utility services holding company engaged in the generation, delivery, and marketing of energy through Generation and the energy distribution and
transmission businesses through ComEd, PECO, BGE, Pepco, DPL and ACE.
Exelon has twelve reportable segments consisting of Generation’s six reportable segments (Mid-Atlantic, Midwest, New England, 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 is changing 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. As a result, beginning in the first quarter of 2019, Generation will disclose five reportable segments consisting of
Mid-Atlantic, Midwest, New York, ERCOT and Other Power Regions. See Note 1 - Significant Accounting Policies and Note 24 - Segment Information of the
Combined Notes to Consolidated Financial Statements for additional information regarding Exelon's principal subsidiaries and reportable segments.
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.
Additionally, the results of Exelon’s corporate operations include interest costs and income from various investment and financing activities.
Exelon’s consolidated financial information includes the results of its eight separate operating subsidiary registrants, Generation, ComEd, PECO, BGE, PHI,
Pepco, DPL and ACE, which, along with Exelon, are collectively referred to as the Registrants. The following combined Management’s Discussion and Analysis
of Financial Condition and Results of Operations is separately filed by Exelon, Generation, ComEd, PECO, BGE, PHI, Pepco, DPL and ACE. However, none of
the Registrants makes any representation as to information related solely to any of the other Registrants.
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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, 2018 compared to the same period in 2017 and December 31, 2017 compared to the same period in 2016 . For additional information
regarding the financial results for the years ended December 31, 2018 , 2017 and 2016 see the discussions of Results of Operations by Registrant.
Exelon
Generation
ComEd
PECO
BGE
Pepco
DPL
ACE
Other (b)
2018
2017
$
2,010 $
370
664
460
313
210
120
75
(195)
Favorable (unfavorable)
2018 vs. 2017 variance
2016
Favorable (unfavorable)
2017 vs. 2016 variance
3,786 $
2,710
(1,776) $
(2,340)
567
434
307
205
121
77
(594)
97
26
6
5
(1)
(2)
399
1,121 $
483
378
438
286
42
(9)
(42)
(422)
2,665
2,227
189
(4)
21
163
130
119
(172)
Successor
For the Years Ended December 31,
2018
2017
Favorable (unfavorable)
2018 vs. 2017 variance
March 24 to December
31,
Predecessor
January 1 to
March 23,
2016
2016
PHI (a)
__________
(a)
(b) Primarily includes eliminating and consolidating adjustments, Exelon’s corporate operations, shared service entities and other financing and investing activities.
Includes the consolidated results of Pepco, DPL and ACE.
(61) $
362 $
398 $
36 $
$
19
Year Ended December 31, 2018 Compared to Year Ended December 31, 2017 . Net income attributable to common shareholders decreased by $1,776
million and diluted earnings per average common share decreased to $2.07 in 2018 from $3.99 in 2017 primarily due to:
•
•
•
•
•
•
•
•
•
Impacts associated with the one-time remeasurement of deferred income taxes in 2017 as a result of the TCJA;
Net unrealized losses on NDT funds in 2018 compared to net gains in 2017;
Lower realized energy prices;
Accelerated depreciation and amortization due to the decision to early retire the Oyster Creek and TMI nuclear facilities;
The gain associated with the FitzPatrick acquisition in 2017;
Decrease in reserves for uncertain tax positions in 2017 related to the deductibility of certain merger commitments associated with the 2012
Constellation and 2016 PHI acquisitions;
Increased mark-to-market losses;
The gain recorded upon deconsolidation of EGTP's net liabilities in 2017;
The absence of EGTP earnings resulting from its deconsolidation in the fourth quarter of 2017;
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•
•
Long-lived asset impairments of certain merchant wind assets in West Texas; and
Increased storm costs at PECO and BGE.
The decreases were partially offset by;
•
•
•
•
•
•
•
•
•
•
•
The impact of the New York and Illinois ZEC revenue (including the impact of zero emission credits generated in Illinois from June 1, 2017 through
December 31, 2017);
Long-lived asset impairments primarily related to the EGTP assets held for sale in 2017;
Increased capacity prices;
The impact of lower federal income tax rate as a result of the TCJA at Generation;
Net realized gains on NDT funds;
The gain on the settlement of a long-term gas supply agreement;
Decreased nuclear outage days;
Increased electric distribution and energy efficiency formula rate earnings at ComEd;
Regulatory rate increases at PECO, BGE and PHI;
The impact of favorable weather at PECO, DPL and ACE; and
The absences of a 2017 impairment of certain transmission-related income tax regulatory assets at ComEd, BGE and PHI.
The decrease in diluted earnings per share was also due to the increase in Exelon’s average diluted shares outstanding as a result of the June 2017 common
stock issuance.
Year Ended December 31, 2017 Compared to Year Ended December 31, 2016 . Net income attributable to common shareholders increased by $2,665
million and diluted earnings per average common share increased to $3.99 in 2017 from $1.21 in 2016 primarily due to:
•
•
•
•
•
•
•
•
•
•
Impacts associated with the one-time remeasurement of deferred income taxes as a result of the TCJA;
The gain associated with the FitzPatrick acquisition;
Accelerated depreciation and amortization due to the decision to early retire the TMI nuclear facility in 2017 compared to the previous decision in
2016 to early retire the Clinton and Quad Cities nuclear facilities;
Higher net unrealized and realized gains on NDT funds;
The impact of the New York ZEC revenue;
The gain recorded upon deconsolidation of EGTP's net liabilities;
Increased capacity prices;
Decreased nuclear outage days;
Decrease in reserves for uncertain tax positions in 2017 related to the deductibility of certain merger commitments associated with the 2012
Constellation and 2016 PHI acquisitions compared to costs incurred as part of the settlement orders approving the PHI acquisition and a charge
related to a 2012 CEG merger commitment in 2016;
Increased electric distribution and transmission formula rate earnings at ComEd;
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•
•
Regulatory rate increases at BGE and PHI; and
Penalties and associated interest expense as a result of a tax court decision on Exelon's like-kind exchange position in 2016.
The increases were partially offset by;
•
•
•
•
•
•
•
Long-lived asset impairments primarily related to the EGTP assets held for sale;
Lower realized energy prices;
The conclusion of the Ginna Reliability Support Services Agreement;
Increased costs related to the acquisition of the FitzPatrick nuclear facility;
Increased mark-to-market losses;
The impact of unfavorable weather at ComEd, PECO, DPL and ACE; and
The impairment of certain transmission-related income tax regulatory assets at ComEd, BGE and PHI.
The net increase in diluted earnings per share from the items listed above was partially offset by the impact of the increase in Exelon’s average diluted shares
outstanding as a result of the June 2017 common stock issuance.
Adjusted (non-GAAP) Operating Earnings. In addition to net income, Exelon evaluates its operating performance using the measure of Adjusted (non-GAAP)
operating earnings because management believes it represents earnings directly related to the ongoing operations of the business. Adjusted (non-GAAP)
operating earnings exclude certain costs, expenses, gains and losses and other specified items. This information is intended to enhance an investor’s overall
understanding of year-to-year operating results and provide an indication of Exelon’s baseline operating performance excluding items that are considered by
management to be not directly related to the ongoing operations of the business. In addition, this information is among the primary indicators management uses
as a basis for evaluating performance, allocating resources, setting incentive compensation targets and planning and forecasting of future periods. Adjusted
(non-GAAP) operating earnings is not a presentation defined under GAAP and may not be comparable to other companies’ presentations or deemed more
useful than the GAAP information provided elsewhere in this report.
The following 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, 2018 as compared to 2017 and 2016 :
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(All amounts after tax; in millions, except per share amounts)
Net Income Attributable to Common Shareholders
Mark-to-Market Impact of Economic Hedging Activities (a) (net of
taxes of $89, $68 and $18, respectively)
Unrealized Losses (Gains) Related to NDT Funds (b) (net of taxes
of $289, $286 and $112, respectively)
Amortization of Commodity Contract Intangibles (c) (net of taxes
of $0, $22 and $22, respectively)
Merger and Integration Costs (d) (net of taxes of $2, $25 and
$50, respectively)
Merger Commitments (e) (net of taxes of $0, $137 and $126,
respectively)
Long-Lived Asset Impairments (f) (net of taxes of $13, $204 and
$68, respectively)
Plant Retirements and Divestitures (g) (net of taxes of $181, $134
and $273, respectively)
Cost Management Program (h) (net of taxes of $16, $21 and $21,
respectively)
Annual Asset Retirement Obligation Update (i) (net of taxes of $7,
$1 and $13, respectively)
Vacation Policy Change (j) (net of taxes of $0, $21 and $0,
respectively)
Change in Environmental Liabilities (net of taxes of $0, $17 and
$0, respectively)
Bargain Purchase Gain (k) (net of taxes of $0, $0 and $0,
respectively)
Gain on Deconsolidation of Business (l) (net of taxes of $0, $83
and $0, respectively)
Gain on Contract Settlement (m) (net of taxes of $20, $0 and $0,
respectively)
Like-Kind Exchange Tax Position (n) (net of taxes of $0, $66 and
$61, respectively)
Curtailment of Generation Growth and Development Activities (o)
(net of taxes of $0, $0 and $35, respectively)
Reassessment of Deferred Income Taxes (p) (entire amount
represents tax expense)
Tax Settlements (q) (net of taxes of $0, $1 and $0, respectively)
Noncontrolling Interests (r) (net of taxes of $24, $24 and $9,
respectively)
Adjusted (non-GAAP) Operating Earnings
For the Years Ended December 31,
2018
2017
2016
Earnings per
Diluted Share
Earnings per
Diluted Share
Earnings per
Diluted Share
$
2,010 $
2.07 $
3,786 $
3.99 $
1,121 $
1.21
252
0.26
107
0.11
24
0.03
337
0.35
(318)
(0.34)
(118)
(0.13)
—
3
—
35
—
—
—
34
40
0.04
35
0.04
114
(137)
(0.14)
437
0.04
321
0.34
103
512
0.53
207
0.22
432
34
(2)
0.04
34
—
(75)
(0.08)
48
20
—
(1)
—
—
0.05
0.02
—
—
—
—
(33)
(0.03)
27
0.03
(233)
(0.25)
(130)
(0.14)
(55)
(0.06)
—
—
—
—
(22)
—
—
—
(26)
(0.03)
199
—
—
(0.02)
(1,299)
—
(5)
(1.37)
(0.01)
(113)
(0.12)
114
0.12
102
$
3,026 $
3.12 $
2,487 $
2.62 $
2,475 $
76
0.04
0.12
0.47
0.11
0.47
0.04
—
—
—
—
—
0.21
0.06
0.01
—
0.11
2.67
—
—
—
—
—
57
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__________
Note:
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 2018 , 2017 and 2016 ranged from 26.0 percent to
29.0 percent, 39.0 percent to 41.0 percent and 39.0 percent to 41.0 percent, respectively. Under IRS regulations, NDT fund 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 46.2 percent, 47.4 percent and 48.7 percent
for the years ended December 31, 2018 , 2017 and 2016 , respectively.
(a) Reflects the impact of net losses on economic hedging activities. See Note 12 - Derivative Financial Instruments of the Combined Notes to Consolidated Financial
Statements for additional information related to hedging activities.
(b) Reflects the impact of net unrealized gains and losses on Generation’s NDT funds for Non-Regulatory and Regulatory Agreement Units. The impacts of the Regulatory
Agreement Units, including the associated income taxes, are contractually eliminated, resulting in no earnings impact.
(c) Represents the non-cash amortization of intangible assets, net, primarily related to commodity contracts recorded at fair value related to, in 2016, the Integrys and
ConEdison Solutions acquisitions, and in 2017, the ConEdison Solutions and FitzPatrick acquisitions.
(d) Reflects certain costs associated with mergers and acquisitions, including, if and when applicable, professional fees, employee-related expenses and integration activities.
In 2016 and 2017, reflects costs related to the PHI and FitzPatrick acquisitions, partially offset in 2016 at ComEd, and in 2017, at PHI, by the anticipated recovery of
previously incurred PHI acquisition costs. In 2018, reflects costs related to the PHI acquisition. See Note 5 - Mergers, Acquisitions and Dispositions of the Combined
Notes to Consolidated Financial Statements for additional information.
(f)
(g)
(e) Represents costs incurred as part of the settlement orders approving the PHI acquisition, and in 2016, a charge related to a 2012 CEG merger commitment, and in 2017,
primarily a decrease in reserves for uncertain tax positions related to the deductibility of certain merger commitments associated with the 2012 CEG and 2016 PHI
acquisitions.
In 2016, primarily reflects the impairment of upstream assets and certain wind projects at Generation. In 2017, primarily reflects the impairment of the EGTP assets held
for sale and PHI District of Columbia sponsorship intangible asset. In 2018, primarily reflects the impairment of certain wind projects at Generation.
In 2016, primarily reflects accelerated depreciation and amortization expenses through December 2016 and construction work in progress impairments associated with
Generation’s previous decision to early retire the Clinton and Quad Cities nuclear facilities, partially offset by a gain associated with Generation’s sale of the New Boston
generating site. In 2017, primarily reflects accelerated depreciation and amortization expenses and one-time charges associated with Generation's previous decision to
early retire the TMI nuclear facility. In 2018, primarily reflects accelerated depreciation and amortization expenses and one-time charges associated with Generation's
decision to early retire the Oyster Creek nuclear facility, a charge associated with a remeasurement of the Oyster Creek ARO and accelerated depreciation and
amortization expenses associated with the previous decision to early retire the TMI nuclear facility, partially offset by a gain associated with Generation's sale of its
electrical contracting business.
(h) Primarily represents severance and reorganization costs related to a cost management program.
(i)
For Pepco, reflects an increase related to asbestos identified at its Buzzard Point property.
(j) Represents the reversal of previously accrued vacation expenses as a result of a change in Exelon's vacation vesting policy.
(k) Represents the excess of the fair value of assets and liabilities acquired over the purchase price for the FitzPatrick acquisition.
(l) Represents the gain recorded upon deconsolidation of EGTP's net liabilities, which included the previously impaired assets and related debt, as a result of the November
2017 bankruptcy filing.
(m) Represents the gain on the settlement of a long-term gas supply agreement at Generation.
(n) Represents in 2016 the recognition of a penalty and associated interest expense as a result of a tax court decision on Exelon’s like-kind exchange tax position, and in
2017, adjustments to income tax, penalties and interest expenses as a result of the finalization of the IRS tax computation related to Exelon’s like-kind exchange tax
position.
(o) Reflects the one-time recognition for a loss on sale of assets and asset impairment charges pursuant to Generation’s strategic decision in the fourth quarter of 2016 to
narrow the scope and scale of its growth and development activities.
(p) Reflects in 2016 the non-cash impact of the remeasurement of deferred income taxes as a result of changes in forecasted apportionment related to the PHI acquisition. In
2017, one-time non-cash impacts associated with remeasurements of deferred income taxes as a result of the TCJA (including impacts on pension obligations contained
within Other), changes in the Illinois and District of Columbia statutory tax rates and changes in forecasted apportionment. In 2018, reflects an adjustment to the
remeasurement of deferred income taxes as a result of the TCJA and changes in forecasted apportionment.
(q) Reflects benefits related to the favorable settlement of certain income tax positions related to PHI's unregulated business interests.
(r) Represents elimination from Generation’s results of the noncontrolling interests related to certain exclusion items, primarily related to the impact of unrealized gains and
losses on NDT funds at CENG.
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Significant 2018 Transactions and Recent Developments
Regulatory Implications of the Tax Cuts and Jobs Act (TCJA)
The Utility Registrants have made filings with their respective State regulators to begin passing back to customers the ongoing annual tax savings resulting from
the TCJA. The amounts being proposed to be passed back to customers reflect the annual benefit of lower income tax rates and the settlement of a portion of
deferred income tax regulatory liabilities established upon enactment of the TCJA. The Utility Registrants have identified over $675 million in ongoing annual
savings to be returned to customers related to TCJA from their distribution utility operations. See Note 4 — Regulatory Matters of the Combined Notes to
Consolidated Financial Statements for additional information.
Utility Rates and Base Rate Proceedings
The Utility Registrants file base rate cases with their regulatory commissions seeking increases or decreases to their electric transmission and distribution, and
gas distribution rates to recover their costs and earn a fair return on their investments. The outcomes of these regulatory proceedings impact the Utility
Registrants’ current and future results of operations, cash flows and financial position.
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The following tables show the Utility Registrants’ completed and pending distribution base rate case proceedings in 2018. See Note 4 — Regulatory Matters of
the Combined Notes to Consolidated Financial Statements for additional information on other regulatory proceedings.
Completed Utility Distribution Base Rate Case Proceedings
Registrant/Jurisdiction
Filing Date
Requested Revenue
Requirement Increase
(Decrease)
Approved Revenue
Requirement Increase
(Decrease)
Approved ROE
Approval Date
Rate Effective Date
ComEd - Illinois (Electric)
April 16, 2018 $
PECO - Pennsylvania (Electric)
March 29, 2018 $
(23)
(a) $
82 (a) $
(24)
(a)
25 (a)
8.69%
December 4, 2018
January 1, 2019
N/A
December 20, 2018
January 1, 2019
BGE - Maryland (Natural Gas)
Pepco - Maryland (Electric)
Pepco - District of Columbia
(Electric)
DPL - Maryland (Electric)
DPL - Delaware (Electric)
June 8, 2018
(amended
August 24,
2018 and
October 12,
2018)
January 2, 2018
(amended
February 5,
2018)
December 19,
2017 (amended
February 9,
2018)
July 14, 2017
(amended
November 16,
2017)
August 17,
2017 (amended
February 9,
2018)
August 17,
2017 (amended
February 9,
2018)
$
$
$
$
$
$
61
$
43
9.8%
January 4, 2019
January 4, 2019
3 (a) $
(15)
(a)
9.5%
May 31, 2018
June 1, 2018
66
$
(24)
(a)
9.525%
August 9, 2018
August 13, 2018
19
$
13
9.5%
February 9, 2018
February 9,
2018
12 (a) $
(7)
(a)
9.7%
August 21, 2018
March 17, 2018
4 (a) $
(4)
(a)
9.7%
November 8, 2018
March 17, 2018
DPL - Delaware (Natural Gas)
__________
(a)
Includes the annual ongoing TCJA tax savings further discussed above.
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Pending Distribution Base Rate Case Proceedings
Registrant/Jurisdiction
Filing Date
Requested Revenue Requirement
Increase
Requested ROE
Expected Approval Timing
August 21, 2018
(amended November 19,
2018)
January 15, 2019
$
$
122 (a)
30
10.1%
10.3%
Third quarter of 2019
Third quarter of 2019
ACE - New Jersey (Electric)
Pepco - Maryland (Electric)
__________
(a)
Includes the annual ongoing TCJA tax savings further discussed above.
Transmission Formula Rate
The following total (decreases)/increases were included in ComEd's, BGE's, Pepco's, DPL's and ACE's 2018 annual electric transmission formula rate updates.
Registrant
Initial Revenue
Requirement
(Decrease) Increase (b)
Annual Reconciliation
Increase/(Decrease)
Total Revenue
Requirement (Decrease)
Increase )
Allowed Return on Rate
Base (d)
Allowed ROE (e)
ComEd (a)
BGE (a)
Pepco
DPL
$
(44) $
18
$
10
6
14
4
2
13
(26)
26 (c)
8
27
8.32%
7.61%
7.82%
7.29%
11.50%
10.50%
10.50%
10.50%
ACE (a)
__________
(a) The time period for any challenges to the annual transmission formula rate update flings expired with no challenges submitted.
(b) The initial revenue requirement changes reflect the annual benefit of lower income tax rates effective January 1, 2018 resulting from the enactment of the TCJA of $69
million , $18 million , $13 million , $12 million and $11 million for ComEd, BGE, Pepco, DPL and ACE, respectively. They do not reflect the pass back or recovery of
income tax-related regulatory liabilities or assets, including those established upon enactment of the TCJA. See Note 4 — Regulatory Matters of the Combined Notes to
Consolidated Financial Statements for additional information.
10.50%
8.02%
(4)
4
—
(c) BGE's transmission revenue requirement includes a FERC approved dedicated facilities charge of $12 million to recover the costs of providing transmission service to
specifically designated load by BGE.
(d) Represents the weighted average debt and equity return on transmission rate bases.
(e) 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.
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. The formula rate filing includes a requested increase of $22 million to PECO’s annual transmission revenues and a requested
rate of return on common equity of 11% , inclusive of a 50 basis point adder for being a member of a regional transmission organization. PECO requested that
the new transmission rate be effective as of July 2017. 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 May 4, 2018, the Chief Administrative Law Judge
terminated settlement judge procedures and designated a new presiding judge. PECO cannot predict the outcome of this proceeding, or the transmission
formula FERC may approve.
On May 11, 2018, pursuant to the transmission formula rate request discussed above, PECO made its first annual formula rate update, which included a
revenue decrease of $6 million. The revenue decrease of $6 million included
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an approximately $20 million reduction as a result of the tax savings associated with the TCJA. The updated transmission rate was effective June 1, 2018,
subject to refund.
Illinois ZEC Procurement
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 required 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. During the year ended December 31, 2018, Generation recognized revenue of $373 million , of which $150 million related to ZECs generated
from June 1, 2017 through December 31, 2017.
Early Plant Retirements
On February 2, 2018, Exelon announced that Generation will permanently cease generation operations at Oyster Creek at the end of its current operating cycle
and permanently ceased generation operations in September 2018. Because of the decision to early retire Oyster Creek in 2018, Exelon and Generation
recognized certain one-time charges in the first quarter of 2018 related to a materials and supplies inventory reserve adjustment, employee-related costs and
construction work-in-progress impairments, among other items.
On July 31, 2018, Generation entered into an agreement with Holtec International and its indirect wholly owned subsidiary, Oyster Creek Environmental
Protection, LLC, for the sale and decommissioning of Oyster Creek. See Note 5 — Mergers, Acquisitions and Dispositions of the Combined Notes to
Consolidated Financial Statements for additional information.
On May 30, 2017, Generation announced it will permanently cease generation operations at Three Mile Island Generating Station (TMI) on or about September
30, 2019. The plant is currently committed to operate through May 2019. As a result of the early nuclear plant retirement decisions at Oyster Creek and TMI,
Exelon and Generation will also recognize annual 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), accelerated amortization of nuclear fuel, and additional ARO accretion expense
associated with the changes in decommissioning timing and cost assumptions were also recorded. The following table summarizes the actual incremental non-
cash expense item incurred in 2018 and the estimated amount of incremental non-cash expense items expected to be incurred in 2019 due to the early
retirement decisions.
Income statement expense (pre-tax)
Depreciation and Amortization (b)
Accelerated depreciation (c)
Accelerated nuclear fuel amortization
Operating and maintenance (d)
Total
Actual
2018
Projected (a)
2019
$
$
539 $
57
32
628 $
230
5
5
240
_________
(a) Actual results may differ based on incremental future capital additions, actual units of production for nuclear fuel amortization, future revised ARO assumptions, etc.
(b) Reflects incremental accelerated depreciation and amortization for TMI and Oyster Creek for the year ended December 31, 2018. The Oyster Creek year-to-date amounts
are from February 2, 2018 through September 17, 2018.
(c) Reflects incremental accelerated depreciation of plant assets, including any ARC.
(d) Primarily includes materials and supplies inventory reserve adjustments, employee-related costs and CWIP impairments.
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.
On May 23, 2018, New Jersey enacted legislation that established a ZEC program, similar to that in Illinois and New York, 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. The NJBPU must complete its processes for determining eligibility for,
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and participation in, the ZEC program by April 18, 2019. On December 19, 2018, PSEG submitted its application for Salem. Assuming the successful
implementation of the New Jersey ZEC program and the selection of Salem as one of the qualifying facilities, the New Jersey ZEC program has the potential to
mitigate the heightened risk of earlier retirement for Salem. See Note 4 — Regulatory Matters and Note 8 - Early Plant Retirements of the Combined Notes to
Consolidated Financial Statements 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.
On March 29, 2018, based on ISO-NE capacity auction results for the 2021 - 2022 planning year in which Mystic Unit 9 did not clear, Generation notified grid
operator ISO-NE of its plans to early retire its Mystic Generating Station assets absent regulatory reforms on June 1, 2022, at the end of the current capacity
commitment for Mystic Units 7 and 8. As a result of these developments, Generation completed a comprehensive review of the estimated undiscounted future
cash flows of the New England asset group during the first quarter of 2018 and no impairment charge was required.
The ISO-NE announced that it would take a three-step approach to fuel security.
•
•
•
First, on May 1, 2018, ISO-NE made a filing with FERC requesting waiver of certain tariff provisions to allow it to retain Mystic Units 8 and 9 for fuel
security for the 2022 - 2024 planning years. FERC denied the waiver request on procedural grounds on July 2, 2018 and ordered ISO-NE to (i) make a
filing within 60 days providing for the filing of a short-term cost-of-service agreement to address fuel security concerns and (ii) make a filing by July 1,
2019 proposing permanent tariff revisions that would improve its market design to better address regional fuel security concerns.
Second, in accordance with FERC's July 2, 2018 order, on August 31, 2018, ISO-NE made a filing with FERC proposing short-term tariff changes to
permit it to retain a resource for fuel security reliability reasons, which FERC accepted on December 3, 2018.
Third, ISO-NE stated its intention to work with stakeholders to develop long-term market rule changes to address system resiliency considering
significant reliability risks identified in ISO-NE’s January 2018 fuel security report. Changes to market rules are necessary because critical units to the
region, such as Mystic Units 8 and 9, cannot recover future operating costs including the cost of procuring fuel. In its July 2, 2018 order, FERC ordered
ISO-NE to make a filing by July 1, 2019 proposing permanent tariff revisions that would improve its market design to better address regional fuel
security concerns. In January 2019, ISO-NE indicated that it intends to seek an extension of the deadline for this filing to November 15, 2019.
On May 16, 2018, Generation made a filing with FERC to establish cost-of-service compensation and terms and conditions of service for Mystic Units 8 and 9 for
the period between June 1, 2022 - May 31, 2024. On December 20, 2018, FERC issued an order accepting the cost of service agreement reflecting a number of
adjustments to the annual fixed revenue requirement and allowing for recovery of a substantial portion of the costs associated with the Everett Marine Terminal.
On January 4, 2019, Generation notified ISO–NE that it will participate in the Forward Capacity Market auction for the 2022 – 2023 capacity commitment period.
In addition, on January 22, 2019, Exelon and several other parties filed requests for rehearing of certain findings of the December 20, 2018 order. The request
for rehearing does not alter Generation's commitment to participate in the Forward Capacity Auction for the 2022–2023 capacity commitment period. Further
developments such as the failure of ISO-NE to adopt long-term solutions for reliability and fuel security could potentially result in future impairments of the New
England asset group, which could be material. See Note 7 — Impairment of Long-Lived Assets and Intangibles and Note 8 - Early Plant Retirements of the
Combined Notes to Consolidated Financial Statements for additional information.
Pension Plan Merger
Effective January 1, 2019, Exelon is merging the Exelon Corporation Cash Balance Pension Plan (CBPP) into the Exelon Corporation Retirement Program
(ECRP). The merging of the plans is not changing the benefits offered to the plan participants and, thus, has no impact on Exelon's pension obligation. However,
beginning in 2019, actuarial
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losses and gains related to the CBPP and ECRP will be amortized over participants’ average remaining service period of the merged ECRP rather than each
individual plan, which will lower Exelon’s 2019 pre-tax pension cost by approximately $ 90 million.
Winter Storm-Related Costs
During March 2018 there were powerful nor'easter storms that brought a mix of heavy snow, ice and high sustained winds and gusts to the region that
interrupted electric service delivery to customers in PECO's, BGE's, Pepco's, DPL's and ACE's service territories. Restoration efforts included significant costs
associated with employee overtime, support from other utilities and incremental equipment, contracted tree trimming crews and supplies, which resulted in
incremental operating and maintenance expense and incremental capital expenditures in the first quarter of 2018 for PECO, BGE, PHI, Pepco, DPL and ACE. In
addition, PHI, Pepco, DPL and ACE recorded regulatory assets for amounts that are probable of recovery through customer rates. The impacts recorded by the
Registrants for the twelve months ended December 31, 2018 are presented below:
Exelon
PECO
BGE
PHI (a)
Pepco
DPL
Customer Outages
Incremental Operating & Maintenance
Incremental Capital Expenditures
(in millions)
1,727,000
$
750,000
425,000
552,000
182,000
138,000
88 (b) $
53
31
4 (b)
2 (b)
2 (b)
85
34
16
35
4
4
ACE
________
(a) PHI reflects the consolidated customer outages, incremental operating & maintenance and incremental capital expenditures of Pepco, DPL and ACE.
(b) Excludes amounts that were deferred and recognized as regulatory assets at Exelon, PHI, Pepco, DPL and ACE of $27 million, $27 million, $5 million, $1 million and $21
— (b)
27
232,000
million, respectively.
Westinghouse Electric Company LLC Bankruptcy
On March 29, 2017, Westinghouse Electric Company LLC (Westinghouse) and its affiliated debtors filed petitions for relief under Chapter 11 of the Bankruptcy
Code in the U.S. Bankruptcy Court for the Southern District of New York. On January 4, 2018, Westinghouse announced its agreement to be purchased by an
affiliate of Brookfield Business Partners, LLC (Brookfield) for approximately $4.6 billion. On March 28, 2018, the Bankruptcy Court entered an Order confirming
the Debtor's Second Amended Joint Plan of Reorganization which provides for the transaction with Brookfield. The transaction closed on August 1, 2018. Exelon
had contracts with Westinghouse primarily related to Generation's purchase of nuclear fuel, as well as a variety of services and equipment purchases associated
with the operation and maintenance of nuclear generating stations. In conjunction with the confirmation hearing, Exelon had filed a reservation of rights
regarding reorganizing Westinghouse's assumption of all Exelon contracts. Exelon reached an agreement with Brookfield, and all Exelon contracts were
assumed by Brookfield on the closing date.
Exelon’s Strategy and Outlook for 2019 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.
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•
Generation’s competitive businesses provide free cash flow to invest primarily in the utilities and in long-term, contracted assets 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. 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.
Continually optimizing the cost structure is a key component of Exelon’s financial strategy. In August 2015, Exelon announced a cost management program
focused on cost savings of approximately $400 million at BSC and Generation, which was fully realized in 2018. Approximately 75% of the savings were related
to Generation, with the remaining amount related to the Utility Registrants. In November 2017, Exelon announced a commitment for an additional $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. These actions are in response to the continuing economic challenges confronting all parts of Exelon’s
business and industry, 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 PHI merger enhances Exelon’s regulated growth to provide stable cash flows, earnings accretion, and dividend support.
Additionally, the Utility Registrants anticipate investing approximately $29 billion over the next five 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 $16 billion by the end of 2023. The Utility Registrants invest in rate base where beneficial to
customers and the community by
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increasing reliability and the service experience or otherwise meeting customer needs. These investments are made at the lowest reasonable cost to customers.
See Note 4 — 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.
Liquidity Considerations
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.). The Registrants expect cash
flows to be sufficient to meet operating expenses, financing costs and capital expenditure requirements.
Exelon, Generation, ComEd, PECO, BGE, Pepco, DPL and ACE have unsecured syndicated revolving credit facilities with aggregate bank commitments of $0.6
billion , $5.3 billion , $1.0 billion , $0.6 billion , $0.6 billion , $0.3 billion , $0.3 billion and $0.3 billion , respectively. Generation also has bilateral credit facilities
with aggregate maximum availability of $0.5 billion . See Liquidity and Capital Resources — Credit Matters — Exelon Credit Facilities below and Note 13 — Debt
and Credit Agreements of the Combined Notes to Consolidated Financial Statements for additional information.
For additional information regarding the Registrants' liquidity for the year ended December 31, 2018 , see Liquidity and Capital Resources discussion below.
Project Financing
Project financing is used to help mitigate risk of specific generating assets. Project financing is based upon a nonrecourse financial structure, in which project
debt is paid back from the cash generated by the specific asset or portfolio of assets. Borrowings under these agreements are secured by the assets and equity
of each respective project. The lenders do not have recourse against Exelon or Generation in the event of a default. If a specific project financing entity does not
maintain compliance with its specific debt financing covenants, there could be a requirement to accelerate repayment of the associated debt or other project-
related borrowings earlier than the stated maturity dates. In these instances, if such repayment was not satisfied, or restructured, the lenders or security holders
would generally have rights to foreclose against the project-specific assets and related collateral. The potential requirement to satisfy its associated debt or other
borrowings earlier than otherwise anticipated could lead to impairments due to a higher likelihood of disposing of the respective project-specific assets
significantly before the end of their useful lives. Additionally, project finance has credit facilities of $0.2 billion as of December 31, 2018. See Note 13 — Debt and
Credit Agreements of the Combined Notes to Consolidated Financial Statements for additional information on nonrecourse debt.
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
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of operations, cash flows and financial positions. See Note 4 — Regulatory Matters of the Combined Notes to Consolidated Financial Statements for additional
information on these regulatory proceedings.
Power Markets
Price of Fuels
The use of new technologies to recover natural gas from shale deposits is increasing natural gas supply and reserves, which places downward pressure on
natural gas prices and, therefore, on wholesale and retail power prices, which results in a reduction in Exelon’s revenues. Forward natural gas prices have
declined significantly 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.
Complaints and PJM Filing at FERC Seeking to Mitigate ZEC Programs
PJM and NYISO capacity markets include a Minimum Offer Price Rule (MOPR) that is intended to preclude buyers from exercising buyer market power. 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. Currently, the MOPRs in PJM and NYISO apply only to certain new gas-fired resources.
On January 9, 2017, EPSA filed two requests with FERC: one seeking to amend a prior complaint against PJM and another seeking expedited action on a
pending NYISO compliance filing in an existing proceeding. A similar complaint also against PJM was filed at FERC on May 31, 2018. These complaints
generally allege that the relevant MOPR should be expanded to also apply to existing resources including those receiving ZEC compensation under the New
York CES and Illinois ZES programs. Exelon filed protests at FERC in response to each filing, arguing generally that ZEC payments provide compensation for
an environmental attribute that is distinct from the energy and capacity sold in the FERC-jurisdictional markets, and therefore, are no different than other
renewable support programs like the PTC and RPS programs that have generally not been subject to a MOPR. However, if successful, for Generation’s facilities
in PJM and NYISO that are currently receiving ZEC compensation (Quad Cities, Ginna, Fitzpatrick and Nine Mile Point), an expanded MOPR could require
exclusion of ZEC compensation when bidding into future capacity auctions such that these facilities would have an increased risk of not clearing in future
capacity auctions and thus no longer receiving capacity revenues during the respective ZEC programs. Any mitigation of these generating resources could have
a material effect on Exelon’s and Generation’s future cash flows and results of operations. The same risk would also exist for the Salem facility if Salem is
selected as an eligible facility under the New Jersey ZEC program.
Separately, PJM submitted two proposed alternative capacity market reforms in April 2018 for FERC’s consideration. PJM argued that either alternative will
resolve any conflict between state policy support for certain resources and the need to ensure reasonable prices for non-supported resources. The first
alternative was to implement a twice-run capacity clearing mechanism (known as the repricing proposal) and, if not acceptable to FERC, a second
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alternative that would expand the existing MOPR to both new and existing generating resources, subject to certain exemptions (known as MOPREx).
In June 2018, FERC issued an order rejecting both of PJM’s proposed alternatives, finding both to be unjust and unreasonable. In the same order, FERC also
addressed one of the MOPR complaints involving PJM and concluded based on that complaint and PJM’s filing that PJM’s existing tariff allows resources
receiving out-of-market support to affect capacity prices in a manner that will cause unjust and unreasonable and unduly discriminatory rates in PJM regardless
of the intent motivating the support. FERC suggested that modifying two elements of PJM’s existing tariff could produce a just and reasonable replacement and
asked for initial comments on its proposal by August 28, 2018, later extended to October 2, 2018. First, FERC found that an expansion of the current MOPR
mechanism to cover all existing generating resources, regardless of resource type, including those receiving either ZEC or REC compensation, could protect the
capacity markets from unwanted price suppression. Second, FERC preliminarily found that a modified version of PJM’s existing Fixed Resource Requirement
(FRR) option could enable state subsidized resources and a corresponding amount of load to be removed from the capacity market, thereby alleviating their
price suppressive effects on capacity clearing prices. Under this alternative, state supported generating resources would potentially be compensated through
mechanisms other than through PJM’s existing market mechanism. FERC established March 21, 2016 as the refund effective date and also allowed PJM to
delay its next capacity auction from May 2019 to August 2019 to allow parties time to develop and file proposals in the FERC proceeding, FERC time to
determine the appropriate solution and PJM time to implement FERC's solution. On October 2, 2018, Exelon, along with several ratepayer advocates,
environmental organizations and other nuclear generators, submitted shared principles supporting a workable new FRR mechanism (as suggested by FERC)
and detailing how such a mechanism should be implemented. Exelon also submitted individual comments covering matters not addressed in the shared
principles. FERC has not yet issued a decision on the second MOPR complaint involving PJM or the MOPR complaint involving NYISO. It is too early to predict
the final outcome of each of these proceedings or their 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) from imports of uranium products, alleging that these
imports threaten national security (the Petition). The Trade Expansion Act of 1962 (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 has initiated an investigation in response to the petition. The Secretary has 270 days to prepare and
submit a report to President Trump, who then has 90 days to act on the Secretary's recommendations. Exelon and Generation cannot currently predict the
outcome of this investigation. The relief sought by the petitioners would require U.S. nuclear reactors to purchase at least 25% of their uranium needs from
domestic mines over the next 10 years, although the DOC will make an independent determination regarding an appropriate remedy should it find that imports
impair national security. It is reasonably possible that if this petition is successful the resulting increase in nuclear fuel costs in future periods could have a
material, unfavorable impact on Exelon’s and Generation’s financial statements.
Potential DOE Order Pursuant to Defense Production Act and Federal Power Act
The DOE is considering an Order directing ISOs, for 24 months, to purchase electric energy or generation capacity from a designated list of coal and nuclear
generation facilities. Based on a draft memorandum, the Order would be pursuant to DOE's authorities under the Defense Production Act and Federal Power
Act, and would forestall any further actions towards retiring, decommissioning, or deactivating coal and nuclear facilities during the term of the Order. The Order
would emphasize the importance of grid resiliency, in addition to grid reliability, noting that fuel security and diversity are critical components of resiliency. The
DOE recognizes that the underlying economic and regulatory issues are complex and will take time resolve. The Order's 24-month duration would enable DOE
to conduct additional analyses to gain a detailed understanding of location-specific vulnerabilities in U.S. energy delivery systems, while preserving certain
generation facilities. Exelon has been and will continue to be an active
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participant in these proceedings but cannot predict the final outcome 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,
BGE, Pepco, DPL and ACE are projecting load volumes to increase (decrease) by (0.2)% , (0.1)% , 0.3% , (0.3)% and (1.5)% , respectively, in 2019 compared
to 2018 . PECO is projecting load volumes to be flat in 2019 compared to 2018 .
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.
Strategic Policy Alignment
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 declared first, second, third and fourth quarter 2018 dividends of $0.3450 per share each on Exelon's common stock, and the first
quarter 2019 dividends declared was $0.3625 . The dividends for the first, second, third and fourth quarter 2018 were paid on March 9, 2018 , June 8, 2018 ,
September 10, 2018 and December 10, 2018 , respectively. The first quarter 2019 dividend is payable on March 8, 2019 .
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.
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. Generation has hedges in place that significantly mitigate this risk for 2019 and 2020 . However,
Generation is exposed to relatively greater commodity price risk in the subsequent years with respect to which a larger portion of its electricity portfolio is
currently unhedged. As of December 31, 2018 , the percentage of expected generation hedged for the Mid-Atlantic, Midwest, New York and ERCOT reportable
segments is 89% - 92% , 56% - 59% and 32% - 35% for 2019 , 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 generating facilities 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, such as wholesale
and retail sales of power, options and swaps. Generation has been and will continue to be proactive in using hedging strategies to mitigate commodity price risk
in subsequent years as well.
Generation procures oil and natural gas through long-term and short-term contracts and spot-market purchases. Nuclear fuel is 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, coal, oil and natural gas 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 62% of Generation’s uranium concentrate requirements
from 2019 through 2023 are supplied by three producers. In the event of non-performance by these
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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.
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 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. The initial compliance deadline to meet the new standards was April 16, 2015; however, facilities may have been granted an additional one or two-
year extension in limited cases. Numerous entities challenged MATS in the D.C. 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. The U.S.
Supreme Court, however, did not vacate the rule; rather, it was remanded to the D.C. Circuit Court to take further action consistent with the U.S. Supreme
Court’s opinion on this single issue. On April 27, 2017, the D.C. Circuit 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. Following EPA’s review and determination of its course of action for the MATS rule, the parties
will have 30 days to file motions on future proceedings. 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.
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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. On October 10, 2017, EPA issued a proposed rule to repeal the CPP in its entirety, based on a proposed change in the Agency’s legal interpretation of
Clean Air Act Section 111(d) regarding actions that the Agency can consider when establishing the Best System of Emission Reduction (“BSER”) for existing
power plants. Under the proposed interpretation, the Agency exceeded its authority under the Clean Air Act by regulating beyond individual sources of GHG
emissions. Subsequently, on August 31, 2018, EPA proposed its Affordable Clean Energy Rule (ACE), which would 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.
2015 Ozone National Ambient Air Quality Standards (NAAQS). On April 11, 2017, the D.C. Circuit ordered that the consolidated 2015 ozone NAAQS
litigation be held in abeyance pending EPA’s further review of the 2015 Rule. EPA did not meet the October 1, 2017 deadline to promulgate initial designations
for areas in attainment or non-attainment of the standard. A number of states and environmental organizations have notified the EPA of their intent to file suit to
compel EPA to issue the designations.
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.
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.
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 22 — Commitments and Contingencies of the Combined Notes to Consolidated Financial Statements for additional information related to
environmental matters, including the impact of environmental regulation.
Other Legislative and Regulatory Developments
Delaware Distribution System Investment Charge
On June 14, 2018, the Governor of Delaware signed new Distribution System Investment Charge (DSIC) legislation, which establishes a system improvement
charge that provides a mechanism to recover infrastructure investments, allowing for gradual rate increases and limiting frequency of distribution base rate
cases. On November 30, 2018, DPL filed its first electric and gas filing in Delaware with the new rates being put into effect on January 1, 2019. This legislation
supports needed infrastructure investment and allows for more timely recovery of those investments, however Exelon, PHI and DPL do not expect a material
impact on the financial statements.
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Pennsylvania Alternative Ratemaking
On June 28, 2018, the Governor of Pennsylvania signed Act 58 of 2018, which authorizes the PAPUC to review and approve utility-proposed alternative rate
mechanisms, including options such as decoupling mechanisms, formula rates, multi-year rate plans, and performance based rates. Exelon and PECO cannot
predict the outcome or the potential financial impact, if any, on Exelon or PECO.
District of Columbia Clean Energy Bill
On December 18, 2018, the Council of the District of Columbia passed the Clean Energy District of Columbia Omnibus Amendment Act of 2018 (the Act), which
was subsequently signed by the Mayor of the District of Columbia on January 18, 2019. The Act is expected to take effect in February 2019 following the
expiration of a 30-day review process by the U.S. House of Representatives. Among other things, the Act would increase electric load by requiring all public
buses, taxis and other specified fleets to be solely zero-emissions vehicles by 2045. The Act would also clarify that, under certain circumstances, the gas and
electric utilities may offer and receive cost recovery including a return on investment on capital and related costs for energy efficiency programs in the District of
Columbia.
Employees
In January 2017, an election was held at BGE which resulted in union representation for approximately 1,284 employees. BGE and IBEW Local 410 are
negotiating an initial agreement which could result in some modifications to wages, hours and other terms and conditions of employment. Negotiations have
been productive and continue. No agreement has been finalized to date and management cannot predict the outcome of such negotiations. Negotiations that
began in 2017 for a first collective bargaining agreement with a small unit of employees represented by Local 501 of Operating Engineers at Exelon’s Hyperion
Solutions facility are complete and the new CBA will expire in 2021. During 2017, Generation finalized CBAs with the Security Officer unions at LaSalle, Limerick
and Quad Cities, which all will expire in 2020 and Dresden expiring in 2021. Additionally, during 2017, Generation acquired and combined two CBAs at
Fitzpatrick into one CBA covering both craft and security employees, which will expire in 2023. Generation also successfully finalized the CBA with the IBEW
union at TMI, which will expire in 2022. During 2018, Generation finalized its CBA with the Security Officer’s union at Braidwood, which will expire in 2021.
Additionally, ACE successfully finalized two contract renewals with the IBEW Local 210, and the new BAs will expire in 2023. As previously reported, there was
an organizing effort over approximately 18 ACE control room System Operators. While an election was held with an outcome favorable to Local 210, collective
bargaining over this small segment of employees will not commence until the issue of whether the System Operators are NLRA statutory supervisors is
determined, and that matter is currently before the NLRB. Furthermore, there was an organizing effort at PECO over approximately 150 Working Foreperson
positions. In October 2018, the Working Foreperson group overwhelmingly rejected unionization in an election held by the NLRB. Lastly, on December 27, 2018
a representation petition was filed by the LEOSU Union seeking to represent security officers at Clinton Power station who are currently represented by SEIU
Local 1. The current collective bargaining agreement between Exelon Nuclear Security and the SEIU Local 1 has been extended, so that the matter between the
two rival labor organizations can be resolved. No election or determination has been held and it is anticipated that this matter will be resolved in 2019.
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 $10.0 billion at December 31, 2018 . 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.
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As a result of recent nuclear plant retirements in the industry, nuclear operators and third-party service providers are obtaining more information about costs
associated with decommissioning activities. At the same time, regulators are gaining more information about decommissioning activities which could result in
changes to existing decommissioning requirements. In addition, as more nuclear plants are retired, it is possible that technological advances will be identified
that could create efficiencies and lead to a reduction in decommissioning costs. The availability of NDT funds could impact the timing of the decommissioning
activities. Additionally, certain factors such as changes in regulatory requirements during plant operations or the profitability of a nuclear plant could impact the
timing of plant retirements. These factors could result in material changes to Generation’s current estimates as more information becomes available and could
change the timing of plant retirements and the probability assigned to the decommissioning outcome scenarios.
The nuclear decommissioning obligation is adjusted on a regular basis due to the passage of time and revisions to the key assumptions for the expected timing
and/or estimated amounts of the future undiscounted cash flows required to decommission the nuclear plants, based upon the following methodologies and
significant estimates and assumptions:
Decommissioning Cost Studies. Generation uses unit-by-unit decommissioning cost studies to provide a marketplace assessment of the expected costs (in
current year dollars) and timing of decommissioning activities, which are validated by comparison to current decommissioning projects within the industry and
other estimates. Decommissioning cost studies are updated, on a rotational basis, for each of Generation’s nuclear units at least every five years, unless
circumstances warrant more frequent updates. As part of the annual cost study update process, Generation evaluates newly assumed costs or substantive
changes in previously assumed costs to determine if the cost estimate impacts are sufficiently material to warrant application of the updated estimates to the
AROs across the nuclear fleet outside of the normal five-year rotating cost study update cycle.
Cost Escalation Factors. Generation uses cost escalation factors to escalate the decommissioning costs from the decommissioning cost studies discussed
above through the assumed decommissioning period for each of the units. Cost escalation studies, updated on an annual basis, are used to determine
escalation factors, and are based on inflation indices for labor, equipment and materials, energy, LLRW disposal and other costs. All of the nuclear AROs are
adjusted each year for the updated cost escalation factors.
Probabilistic Cash Flow Models. Generation’s probabilistic cash flow models include the assignment of probabilities to various scenarios for decommissioning
cost levels, decommissioning approaches, and timing of plant shutdown on a unit-by-unit basis. Probabilities assigned to cost levels include an assessment of
the likelihood of costs 20% higher (high-cost scenario) or 15% lower (low-cost scenario) than the base cost scenario. The assumed decommissioning scenarios
include the following three alternatives: (1) DECON which assumes decommissioning activities begin shortly after the cessation of operation, (2) Shortened
SAFSTOR generally has a 30-year delay prior to onset of decommissioning activities, and (3) SAFSTOR which assumes the nuclear facility is placed and
maintained in such condition that the nuclear facility can be safely stored and subsequently decontaminated generally within 60 years after cessation of
operations. In each decommissioning scenario, spent fuel is transferred to dry cask storage as soon as possible until DOE acceptance for disposal.
The actual decommissioning approach selected once a nuclear facility is shutdown will be determined by Generation at the time of shutdown and may be
influenced by multiple factors including the funding status of the 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
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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 22 — 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 $10.0 billion to approximately $10.1 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
2017 CARFR rather than the 2018 CARFR
2018 CARFR increased by 50 basis points
2018 CARFR decreased by 50 basis points
Increase (Decrease) to ARO at
December 31, 2018
$
50
(100)
130
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 site or sites for which an early plant retirement has been announced.
Increase to ARO at
December 31, 2018
$
1,530
650
410
720
90
See Note 1 — Significant Accounting Policies , Note 8 — Early Plant Retirements and Note 15 — Asset Retirement Obligations of the Combined Notes to
Consolidated Financial Statements for additional information regarding accounting for nuclear decommissioning obligations.
Goodwill (Exelon, ComEd and PHI)
As of December 31, 2018 , 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
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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 24 — 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 10 — 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.
Exelon’s, ComEd’s and PHI’s accounting policy is to perform a quantitative test of goodwill at least once every three years, or more frequently if events occur or
circumstances change that would more likely than not reduce the fair value of the reporting unit below its carrying amount.
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 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 10 — 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 5 —
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)
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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 4 —
Regulatory Matters , Note 5 — Mergers, Acquisitions and Dispositions and Note 10 — 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 their long-lived assets and asset groups, excluding goodwill, for impairment when circumstances indicate the
carrying value of those assets may not be recoverable. Indicators of potential impairment may include a deteriorating business climate, including 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 have a significant impact in the consolidated financial
statements. An impairment evaluation is based on an undiscounted cash flow analysis at the lowest level at which cash flows of the long-lived assets or asset
groups are largely independent of the cash flows of other assets and liabilities. For the generation business, the lowest level of independent cash flows is
determined by the evaluation of several factors, including the geographic dispatch of the generation units and the hedging strategies related to those units as
well as the associated intangible assets or liabilities recorded on the balance sheet. The cash flows from the generating units are generally evaluated at a
regional portfolio level with cash flows generated from the customer supply and risk management activities, including cash flows from related intangible assets
and liabilities on the balance sheet. In certain cases, generating assets may be evaluated on an individual basis where those assets are contracted on a long-
term basis with a third party and operations are independent of other generating assets (typically contracted renewables). For such assets the financial viability
of the third party, including the impact of bankruptcy on the contract, may be a significant assumption in the assessment.
On a quarterly basis, Generation assesses its long-lived assets or asset groups for indicators of impairment. If indicators are present for a long-lived asset or
asset group, a comparison of the undiscounted expected future cash flows to the carrying value is performed. When the undiscounted cash flow analysis
indicates the carrying value of a long-lived asset or asset group is not recoverable, the amount of the impairment loss is determined by measuring the excess of
the carrying amount of the long-lived asset or asset group over its fair value. The fair value of the long-lived asset or asset group is dependent upon a market
participant’s view of the exit price of the assets. This includes significant assumptions of the estimated future cash flows generated by the assets and market
discount rates. Events and circumstances often do not occur as expected 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 7 — Impairment of Long-Lived Assets and Intangibles of the Combined Notes to Consolidated Financial Statements for a discussion of asset
impairment evaluations made by Exelon.
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
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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 4 - 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 8 — Early Plant Retirements of the Combined
Notes to the Consolidated Financial Statements for additional information.
Changes in estimated useful lives of electric generation assets and of electric and natural gas transmission and distribution assets could have a significant
impact on the Registrants’ future results of operations. See Note 1 — Significant Accounting Policies of the Combined Notes to Consolidated Financial
Statements for information regarding depreciation and estimated service lives of the property, plant and equipment of the Registrants.
Defined Benefit Pension and Other Postretirement Employee Benefits (All Registrants)
Exelon sponsors defined benefit pension plans and 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
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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, 2018 and 2017 , 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 utilizes the IRS's RP-2000 base table and the Scale BB 2-Dimensional improvement scale with long-term improvements
of 0.75% .
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 2018 cost:
Discount rate (a)
EROA
Change in benefit obligation at December 31, 2018:
Discount rate (a)
Actual Assumption
Pension
OPEB
Change in
Assumption
Pension
OPEB
Total
3.62%
3.62%
7.00%
7.00%
4.31%
4.31%
3.61%
3.61%
6.60%
6.60%
4.30%
4.30%
0.5%
(0.5)%
0.5%
(0.5)%
0.5%
(0.5)%
$
(51) $
(17) $
62
(90)
89
(1,180)
1,371
21
(13)
13
(246)
284
(68)
83
(103)
102
(1,426)
1,655
__________
(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 16 — 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.
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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, 2018
Gain (loss)
Exelon
ComEd
PECO
BGE
PHI
Pepco
DPL
ACE
$
744 $
4,743 $
55 $
694 $
(853) $
(84) $
375 $
(6)
Charge against OCI (a)
___________
(a) Exelon's charge against OCI (before taxes) consists of up to $2.4 billion , $529 million , $157 million , $413 million , $208 million and $105 million related to ComEd's,
3,754 $
— $
— $
— $
— $
— $
— $
$
—
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 $(47) 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.
See Note 4 — 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 12 — 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.
Under current 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, the normal purchases and normal sales exception. 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 normal purchases and
normal sales transactions, which are thus not required to be
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recorded at fair value, but rather on an accrual basis of accounting. Determining whether a contract qualifies for the normal purchases and normal sales
exception 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 normal purchases and normal sales are recognized when
the underlying physical transaction is completed. Contracts that qualify for the normal purchases and normal sales exception 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
normal purchases and normal sales exception.
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 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.
Interest Rate and Foreign Exchange Derivative Instruments. The Registrants may utilize fixed-to-floating interest rate swaps to achieve the targeted level of
variable-rate debt as a percent of total debt. Additionally, the Registrants may use forward-starting interest rate swaps and treasury rate locks to lock in interest-
rate levels and floating to fixed swaps for project financing. In addition, Generation enters into interest rate derivative contracts to economically hedge risk
associated with the interest rate component of commodity positions. Generation does not utilize interest rate derivatives with the objective of benefiting from
shifts or changes in market interest rates. To manage foreign exchange rate exposure associated with international energy purchases in currencies other than
U.S. dollars, Generation utilizes foreign currency derivatives, which are typically designated as economic hedges. The fair value of the agreements is calculated
by discounting the future net cash flows to the present value based on observable inputs and are primarily categorized in Level 2 in the fair value hierarchy.
Certain exchange based interest rate derivatives that are valued using unadjusted quoted prices in active markets are categorized in Level 1 in the fair value
hierarchy.
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See ITEM 7A. QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK and Note 11 — Fair Value of Financial Assets and Liabilities and
Note 12 — Derivative Financial Instruments of the Combined Notes to Consolidated Financial Statements for additional information regarding the Registrants’
derivative instruments.
Taxation (All Registrants)
Significant management judgment is required in determining the Registrants’ provisions for income taxes, primarily due to the uncertainty related to tax positions
taken, as well as deferred tax assets and liabilities and valuation allowances. The Registrants account for uncertain income tax positions using a benefit
recognition model with a two-step approach including a more-likely-than-not recognition threshold and a measurement approach based on the largest amount of
tax benefit that is greater than 50% likely of being realized upon ultimate settlement. Management evaluates each position based solely on the technical merits
and facts and circumstances of the position, assuming the position will be examined by a taxing authority having full knowledge of all relevant information.
Significant judgment is required to determine whether the recognition threshold has been met and, if so, the appropriate amount of tax benefits to be recorded in
the Registrants’ consolidated financial statements.
The Registrants evaluate quarterly the probability of realizing deferred tax assets by reviewing a forecast of future taxable income and their intent and ability to
implement tax planning strategies, if necessary, to realize deferred tax assets. The Registrants also assess negative evidence, such as the expiration of
historical operating loss or tax credit carryforwards, that could indicate the Registrant's inability to realize its deferred tax assets. Based on the combined
assessment, the Registrants record valuation allowances for deferred tax assets when it is more-likely-than-not such benefit will not be realized in future periods.
Actual income taxes could vary from estimated amounts due to the future impacts of various items, including future changes in income tax laws, the Registrants’
forecasted financial condition and results of operations, failure to successfully implement tax planning strategies, as well as results of audits and examinations of
filed tax returns by taxing authorities. See Note 14 — Income Taxes of the Combined Notes to Consolidated Financial Statements for additional information.
Accounting for Loss Contingencies (All Registrants)
In the preparation of their financial statements, the Registrants make judgments regarding the future outcome of contingent events and record liabilities for loss
contingencies that are probable and can be reasonably estimated based upon available information. The amount recorded may differ from the actual expense
incurred when the uncertainty is resolved. Such difference could have a significant impact in the Registrants' consolidated financial statements.
Environmental Costs. Environmental investigation and remediation liabilities are based upon estimates with respect to the number of sites for which the
Registrants will be responsible, the scope and cost of work to be performed at each site, the portion of costs that will be shared with other parties, the timing of
the remediation work and changes in technology, regulations and the requirements of local governmental authorities. Annual studies and/or reviews are
conducted at ComEd, PECO, BGE and DPL to determine future remediation requirements for MGP sites and estimates are adjusted accordingly. In addition,
periodic reviews are performed at each of the Registrants to assess the adequacy of other environmental reserves. These matters, if resolved in a manner
different from the estimate, could have a significant impact in the Registrants’ consolidated financial statements. See Note 22 — Commitments and
Contingencies of the Combined Notes to Consolidated Financial Statements for additional information.
Other, Including Personal Injury Claims. The Registrants are self-insured for general liability, automotive liability, workers’ compensation, and personal injury
claims to the extent that losses are within policy deductibles or exceed the amount of insurance maintained. The Registrants have reserves for both open claims
asserted and an estimate of claims incurred but not reported (IBNR). The IBNR reserve is estimated based on actuarial assumptions and analysis and is
updated annually. Future events, such as the number of new claims to be filed each year, the average cost of disposing of claims, as well as the numerous
uncertainties surrounding litigation and possible state and national legislative measures could cause the actual costs to be higher or lower than estimated.
Accordingly, these claims, if resolved in a manner different from the estimate, could have a material impact in the Registrants’ consolidated financial statements.
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Revenue Recognition (All Registrants)
Sources of Revenue and Determination of Accounting Treatment. The Registrants earn revenues from various business activities including: the sale of
power and energy-related products, such as natural gas, capacity, and other commodities in non-regulated markets (wholesale and retail); the sale and delivery
of power and natural gas in regulated markets; and the provision of other energy-related non-regulated products and services.
The accounting treatment for revenue recognition is based on the nature of the underlying transaction and applicable authoritative guidance. The Registrants
primarily apply the Revenue from Contracts with Customers, Derivative and Alternative Revenue Program (ARP) guidance to recognize revenue as discussed in
more detail below.
Revenue from Contracts with Customers. Under the Revenue from Contracts with Customers guidance, 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 normal purchases and normal sales (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 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 Alternative Revenue Programs (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
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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 4 — 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
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
2018
2017
Favorable
(unfavorable) 2018 vs.
2017 variance
2016
Favorable (unfavorable)
2017 vs. 2016 variance
$
20,437 $
18,500 $
1,937 $
17,757 $
11,693
9,690
(2,003)
8,830
8,744
8,810
(66)
8,927
5,464
1,797
556
7,817
48
—
—
975
(432)
(178)
(610)
365
(108)
(30)
443
73
6,299
1,457
555
8,311
2
233
213
947
(440)
948
508
1,455
(1,376)
(33)
2,798
88
835
(340)
(1)
494
46
(233)
(213)
28
8
(1,126)
(1,118)
(1,090)
(1,268)
3
(2,355)
(15)
5,663
1,879
506
8,048
(59)
—
—
820
(364)
401
37
857
282
(25)
550
67
743
(860)
(117)
(636)
422
(49)
(263)
61
233
213
127
(76)
547
471
598
1,658
(8)
2,248
21
2,227
Net income attributable to membership interest
$
370
$
2,710
$
(2,340)
$
483
$
Year Ended December 31, 2018 Compared to Year Ended December 31, 2017 . Net income attributable to membership interest decreased by $2,340
million primarily due to:
•
•
•
•
•
•
•
Impacts associated with the one-time remeasurement of deferred income taxes in 2017 as a result of the TCJA;
Net unrealized losses on NDT funds in 2018 compared to net gains in 2017;
Lower realized energy prices;
Accelerated depreciation and amortization due to the decision to early retire the Oyster Creek and TMI nuclear facilities;
The gain associated with the FitzPatrick acquisition in 2017;
Increased mark-to-market losses;
The gain recorded upon deconsolidation of EGTP's net liabilities in 2017;
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•
•
The absence of EGTP earnings resulting from its deconsolidation in the fourth quarter of 2017; and
Long-lived asset impairments of certain merchant wind assets in West Texas.
The decreases were partially offset by;
•
•
•
•
•
•
The impact of the New York and Illinois ZEC revenue (including the impact of zero emission credits generated in Illinois from June 1, 2017 through
December 31, 2017);
Long-lived asset impairments primarily related to the EGTP assets held for sale in 2017;
Increased capacity prices;
The impact of lower federal income tax rate as a result of the TCJA at Generation;
Net realized gains on NDT funds; and
Decreased nuclear outage days.
Year Ended December 31, 2017 Compared to Year Ended December 31, 2016 . Net income attributable to membership interest increased by $2,227
million primarily due to:
•
•
•
•
•
•
•
•
Impacts associated with the one-time remeasurement of deferred income taxes as a result of the TCJA;
The gain associated with the FitzPatrick acquisition;
Accelerated depreciation and amortization due to the decision to early retire the TMI nuclear facility in 2017 compared to the previous decision in 2016
to early retire the Clinton and Quad Cities nuclear facilities;
Higher net unrealized and realized gains on NDT funds;
The impact of the New York ZEC revenue;
The gain recorded upon deconsolidation of EGTP's net liabilities;
Increased capacity prices; and
Decreased nuclear outage days.
These increases were partially offset by:
•
•
•
•
•
Long-lived asset impairments primarily related to the EGTP assets held for sale;
Lower realized energy prices;
The conclusion of the Ginna Reliability Support Services Agreement;
Increased costs related to the acquisition of the FitzPatrick nuclear facility; and
Increased mark-to-market losses.
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 six reportable segments are Mid-Atlantic, Midwest, New England, ERCOT and Other Power Regions.
During the first quarter of 2019, due to a change in economics in our New England region, Generation is changing 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. As a result,
beginning in the first quarter of 2019, Generation will disclose five reportable segments consisting of Mid-Atlantic, Midwest, New York, ERCOT and
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Other Power Regions. See Note 24 - 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:
amortization of certain intangible assets relating to commodity contracts recorded at fair value from mergers and acquisitions; 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, 2018 compared to 2017 and December 31, 2017 compared to 2016 , RNF by region were as follows:
Mid-Atlantic (a)
Midwest (a)
New England
New York (c)
ERCOT
Other Power Regions
Total electric revenues net of
purchased power and fuel
expense
Proprietary Trading
Mark-to-market losses
Other (b)
Total revenue net of purchased
power and fuel expense
2018
2017
Variance
% Change
2016
Variance
% Change
2018 vs. 2017
2017 vs. 2016
$
3,073 $
3,214 $
3,135
354
1,122
258
375
2,820
514
1,008
332
305
8,317
8,193
42
(319)
704
18
(175)
774
(141)
315
(160)
114
(74)
70
124
24
(144)
(70)
(4.4)% $
3,317 $
11.2 %
(31.1)%
11.3 %
(22.3)%
23.0 %
1.5 %
n.m.
82.3 %
(9.0)%
2,971
438
752
281
336
8,095
15
(41)
858
(103)
(151)
76
256
51
(31)
98
3
(134)
(84)
(3.1)%
(5.1)%
17.4 %
34.0 %
18.1 %
(9.2)%
1.2 %
n.m.
326.8 %
(9.8)%
$
8,744
$
8,810
$
(66)
(0.7)% $
8,927
$
(117)
(1.3)%
_________
(a)
Includes results of transactions with PECO and BGE in the Mid-Atlantic region and results of transactions with ComEd in the Midwest region. As a result of the PHI
merger, includes results of transactions with Pepco, DPL and ACE in the Mid-Atlantic region beginning on March 24, 2016.
(b) Other represents activities not allocated to a region. Includes amortization of intangible assets related to commodity contracts recorded at fair value of a $54 million
decrease to RNF and a $57 million decrease to RNF for the years ended December 31, 2017 and 2016 , respectively, accelerated nuclear fuel amortization associated
with announced early plant retirements, as discussed in Note 8 - Early Plant Retirements of the Combined Notes to Consolidated Financial Statements, of $57 million ,
$12 million and $60 million for the years ended December 31, 2018 , 2017 and 2016 , respectively, and gain on the settlement of a long-term gas supply agreement of $75
million for the year ended December 31, 2018.
Includes the ownership of the FitzPatrick nuclear facility from March 31, 2017.
(c)
105
2018
2017
Variance
% Change
2016
Variance
% Change
2018 vs. 2017
2017 vs. 2016
Table of Contents
Generation’s supply sources by region are summarized below:
Supply Source (GWhs)
Nuclear Generation (a)
Mid-Atlantic
Midwest
New York (c)
64,099
94,283
26,640
64,466
93,344
25,033
Total Nuclear Generation
185,022
182,843
Fossil and Renewables
Mid-Atlantic
Midwest
New England
New York
ERCOT
Other Power Regions
Total Fossil and Renewables
Purchased Power
Mid-Atlantic
Midwest
New England
New York
ERCOT
Other Power Regions
Total Purchased Power
Total Supply/Sales by Region
Mid-Atlantic (b)
Midwest (b)
New England
New York
ERCOT
Other Power Regions
3,670
1,373
4,731
3
11,180
8,525
29,482
6,506
996
2,789
1,482
7,179
3
12,072
6,869
30,394
9,801
1,373
26,033
18,517
—
6,550
18,965
59,050
74,275
96,652
30,764
26,643
17,730
27,490
28
7,346
14,530
51,595
77,056
96,199
25,696
25,064
19,418
21,399
Total Supply/Sales by Region
273,554
264,832
(367)
939
1,607
2,179
881
(109)
(2,448)
—
(892)
1,656
(912)
(3,295)
(377)
7,516
(28)
(796)
4,435
7,455
(2,781)
453
5,068
1,579
(1,688)
6,091
8,722
(0.6)%
1.0 %
6.4 %
1.2 %
31.6 %
(7.4)%
(34.1)%
— %
(7.4)%
24.1 %
(3.0)%
(33.6)%
(27.5)%
40.6 %
— %
(10.8)%
30.5 %
14.4 %
(3.6)%
0.5 %
19.7 %
6.3 %
(8.7)%
28.5 %
3.3 %
63,447
94,668
18,684
176,799
2,731
1,488
6,968
3
6,785
8,179
26,154
16,874
2,255
16,632
—
10,637
13,589
59,987
83,052
98,411
23,600
18,687
17,422
21,768
262,940
1,019
(1,324)
6,349
6,044
58
(6)
211
—
5,287
(1,310)
4,240
(7,073)
(882)
1,885
28
(3,291)
941
(8,392)
(5,996)
(2,212)
2,096
6,377
1,996
(369)
1,892
1.6 %
(1.4)%
34.0 %
3.4 %
2.1 %
(0.4)%
3.0 %
— %
77.9 %
(16.0)%
16.2 %
(41.9)%
(39.1)%
11.3 %
— %
(30.9)%
6.9 %
(14.0)%
(7.2)%
(2.2)%
8.9 %
34.1 %
11.5 %
(1.7)%
0.7 %
__________
(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 and BGE in the Mid-Atlantic region and affiliate sales to ComEd in the Midwest region. As a result of the PHI Merger, includes affiliate
sales to Pepco, DPL and ACE in the Mid-Atlantic region beginning on March 24, 2016.
Includes the ownership of the FitzPatrick nuclear facility from March 31, 2017.
(b)
(c)
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Table of Contents
For the years ended December 31, 2018 compared to 2017 and December 31, 2017 compared to 2016 , changes in RNF by region were as follows:
Mid-Atlantic
Increase/(Decrease)
$
(141)
2018 vs. 2017
Description
• lower realized energy prices,
partially offset by
• increased capacity prices
• the impact of the Illinois ZES
• increased capacity prices,
partially offset by
• lower realized energy prices
• lower realized energy prices,
partially offset by
• increased capacity prices
• impact of the New York CES
• acquisition of Fitzpatrick,
partially offset by
• the conclusion of the Ginna Reliability
Support Service Agreement
• deconsolidation of EGTP in 2017,
partially offset by
• the addition of two combined-cycle gas
turbines in Texas
Midwest
New England
New York
ERCOT
Other Power Regions
Proprietary Trading
Mark-to-Market
Other
315
(160)
114
(74)
70
24
(144)
(70)
Increase/(Decrease)
$
(103)
2017 vs. 2016
Description
• lower load volumes
• lower realized energy prices
• decreased capacity prices,
partially offset by
• the absence of oil inventory write-downs in
2017
• decreased nuclear outage days
(151)
• lower realized energy prices
• increased nuclear outage days, partially
offset by
• decreased fuel prices
76
256
• increased capacity prices,
partially offset by
• lower realized energy prices
• the impact of the New York CES
• acquisition of FitzPatrick,
partially offset by
• conclusion of the Ginna Reliability Support
Service Agreement
• lower realized energy prices
51
• the addition of two combined-cycle gas
turbines in Texas,
partially offset by
• lower realized energy prices
• higher realized energy prices
(31)
• lower realized energy prices
• congestion activity
3
• congestion activity
• losses on economic hedging activities of
$319 million in 2018 compared to losses of
$175 million in 2017
• decline in revenues related to the energy
efficiency business
• the sale of Generation's electrical
contracting business in 2018
• accelerated nuclear fuel amortization
associated with announced early plant
retirements,
partially offset by
• the absence of amortization of energy
contracts recorded at fair value associated
with prior acquisitions
• gain on the settlement of a long-term gas
supply agreement
(134)
(84)
• losses on economic hedging activities of
$175 million in 2017 compared to losses of
$41 million in 2016
• the impacts of declining natural gas prices
on Generation's natural gas portfolio
• decline in revenues related to the
distributed generation business,
partially offset by
• decrease in accelerated nuclear fuel
amortization associated with announced
early plant retirements
Total
$
(66)
$
(117)
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Table of Contents
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 Nuclear, LLC and including the ownership of the FitzPatrick nuclear
facility from March 31, 2017. The nuclear fleet capacity factor presented in the table is defined as the ratio of the actual output of a plant over a period of time to
its output if the plant had operated at full average annual mean capacity for that time period. Generation considers capacity factor to be a useful measure to
analyze the nuclear fleet performance between periods. Generation has included the analysis below as a complement to the financial information provided in
accordance with GAAP. However, these measures are not a presentation defined under GAAP and may not be comparable to other companies’ presentations or
be more useful than the GAAP information provided elsewhere in this report.
Nuclear fleet capacity factor
Refueling outage days
Non-refueling outage days
The changes in Operating and maintenance expense , consisted of the following:
2018
2017
2016
94.6%
274
38
94.1%
293
53
94.6%
245
63
Impairment and related charges of certain generating assets (b)
Merger and integration costs (c)
Insurance
Pension and non-pension postretirement benefits expense
BSC costs
Plant retirements and divestitures (d)
Accretion expense
Nuclear refueling outage costs, including the co-owned Salem plant
Labor, other benefits, contracting and materials (e)
Vacation policy change (f)
Change in environmental liabilities
Other
Decrease in operating and maintenance expense
Increase (Decrease)
2018 vs. 2017 (a)
(432)
(68)
(36)
(22)
13
53
(14)
(24)
(255)
40
(45)
(45)
(835)
$
$
Includes the ownership of the FitzPatrick nuclear facility from March 31, 2017.
__________
(a)
(b) Primarily reflects the impairment of certain wind projects in 2018 and charges to earnings related to impairments as a result of the EGTP assets in 2017.
(c) Primarily reflects merger and integration costs associated with the PHI and FitzPatrick acquisitions, including, if and when applicable, professional fees, employee-related
expenses and integration activities.
(d) Primarily represents the announcement to early retire the Oyster Creek nuclear facility, a charge associated with a remeasurement of the Oyster Creek ARO compared to
the previous decision to early retire the TMI nuclear facility in 2017.
(e) Primarily reflects decreased spending related to energy efficiency projects and decreased costs related to the sale of Generation's electrical contracting business.
(f) Primarily reflects the reversal of previously accrued vacation expenses as a result of a change in Exelon's vacation vesting policy.
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Table of Contents
Impairment and related charges of certain generating assets (b)
Merger and integration costs
ARO update (c)
Pension and non-pension postretirement benefits expense (c)
BSC costs
Plant retirements and divestitures (d)
Accretion expense (e)
Nuclear refueling outage costs, including the co-owned Salem plant (f)
Merger commitments (g)
Labor, other benefits, contracting and materials (h)
Cost management program
Curtailment of Generation growth and development activities (i)
Vacation policy change (j)
Allowance for uncollectible accounts
Change in environmental liabilities
Other
Increase in operating and maintenance expense
Increase (Decrease)
2017 vs. 2016 (a)
307
13
84
10
23
127
35
104
(53)
38
(2)
(24)
(40)
33
44
(63)
636
$
$
Includes the ownership of the FitzPatrick nuclear facility from March 31, 2017.
__________
(a)
(b) Primarily reflects charges to earnings related to impairments as a result of the EGTP assets in 2017 and impairment of Upstream assets and certain wind projects in 2016.
(c) Primarily reflects the non-cash benefit pursuant to the annual update of the nuclear decommissioning obligation related to the non-regulatory units in 2017 compared to
2016.
(d) Primarily represents the announcement of the early retirement of the TMI nuclear facility in 2017 compared to the previous decision to early retire the Clinton and Quad
Cities nuclear facilities in 2016.
(e) Reflects the impact of increased accretion expenses primarily due to the acquisition of FitzPatrick on March 31, 2017.
(f) Primarily reflects an increase in the number of nuclear outage days during 2017 compared to 2016.
(g) Primarily represents costs incurred as part of the settlement orders approving the PHI merger during 2016.
(h) Reflects increased salaries, wages and contracting costs primarily related to the acquisition of the FitzPatrick nuclear facility beginning on March 31, 2017.
(i) Reflects the one-time recognition for a loss on sale of assets and asset impairment charges pursuant to Generation's strategic decision in the fourth quarter of 2016 to
narrow the scope and scale of its growth and development activities.
(j) Represents the reversal of previously accrued vacation expenses as a result of a change in Exelon's vacation vesting policy.
Depreciation and amortization expense for the year ended December 31, 2018 compared to the year ended December 31, 2017 increased primarily due to
accelerated depreciation and amortization expenses associated with the decision to early retire the Oyster Creek nuclear facility in 2018 compared to the
previous decision to early retire the TMI nuclear facility in 2017.
Depreciation and amortization expense for the year ended December 31, 2017 compared to the year ended December 31, 2016 decreased primarily due to
accelerated depreciation and increased nuclear decommissioning amortization related to the previous decision to early retire the Clinton and Quad Cities nuclear
facilities in 2016 compared to the decision to early retire the TMI nuclear facility in 2017.
Gain (loss) on sales of assets and businesses for the year ended December 31, 2018 compared to the year ended December 31, 2017 increased due to
Generation's 2018 sale of its electrical contracting business.
Gain (loss) on sales of assets and businesses for the year ended December 31, 2017 compared to the year ended December 31, 2016 increased primarily
due to certain Generation projects and contracts being terminated or renegotiated in 2016, partially offset by a gain associated with Generation's sale of the
retired New Boston generating site in 2016.
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Bargain purchase gain for the year ended December 31, 2018 compared to the year ended December 31, 2017 . decreased as a result of the gain associated
with the FitzPatrick acquisition. See Note 5 — Mergers, Acquisitions and Dispositions of the Combined Notes to Consolidated Financial Statements for additional
information.
Gain on deconsolidation of business for the year ended December 31, 2018 compared to the year ended December 31, 2017 decreased due to the
deconsolidation of EGTP's net liabilities, which included the previously impaired assets and related debt, as a result of the November 2017 bankruptcy filing. See
Note 5 — Mergers, Acquisitions and Dispositions of the Combined Notes to Consolidated Financial Statements for additional information.
Other, Net decreased primarily due to the net decrease in unrealized gains related to the NDT funds of Generation’s Non-Regulatory Agreement Units as
described in the table below. Other, net also reflects $45 million , $209 million and $80 million for the years ended December 31, 2018 , 2017 and 2016
respectively, related to the contractual elimination of income tax expense (benefit) associated with the NDT funds of the Regulatory Agreement Units. See Note
15 — Asset Retirement Obligations of the Combined Notes to Consolidated Financial Statements for additional information regarding NDT funds.
The following table provides unrealized and realized gains (losses) on the NDT funds of the Non-Regulatory Agreement Units:
Net unrealized (losses) gains on NDT funds
Net realized gains on sale of NDT funds
2018
2017
2016
$
(483) $
180
521 $
95
194
35
Effective income tax rates were (29.5)% , (94.6)% and 32.9% for the years ended December 31, 2018, 2017 and 2016, respectively. The increase is primarily
related to impacts associated with the one-time remeasurement of deferred income taxes in 2017 as a result of the TCJA. See Note 14 — Income Taxes of the
Combined Notes to Consolidated Financial Statements for additional information of the change in the effective income tax rate.
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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
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
2018
2017
Favorable (unfavorable)
2018 vs. 2017 variance
2016
Favorable (unfavorable)
2017 vs. 2016 variance
$
5,882 $
5,536 $
346 $
5,254 $
2,155
3,727
1,641
3,895
(514)
(168)
1,458
3,796
1,335
1,427
92
1,530
940
311
2,586
5
1,146
(347)
33
(314)
832
168
850
296
2,573
1
1,323
(361)
22
(339)
984
417
(90)
(15)
(13)
4
(177)
14
11
25
(152)
249
775
293
2,598
7
1,205
(461)
(65)
(526)
679
301
$
664 $
567 $
97 $
378 $
282
(183)
99
103
(75)
(3)
25
(6)
118
100
87
187
305
(116)
189
Year Ended December 31, 2018 Compared to Year Ended December 31, 2017 . Net income increased by $97 million primarily due to higher electric
distribution and energy efficiency formula rate earnings (reflecting the impacts of increased capital investment). The TCJA did not significantly impact Net income
as the favorable income tax impacts were predominantly offset by lower revenues resulting from the pass back of the tax savings through customer rates.
Year Ended December 31, 2017 Compared to Year Ended December 31, 2016 . Net income increased $189 million primarily due to the recognition of the
penalty and the after-tax interest due on the asserted penalty related to the Tax Court's decision on Exelon's like-kind exchange tax position in 2016 and
increased electric distribution and transmission formula rate earnings (reflecting the impacts of increased capital investment and higher allowed electric
distribution ROE). The higher Net income was partially offset by the impact of weather conditions in 2016. See Revenue Decoupling discussion below for
additional information on the impact of weather.
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.
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The changes in RNF consisted of the following:
Weather (a)
Volume (a)
Pricing and customer mix (a)
Electric distribution revenue
Transmission revenue
Energy efficiency revenue (b)
Regulatory required programs (b)
Uncollectible accounts recovery, net
Other
Total (decrease) increase
Increase (Decrease)
2018 vs. 2017
Increase (Decrease)
2017 vs. 2016
$
$
— $
—
—
(127)
(43)
47
(97)
6
46
(168) $
(36)
(5)
(18)
170
60
16
(85)
(7)
4
99
__________
(a) For the year ended December 31, 2017, compared to the same period in 2016, the changes reflect the 2016 impacts of weather, volume and pricing and customer mix.
Pursuant to the revenue decoupling provision in FEJA, ComEd began recording an adjustment to revenue in the first quarter of 2017 to eliminate the favorable or
unfavorable impacts associated with variations in delivery volumes associated with above or below normal weather, number of customers or usage per customer.
(b) Beginning June 1, 2017, ComEd is deferring energy efficiency costs as a regulatory asset that will be recovered through the energy efficiency formula rate over the
weighted average useful life of the related energy efficiency measures.
Revenue Decoupling. The demand for electricity is affected by weather and customer usage. However, beginning January 1, 2017, 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, investments being recovered and allowed ROE. During the year ended December 31, 2018 , as compared to
the same period in 2017 , electric distribution revenue decreased $127 million , primarily due to the impact of the lower federal income tax rate, partially offset by
increased revenues due to higher rate base and increased Depreciation expense. During the year ended December 31, 2017 , as compared to the same period
in 2016 , electric distribution revenue increased $170 million , primarily due to increased capital investment, increased Depreciation expense, higher allowed
ROE due to an increase in treasury rates and revenue decoupling impacts (as described above). See Operating and Maintenance Expense below and Note 4
— 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. Transmission revenue decreased for the year ended
December 31, 2018 , primarily due to decreased peak load and the impact of the lower federal tax rate, partially offset by increased revenues due to higher rate
base and increased Depreciation expense. Transmission revenue increased for the year ended December 31, 2017 , primarily due to increased capital
investment, higher Depreciation expense, and increased highest daily peak load. See Operating and Maintenance Expense below and Note 4 — Regulatory
Matters of the Combined Notes to Consolidated Financial Statements for additional information.
Energy Efficiency Revenue. Beginning June 1, 2017, 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. See Depreciation and
amortization expense discussions below and Note 4 — Regulatory Matters of the Combined Notes to Consolidated Financial Statements for additional
information.
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Regulatory Required Programs represent revenues collected under approved rate riders to recover costs incurred for regulatory programs such as purchased
power administrative costs and energy efficiency and demand response through June 1, 2017 pursuant to FEJA. The riders are designed to provide full and
current cost recovery. The costs of such programs are included in Operating and maintenance expense. Revenues from regulatory programs decreased for the
year ended December 31, 2018 , as compared to the same period in 2017 , and for the year ended December 31, 2017 , as compared to the same period in
2016 , primarily due to the fact that beginning on June 1, 2017, ComEd is deferring energy efficiency costs as a regulatory asset that will be recovered through
the energy efficiency formula rate over the weighted average useful life of the related energy efficiency measures.
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 increase in Other revenue for the years ended December 31, 2018, as compared to the same period in 2017 primarily reflects mutual
assistance revenues associated with hurricane and winter storm restoration efforts. An equal and offsetting amount has been included in Operating and
maintenance expense and Taxes other than income.
See Note 24 — 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
Labor, other benefits, contracting and materials (a)
Pension and non-pension postretirement benefits expense
Storm costs
Uncollectible accounts expense—provision (b)
Uncollectible accounts expense—recovery, net (b)
BSC costs (a)(c)
Other (a)
Regulatory required programs
Energy efficiency and demand response programs (d)
Decrease in operating and maintenance expense
Increase (Decrease)
2018 vs. 2017
Increase (Decrease)
2017 vs. 2016
$
$
20 $
—
(19)
5
1
(5)
3
5
(97)
(92)
$
(41)
3
2
(6)
(1)
44
(19)
(18)
(85)
(103)
__________
(a)
Includes costs associated with mutual assistance provided to other utilities in 2018. An equal and offsetting increase has been recognized in Operating revenues for the
period presented.
(b) 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. An equal and offsetting amount has been recognized in Operating revenues for the periods presented.
(c) For the year ended December 31, 2017, primarily reflects increased information technology support services from BSC and includes the $8 million write-off of a regulatory
asset related to Constellation merger and integration costs for which recovery is no longer expected.
(d) Beginning June 1, 2017 ComEd is deferring energy efficiency costs as a regulatory asset that will be recovered through the energy efficiency over the weighted average
useful life of the related energy efficiency measures.
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The increases in Depreciation and amortization expense consisted of the following:
Depreciation expense (a)
Regulatory asset amortization (b)
Other
Total increase
Increase
2018 vs. 2017
Increase
2017 vs. 2016
$
$
36 $
53
1
90 $
60
7
8
75
__________
(a) Primarily reflects ongoing capital expenditures.
(b) Beginning in June 2017, includes amortization of ComEd's energy efficiency formula rate regulatory asset.
The decrease in Interest expense , net, for the year ended 2018 compared to the same period in 2017 , and for the year ended 2017 compared to the same
period in 2016 , consisted of the following:
Interest expense related to uncertain tax positions (a)
Interest expense on debt (including financing trusts)
Other
Decrease in interest expense, net
Increase (Decrease)
2018 vs. 2017
Increase (Decrease)
2017 vs. 2016
$
$
(13)
$
2
(3)
(14)
$
(104)
6
(2)
(100)
__________
(a) Primarily reflects the recognition of after-tax interest related to the Tax Court's decision on Exelon's like-kind exchange tax position in the 2016 and 2017. See Note 14 —
Income Taxes of the Combined Notes to Consolidated Financial Statements for additional information.
The increase in Other, net , for the year ended 2018 compared to the same period in 2017 , and for the year ended 2017 compared to the same period in 2016 ,
consisted of the following:
Other income and deductions, net (a)
AFUDC equity
Other
Increase (decrease) in Other, net
Increase
2018 vs. 2017
Increase (Decrease)
2017 vs. 2016
$
$
1 $
7
3
11 $
88
(2)
1
87
__________
(a) Primarily reflects the recognition of the penalty related to the Tax Court's decision on Exelon's like-kind exchange tax position in 2016.
Effective income tax rates for the years ended December 31, 2018 , 2017 and 2016 , were 20.2% , 42.4% and 44.3% , respectively. The decrease in the
effective income tax rate for the year ended December 31, 2018 , compared to the same period in 2017 is primarily due to the lower federal income tax rate as a
result of the TCJA. The decrease in the effective income tax rate for the year ended December 31, 2017 , compared to the same period in 2016 is primarily due
to the recognition of a non-deductible penalty related to the Tax Court's decision on Exelon's like-kind exchange tax position in the third quarter of 2016. See
Note 14 — Income Taxes of the Combined Notes to Consolidated Financial Statements for additional information regarding the components of the effective
income tax rates.
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Results of Operations—PECO
Operating revenues
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
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
2018
2017
Favorable (unfavorable)
2018 vs. 2017 variance
2016
Favorable (unfavorable)
2017 vs. 2016 variance
$
3,038 $
2,870 $
168 $
2,994 $
1,090
1,948
898
301
163
1,362
1
587
(129)
8
(121)
466
6
969
1,901
806
286
154
1,246
—
655
(126)
9
(117)
538
104
(121)
47
(92)
(15)
(9)
(116)
1
(68)
(3)
(1)
(4)
(72)
98
1,047
1,947
811
270
164
1,245
—
702
(123)
8
(115)
587
149
$
460 $
434 $
26 $
438 $
(124)
78
(46)
5
(16)
10
(1)
—
(47)
(3)
1
(2)
(49)
45
(4)
Year Ended December 31, 2018 Compared to Year Ended December 31, 2017 . Net income was higher due to favorable weather and volumes. The TCJA
did not significantly impact Net Income as the favorable income tax impacts were predominantly offset by lower revenues resulting from the requirement to pass
back the tax savings through customer rates.
Year Ended December 31, 2017 Compared to Year Ended December 31, 2016 . Net income was lower primarily due to unfavorable weather. The TCJA did
not significantly impact Net Income as the favorable income tax impacts were predominantly offset by lower revenues resulting from the requirement to pass
back the tax savings through customer rates.
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.
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The changes in RNF consisted of the following:
Weather
Volume
Pricing
Regulatory required programs
Other
Total increase (decrease)
$
$
2018 vs. 2017
Increase (Decrease)
2017 vs. 2016
Increase (Decrease)
Electric
Gas
Total
Electric
Gas
Total
39 $
22 $
61 $
(28) $
4 $
37
(75)
11
14
4
(1)
—
(4)
41
(76)
11
10
(18)
8
(31)
14
3
2
—
—
26 $
21 $
47 $
(55) $
9 $
(24)
(15)
10
(31)
14
(46)
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, 2018 compared to the same period in 2017 RNF was increased by the impact of favorable weather conditions in PECO's service territory. For the
year ended December 31, 2017 compared to the same period in 2016 RNF was reduced 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, 2018 and December 31, 2017 compared to the same periods in 2017 and 2016 ,
respectively, and normal weather consisted of the following:
Heating and Cooling Degree-Days
Heating Degree-Days
Cooling Degree-Days
2018
2017
Normal
2018 vs. 2017
2018 vs. Normal
4,539
1,584
3,949
1,490
4,487
1,411
14.9 %
6.3 %
1.2 %
12.3 %
For the Years Ended December 31,
% Change
Heating and Cooling Degree-Days
Heating Degree-Days
Cooling Degree-Days
2017
2016
Normal
2017 vs. 2016
2017 vs. Normal
3,949
1,490
4,041
1,726
4,603
1,290
(2.3)%
(13.7)%
(14.2)%
15.5 %
For the Years Ended December 31,
% Change
Volume. Delivery volume, exclusive of the effects of weather, for the year ended December 31, 2018 compared to the same period in 2017 , was driven by
electric and primarily reflects the impact of moderate economic and customer growth partially offset by the impact of energy efficiency initiatives on customer
usages primarily in the residential class. Additionally, the increase represents a shift in the volume profile across classes from the commercial and industrial
classes to the residential class.
Delivery volume, exclusive of the effects of weather, for the year ended December 31, 2017 compared to the same period in 2016, was driven by electric and
primarily reflects the impact of energy efficiency initiatives on customer usages for residential and small commercial and industrial electric classes, partially offset
by solid customer growth. Additionally, the decrease represents a shift in the volume profile across classes from residential and small commercial and industrial
to large commercial and industrial.
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Electric Retail Deliveries to Customers (in
GWhs)
2018
2017
% Change 2018 vs.
2017
Weather - Normal %
Change
2016
% Change 2017 vs.
2016
Weather - Normal %
Change
Retail Deliveries (a)
Residential
Small commercial & industrial
Large commercial & industrial
Public authorities & electric
railroads
Total electric retail deliveries
14,005
8,177
15,516
13,024
7,968
15,426
761
809
38,459
37,227
7.5 %
2.6 %
0.6 %
(5.9)%
3.3 %
3.5 %
0.2 %
0.4 %
(5.6)%
1.4 %
13,664
8,099
15,263
890
37,916
(4.7)%
(1.6)%
1.1 %
(9.1)%
(1.8)%
(1.8)%
(1.1)%
1.4 %
(9.1)%
(0.5)%
__________
(a) Reflects delivery volumes and revenue from customers purchasing electricity directly from PECO and customers purchasing electricity from a competitive electric
generation supplier as all customers are assessed distribution charges.
Number of Electric Customers
Residential
Small commercial & industrial
Large commercial & industrial
Public authorities & electric railroads
Total
As of December 31,
2018
2017
2016
1,480,925
152,797
3,118
9,565
1,469,916
151,552
3,112
9,569
1,456,585
150,142
3,096
9,823
1,646,405
1,634,149
1,619,646
Natural Gas Deliveries to customers (in
mmcf)
2018
2017
% Change 2018 vs.
2017
Weather-
Normal %
Change
2016
% Change 2017 vs.
2016
Weather-
Normal %
Change
Retail Deliveries (a)
Residential
Small commercial & industrial
Large commercial & industrial
Transportation
Total natural gas deliveries
43,450
21,997
65
26,595
92,107
37,919
20,515
23
26,382
84,839
14.6%
7.2%
182.6%
0.8%
8.6%
1.8 %
(0.4)%
175.8 %
(3.2)%
(0.2)%
36,872
19,525
50
27,630
84,077
2.8 %
5.1 %
(54.0)%
(4.5)%
0.9 %
0.6 %
1.9 %
28.3 %
(2.3)%
0.1 %
__________
(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.
Number of Gas Customers
Residential
Small commercial & industrial
Large commercial & industrial
Transportation
Total
As of December 31,
2018
2017
2016
482,255
44,170
1
754
477,213
43,887
5
771
472,606
43,664
4
790
527,180
521,876
517,064
Pricing for the year ended December 31, 2018 compared to the same period in 2017 reflects the anticipated pass back of the Tax Cuts and Jobs Act tax
savings through customer rates.
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The increase in Operating revenues net of purchased power and fuel expense as a result of pricing for the year ended December 31, 2017 compared to the
same period in 2016 reflects higher overall effective rates due to decreased usage in the residential and small commercial and industrial customer classes.
Operating revenues net of fuel expense as a result of pricing remained relatively consistent. See Note 4 — Regulatory Matters for additional information.
Regulatory Required Programs represent revenues collected under approved riders to recover costs incurred for regulatory programs such as smart meter,
energy efficiency 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.
Other revenue includes rental revenue, revenue related to late payment charges, mutual assistance revenues and wholesale transmission revenue.
See Note 24 — Segment Information of the Combined Notes to Consolidated Financial Statements for the presentation of PECO's revenue disaggregation.
The changes in Operating and maintenance expense consisted of the following:
Increase (Decrease)
2018 vs. 2017
Increase (Decrease)
2017 vs. 2016
Baseline
Labor, other benefits, contracting and materials
Storm-related costs (a)
Pension and non-pension postretirement benefits expense
BSC costs
Uncollectible accounts expense
Other
Regulatory required programs
Energy efficiency
Other
$
10 $
63
(7)
—
7
9
82
10
—
10
Increase (decrease) in operating and maintenance expense
__________
(a) Reflects increased costs incurred from the Q1 2018 winter storms.
The changes in Depreciation and amortization expense consisted of the following:
$
92 $
17
(7)
(3)
4
(5)
—
6
(10)
(1)
(11)
(5)
Depreciation expense (a)
Regulatory asset amortization
Increase in depreciation and amortization expense
__________
(a) Depreciation expense increased due to ongoing capital expenditures.
Increase (Decrease)
2018 vs. 2017
Increase (Decrease)
2017 vs. 2016
$
$
13 $
2
15
$
17
(1)
16
Taxes other than income increased for the year ended December 31, 2018 , compared to the same period in 2017 , primarily due to an increase in gross
receipts tax driven by increased electric revenue.
Taxes other than income decreased for the year ended December 31, 2017 , compared to the same period in 2016 , primarily due to a decrease in gross
receipts tax driven by decreases in electric revenue.
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Effective income tax rates were 1.3% , 19.3% and 25.4% for the years ended December 31, 2018 , 2017 and 2016 , respectively. The decrease is primarily
due to the lower federal income tax rate as a result of the TCJA. See Note 14 — Income Taxes of the Combined Notes to Consolidated Financial Statements for
additional information of the change in effective income tax rates.
Results of Operations—BGE
2018
2017
Favorable (unfavorable)
2018 vs. 2017 variance
2016
Favorable (unfavorable)
2017 vs. 2016 variance
Operating revenues
$
Purchased power and fuel expense
Revenues net of purchased power and fuel
expense
Other operating expenses
3,169 $
1,182
3,176 $
1,133
1,987
2,043
Operating and maintenance
Depreciation and amortization
Taxes other than income
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
Preference stock dividends
Net income attributable to common
shareholder
777
483
254
1,514
1
474
(106)
19
(87)
387
74
313
—
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
—
3,233 $
1,294
1,939
737
423
229
1,389
—
550
(103)
21
(82)
468
174
294
8
(57)
161
104
21
(50)
(11)
(40)
—
64
(2)
(5)
(7)
57
(44)
13
8
21
$
313 $
307 $
6
$
286 $
Year Ended December 31, 2018 Compared to Year Ended December 31, 2017 . Net income attributable to common shareholder increased by $6 million
primarily due to an increase in transmission formula rate revenues and the absence of the 2017 impairment of certain transmission-related income tax regulatory
assets offset by increased storm restoration costs as a result of storms in March 2018 and September 2018. The TCJA did not significantly impact Net income
attributable to common shareholder as the favorable income tax impacts were predominantly offset by lower revenues resulting from the pass back of the tax
savings through customer rates.
Year Ended December 31, 2017 Compared to Year Ended December 31, 2016 . Net income attributable to common shareholder increased by $21 million
primarily due to the impacts of the electric and natural gas distribution rate orders issued by the MDPSC in June 2016 and July 2016, an increase in
transmission formula rate revenues, the absence of cost disallowances resulting from the 2016 distribution rate orders issued by the MDPSC, and decreased
storm costs in 2017. These increases were partially offset by the favorable 2016 settlement of the Baltimore City conduit fee dispute, the initiation of cost
recovery of the AMI programs under the distribution rate orders and increased capital investment, higher income tax expense primarily resulting from higher
taxable income as well as a 2016 favorable adjustment, and the 2017 impairment of certain transmission-related income tax regulatory assets.
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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.
The changes in RNF consisted of the following:
2018 vs. 2017
Increase (Decrease)
2017 vs. 2016
Increase (Decrease)
Electric
Gas
Total
Electric
Gas
Total
Distribution rate increase (decrease)
Regulatory required programs
Transmission revenue
Other, net
Total (decrease) increase
$
$
(62) $
(28) $
(90) $
21 $
29 $
2
15
5
2
—
10
4
15
15
17
18
5
3
—
11
(40) $
(16)
$
(56) $
61 $
43 $
50
20
18
16
104
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,
2018
2017
2016
1,168,372
1,160,783
1,150,096
113,915
12,253
262
113,594
12,155
272
113,230
12,053
280
1,294,802
1,286,804
1,275,659
As of December 31,
2018
2017
2016
633,757
38,332
5,954
678,043
629,690
38,392
5,855
673,937
623,647
37,941
6,314
667,902
Distribution Revenues decreased during the year ended December 31, 2018 , compared to the same period in 2017 , primarily due to the impact of reduced
distribution rates to reflect the lower federal income tax rate and increased during the year ended December 31, 2017 , compared to the same period in 2016 ,
primarily due to the impact of the electric and natural gas distribution rate changes that became effective in June 2016 in accordance with the electric and natural
gas distribution rate case orders in June 2016 and July 2016 . See Note 4 — 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
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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.
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 years ended
December 31, 2018 and 2017 primarily due to increases in capital investment and operating and maintenance expense recoveries. See Operating and
maintenance expense below and Note 4 — Regulatory Matters of the Combined Notes to Consolidated Financial Statements for additional information.
Other revenue includes revenue related to late payment charges, mutual assistance revenues, off-system sales and service application fees.
See Note 24 — 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
Impairment on long-lived assets and losses on regulatory assets (a)
Labor, other benefits, contracting and materials
Pension and non-pension postretirement benefits expense
Storm-related costs (b)
Uncollectible accounts expense
BSC costs
Conduit lease settlement (c)
Other
Regulatory Required Programs
Other
Total (decrease) increase
Increase (Decrease)
2018 vs. 2017
Increase (Decrease)
2017 vs. 2016
$
$
$
— $
18
(2)
39
2
7
—
3
67 $
(6)
61 $
(50)
(11)
—
(13)
7
16
15
7
(29)
8
(21)
__________
(a) See Note 4 — Regulatory Matters of the Combined Notes to Consolidated Financial Statements for additional information on Smart Meter and Smart Grid Investments.
(b) Reflects increased storm restoration costs incurred from storms in Q1 2018 and Q3 2018.
(c) See Note 22 — Commitments and Contingencies of the Combined Notes to Consolidated Financial Statements for additional information.
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The changes in Depreciation and amortization expense consisted of the following:
Depreciation expense (a)
Regulatory asset amortization (b)
Regulatory required programs
Increase in depreciation and amortization expense
Increase (Decrease)
2018 vs. 2017
Increase (Decrease)
2017 vs. 2016
$
$
25 $
(24)
9
10 $
13
25
12
50
__________
(a) Depreciation expense increased due to ongoing capital expenditures.
(b) Regulatory asset amortization decreased for the year ended December 31, 2018 compared to the same period in 2017 , primarily due to certain regulatory assets that
became fully amortized as of December 31, 2017 and increased for the year ended December 31, 2017 compared to the same period in 2016 , primarily due to energy
efficiency programs and the initiation of cost recovery of the AMI programs under the final electric and natural gas distribution rate case order issued by the MDPSC in
June 2016. See Note 4 — Regulatory Matters of the Combined Notes to Consolidated Financial Statements for additional information.
Taxes other than income increased for the year ended December 31, 2018 compared to the same period in 2017 , and for the year ended December 31, 2017
compared to the same period in 2016 , primarily due to an increase in property taxes.
Effective income tax rates were 19.1% , 41.5% and 37.2% for the years ended December 31, 2018 , 2017 and 2016 , respectively. Income taxes decreased
for the year ended December 31, 2018 compared to the same period in 2017 , primarily due to the lower federal income tax rate as a result of the TCJA. See
Note 14 — Income Taxes of the Combined Notes to Consolidated Financial Statements for additional information regarding the components of the effective
income tax rates.
Results of Operations—PHI
PHI’s results of operations include the results of its three reportable segments, Pepco, DPL and ACE. PHI also has a business services subsidiary, PHISCO,
which provides a variety of support services and the costs are directly charged or allocated to the applicable subsidiaries. Additionally, the results of PHI's
corporate operations include interest costs from various financing activities. For "Predecessor" reporting periods, PHI's results of operations also include the
results of PES and PCI. See Note 24 — Segment Information of the Combined Notes to Consolidated Financial Statements for additional information regarding
PHI's reportable segments. All material intercompany accounts and transactions have been eliminated in consolidation.
The following tables sets forth PHI's GAAP Net Income (Loss) by Registrant. As a result of the PHI Merger, the tables present two separate reporting periods for
2016. The "Predecessor" reporting periods represent PHI's results of operations for the period of January 1, 2016 to March 23, 2016 . The "Successor" reporting
periods represents PHI's results of operations for the years ended December 31, 2018 and 2017 as well as March 24, 2016 to December 31, 2016 . See the
results of operations for Pepco, DPL, and ACE for additional information by segment.
PHI
$
398 $
362 $
36 $
(61) $
19
For the Years Ended December 31,
Favorable (unfavorable)
2018 vs. 2017 variance
March 24 to December
31,
Successor
Predecessor
January 1 to
March 23,
2018
2017
2016
2016
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Pepco
DPL
ACE
For the Years Ended December 31,
Favorable (unfavorable)
2018 vs. 2017 variance
For the Years Ended December 31, Favorable (unfavorable)
2017 vs. 2016 variance
2018
2017
$
210 $
205 $
120
75
121
77
2017
2016
$
205 $
42 $
121
77
(9)
(42)
5
(1)
(2)
163
130
119
Other (a)
_________
(a) Primarily includes eliminating and consolidating adjustments, PHI’s corporate operations, shared service entities and other financing activities. Not included for 2016 due
n/a
34
(41)
(41)
n/a
(7)
to PHI Predecessor periods not being comparable.
Successor Year Ended December 31, 2018 Compared to Successor Year Ended December 31, 2017 . Net income increased by $36 million primarily due
to distribution rate increases (not reflecting the impact of the TCJA), favorable weather and volume, the absence of 2017 impairments of certain transmission-
related income tax regulatory assets and the DC sponsorship intangible asset, partially offset by an increase in asset retirement obligations primarily related to
asbestos identified at the Buzzard Point property and the deferral of accumulated merger integration cost as regulatory assets in 2017. T he TCJA did not
significantly impact Net income as the favorable tax impacts were predominantly offset by lower revenues resulting from the pass back of the tax savings
through customer rates.
Successor Period of March 24, 2016 to December 31, 2016 . Net loss for the Successor period of March 24, 2016 to December 31, 2016 was $61 million .
There were no significant changes in the underlying trends affecting PHI's results of operations during the Successor period March 24, 2016 to December 31,
2016 except for the pre-tax recording of $392 million of non-recurring merger-related costs including merger integration and merger commitments within
Operating and maintenance expense.
Predecessor Period of January 1, 2016 to March 23, 2016 . Net income for the Predecessor period of January 1, 2016 to March 23, 2016 was $19 million .
There were no significant changes in the underlying trends affecting PHI's results of operations during the Predecessor period of January 1, 2016 to March 23,
2016 except for the pre-tax recording of $29 million of non-recurring merger-related costs within Operating and maintenance expense and $18 million of
preferred stock derivative expense within Other, net.
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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
2018
2017
Favorable (unfavorable)
2018 vs. 2017 variance
2016
Favorable (unfavorable)
2017 vs. 2016 variance
$
2,239 $
2,158 $
81
$
2,186 $
654
1,585
501
385
379
614
1,544
454
321
371
(40)
41
(47)
(64)
(8)
(119)
(1)
(79)
(7)
(1)
(8)
(87)
92
5
706
1,480
642
295
377
1,314
8
174
(127)
36
(91)
83
41
$
42 $
(28)
92
64
188
(26)
6
168
(7)
225
6
(4)
2
227
(64)
163
Total other operating expenses
1,265
1,146
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
—
320
(128)
31
(97)
223
13
1
399
(121)
32
(89)
310
105
$
210 $
205 $
Year Ended December 31, 2018 Compared to Year Ended December 31, 2017 . Net income increased by $5 million primarily due to higher electric
distribution base rates (not reflecting the impact of the TCJA) in Maryland that became effective October 2017 and June 2018 and higher electric distribution
base rates (not reflecting the impact of the TCJA) in the District of Columbia that became effective August 2017 and August 2018, partially offset by an increase
in asset retirement obligations related primarily to the Buzzard Point property, deferral of accumulated merger integration costs as regulatory assets in 2017 and
higher regulatory asset amortization due to additional regulatory assets related to rate case activity. The TCJA did not significantly impact Net income as the
favorable tax impacts were predominantly offset by lower revenues resulting from pass back of tax savings through customer rates.
Year Ended December 31, 2017 Compared to Year Ended December 31, 2016 . Net income increased by $163 million primarily due to a decrease in
Operating and maintenance expense due to merger-related costs recognized in March 2016, higher electric distribution base rates in Maryland that became
effective November 2016 and October 2017 and higher electric distribution base rates in the District of Columbia that became effective August 2017, partially
offset by higher depreciation expense due to increased depreciation rates in Maryland effective November 2016. Income taxes expense included unrecognized
tax benefits of $21 million for uncertain tax positions related to the deductibility of certain merger commitments in the first quarter of 2017. This decrease was
offset by an increase in income taxes due to the $14 million December 2017 impairment of certain transmission related income tax regulatory assets.
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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.
The changes in RNF consisted of the following:
Volume
Distribution revenue
Regulatory required programs
Transmission revenues
Other
Total increase
Increase (Decrease)
2018 vs. 2017
Increase (Decrease)
2017 vs. 2016
12 $
(3)
35
—
(3)
41 $
16
66
(12)
9
(15)
64
$
$
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, 2018 compared to the same period in 2017 , and for the year ended
2017 compared to the same period in 2016 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,
2018
2017
2016
807,442
54,306
22,022
150
883,920
792,211
53,489
21,732
144
867,576
780,652
53,529
21,391
130
855,702
Distribution Revenues decreased for the year ended December 31, 2018 compared to the same period in 2017 primarily due to the impact of reduced
distribution rates to reflect the lower federal income tax rate, partially offset by higher electric distribution rates in Maryland that became effective in October 2017
and June 2018 and higher electric distribution rates in the District of Columbia that became effective August 2017 and August 2018. Distribution revenues
increased for the year ended December 31, 2017 compared to the same period in 2016 , primarily due to higher electric distribution rates in Maryland that
became effective in November 2016 and October 2017 and higher electric distribution rates in the District of Columbia that became effective August 2017. See
Note 4 — 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. Revenues from regulatory required programs increased for the year ended December 31, 2018 compared to the same period in 2017 primarily due to
increases in the Maryland and District of Columbia surcharge rates and sales due to higher volumes, as well as the DC PLUG surcharge which became effective
in February 2018. Revenues from regulatory required programs decreased for the year ended December 31, 2017 compared to the same period
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Table of Contents
in 2016 primarily due to lower demand-side management program surcharge revenue due to a decrease in kWh sales and a rate decrease effective January
2017.
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, 2017 compared to the same period in 2016 due to higher rates effective June 2017.
Other revenue includes rental revenue, revenue related to late payment charges, mutual assistance revenues and recoveries of other taxes. Other revenue
decreased for the year ended December 31, 2017 compared to the same period in 2016 due to lower pass-through revenue primarily the result of lower sales
that resulted in a decrease in utility taxes that are collected by Pepco on behalf of the jurisdiction.
See Note 24 - 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
ARO update (a)
Merger costs (b)
BSC and PHISCO costs (c)
Uncollectible accounts expense
Labor, other benefits, contracting and materials
Write-off of construction work in progress (d)
Remeasurement of AMI-related regulatory asset (e)
Other
Regulatory required programs
Total increase (decrease)
Increase (Decrease)
2018 vs. 2017
Increase (Decrease)
2017 vs. 2016
$
$
22 $
13
9
2
(2)
—
—
4
48
(1)
47 $
—
(132)
(24)
(11)
15
(14)
(7)
(9)
(182)
(6)
(188)
__________
(a) Reflects an increase primarily related to asbestos identified at the Buzzard Point property. See Note 15 - Asset Retirement Obligations of the Combined Notes to
Consolidated Financial Statements for additional information.
(b) Decrease in 2017 primarily due to merger-related commitments for customer rate credits and charitable contributions recognized in 2016. Increase in 2018 primarily due to
a deferral of accumulated merger integration costs as regulatory assets in 2017.
(c) Decrease in 2017 primarily related to merger severance and compensation costs recognized in 2016.
(d) Primarily resulting from a review of capital projects during the fourth quarter of 2016.
(e) Related to a remeasurement of a regulatory asset for legacy meters recognized in 2016.
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The changes in Depreciation and amortization expense consisted of the following:
Depreciation expense (a)
Regulatory asset amortization (b)
Regulatory required programs (c)
Total increase
Increase (Decrease)
2018 vs. 2017
Increase (Decrease)
2017 vs. 2016
$
$
14 $
25
25
64 $
28
8
(10)
26
_________
(a) Depreciation expense increased due to ongoing capital expenditures and higher depreciation rates in Maryland effective November 2016.
(b) Regulatory asset amortization increased due to additional regulatory assets related to rate case activity.
(c) Regulatory required programs increased as a result of higher amortization of the DC PLUG regulatory asset.
Taxes other than income for the year ended December 31, 2018 compared to the same period in 2017 increased primarily due to an increase in utility taxes
that are collected and passed through by Pepco (which is substantially offset in Operating revenues). Taxes other than income for the year ended December 31,
2017 compared to the same period in 2016 decreased primarily due to lower utility taxes that are collected and passed through by Pepco (which is substantially
offset in Operating revenues), partially offset by higher property taxes.
Gain on sales of assets for the year ended December 31, 2017 compared to the same period in 2016 decreased primarily due to the sale of land in May 2016.
Interest expense, net for the year ended December 31, 2018 compared to the same period in 2017 increased primarily due to higher outstanding debt. Interest
expense, net for the year ended December 31, 2017 compared to the same period in 2016 decreased primarily due to the recording of interest expense for an
uncertain tax position in 2016, partially offset by higher outstanding debt.
Other, net for the year ended December 31, 2017 compared to the same period in 2016 decreased primarily due to the September 2016 reversal of
contributions in aid of construction tax gross-up reserves due to the determination that there is no legal obligation to refund customers per contract term.
Effective income tax rates for the years ended December 31, 2018 , 2017 , and 2016 were 5.8% , 33.9% , and 49.4% , respectively. The decrease in the
effective income tax rate for the year ended December 31, 2018 compared to the same period in 2017 is primarily due to the lower federal income tax rate as a
result of the TCJA. See Note 14 — Income Taxes of the Combined Notes to Consolidated Financial Statements for additional information regarding the
components of the change in effective income tax rates
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Table of Contents
Results of Operations—DPL
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
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 (loss)
2018
2017
Favorable (unfavorable)
2018 vs. 2017 variance
2016
Favorable (unfavorable)
2017 vs. 2016 variance
$
1,332 $
1,300 $
32
$
1,277 $
561
771
344
182
56
582
1
190
(58)
10
(48)
142
22
532
768
315
167
57
539
—
229
(51)
14
(37)
192
71
(29)
3
(29)
(15)
1
(43)
1
(39)
(7)
(4)
(11)
(50)
49
583
694
441
157
55
653
9
50
(50)
13
(37)
13
22
$
120 $
121 $
(1)
$
(9) $
23
51
74
126
(10)
(2)
114
(9)
179
(1)
1
—
179
(49)
130
Year Ended December 31, 2018 Compared to Year Ended December 31, 2017 . Net income remained relatively consistent. The TCJA did not significantly
impact Net income as the favorable tax impacts were predominately offset by lower revenues resulting from the pass back of the tax savings through customer
rates.
Year Ended December 31, 2017 Compared to Year Ended December 31, 2016 . Net income increased $130 million primarily due to merger-related costs
recognized in March 2016, higher distribution base rates in Delaware that became effective July and December 2016 and higher distribution base rates in
Maryland that became effective February 2017, partially offset by higher depreciation expense due to increased depreciation rates in Maryland effective
February 2017. Income taxes expense included unrecognized tax benefits of $16 million for uncertain tax positions related to the deductibility of certain merger
commitments in the first quarter of 2017. This decrease was offset by an increase in income taxes due to the $6 million December 2017 impairment of certain
transmission-related income tax regulatory assets.
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
2018 vs. 2017
Increase (Decrease)
2017 vs. 2016
Increase (Decrease)
Electric
Gas
Total
Electric
Gas
Total
$
11 $
8 $
19 $
(7) $
(13) $
(20)
7
(20)
(2)
6
1
2
(6)
(5)
—
1
9
(26)
(7)
6
2
2
65
(3)
10
6
11
4
—
—
(1)
$
3
$
— $
3
$
73
$
1
$
13
69
(3)
10
5
74
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, 2018 compared to the same period in 2017 , RNF related to weather was higher due to the impact of favorable weather conditions in
DPL's Delaware service territory. During the year ended December 31, 2017 compared to the same period in 2016 , RNF related to weather was lower due to
the impact of 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 years ended
December 31, 2018 and December 31, 2017 compared to same periods in 2017 and 2016 , respectively, and normal weather consisted of the following:
Delaware Electric Service Territory
For the Years Ended December 31,
% Change
Heating and Cooling Degree-Days
2018
2017
Normal
2018 vs. 2017
2018 vs. Normal
Heating Degree-Days
Cooling Degree-Days
4,713
1,456
4,203
1,265
4,624
1,210
12.1 %
15.1 %
1.9 %
20.3 %
Heating and Cooling Degree-Days
2017
2016
Normal
2017 vs. 2016
2017 vs. Normal
Heating Degree-Days
Cooling Degree-Days
4,203
1,265
4,454
1,463
4,664
1,193
(5.6)%
(13.5)%
(9.9)%
6.0 %
For the Years Ended December 31,
% Change
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Delaware Natural Gas Service Territory
For the Years Ended December 31,
% Change
Heating Degree-Days
Heating Degree-Days
Heating Degree-Days
Heating Degree-Days
2018
2017
Normal
2018 vs. 2017
2018 vs. Normal
4,713
4,203
4,716
12.1 %
(0.1)%
For the Years Ended December 31,
% Change
2017
2016
Normal
2017 vs. 2016
2017 vs. Normal
4,203
4,454
4,739
(5.6)%
(11.3)%
Volume, exclusive of the effects of weather, increased for the year ended December 31, 2018 compared to the same period in 2017 primarily due to the impact
of increased average residential customer usage in DPL's Delaware service territory and overall customer growth. Volume increased for the year ended
December 31, 2017 compared to the same period in 2016 , primarily due to the impact of customer growth.
Electric Retail Deliveries to Delaware Customers (in
GWhs)
2018
2017
% Change
2018 vs. 2017
Weather - Normal
% Change
2016
% Change
2017 vs. 2016
Weather - Normal
% Change
Retail Deliveries
Residential
Small commercial & industrial
Large commercial & industrial
Public authorities & electric railroads
3,204
1,344
3,636
33
2,967
1,317
3,473
32
8.0%
2.1%
4.7%
3.1%
1.8%
—%
3.7%
3.4%
3,072
1,341
3,476
35
(3.4)%
(1.8)%
(0.1)%
(8.6)%
0.9 %
(0.2)%
0.9 %
(7.1)%
Total electric retail deliveries (a)
__________
(a) Reflects delivery volumes and revenues from customers purchasing electricity directly from DPL and customers purchasing electricity from a competitive electric
0.7 %
(1.7)%
2.3%
5.5%
7,789
7,924
8,217
generation supplier as all customers are assessed distribution charges.
Number of Total Electric Customers (Maryland and Delaware)
2018
2017
2016
As of December 31,
Residential
Small commercial & industrial
Large commercial & industrial
Public authorities & electric railroads
Total
463,670
61,381
1,406
621
459,389
60,697
1,400
629
527,078
522,115
456,181
60,173
1,411
643
518,408
Natural Gas Retail Deliveries to Delaware Customers (in
mmcf)
2018
2017
% Change
2018 vs. 2017
Weather Normal
% change
2016
% Change
2017 vs. 2016
Weather Normal
% change
Retail Deliveries
Residential
Small commercial & industrial
Large commercial & industrial
Transportation
8,633
4,134
1,952
6,831
7,445
3,754
1,908
6,538
16.0%
10.1%
2.3%
4.5%
3.4 %
(1.6)%
2.3 %
2.3 %
7,765
3,700
1,875
6,202
(4.1)%
1.5 %
1.8 %
5.4 %
1.1%
6.5%
1.7%
6.3%
Total natural gas deliveries (a)
_________
(a) Reflects delivery volumes and revenues from customers purchasing natural gas directly from DPL and customers purchasing natural gas from a competitive natural gas
3.8%
0.5 %
2.0 %
9.7%
19,542
19,645
21,550
supplier as all customers are assessed distribution charges.
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Number of Delaware Gas Customers
Residential
Small commercial & industrial
Large commercial & industrial
Transportation
Total
As of December 31,
2018
2017
2016
124,183
9,986
18
156
122,347
9,833
20
154
120,951
9,784
17
156
134,343
132,354
130,908
Distribution Revenue decreased for the year ended December 31, 2018 compared to the same period in 2017 primarily due to reduced electric distribution
rates and gas distribution rates in Delaware that were put into effect in March 2018 which reflect the impact of the lower federal income tax rate. Distribution
revenue increased for the year ended December 31, 2017 compared to the same period in 2016 , primarily due to higher electric distribution and natural gas
distribution base rates in Delaware that became effective in July and December 2016 and higher electric distribution base rates in Maryland that became
effective in February 2017. See Note 4 — 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, 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.
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, 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, 2018 compared to the same period in 2017 and for the year ended 2017 compared to the same period in 2016 due to higher rates effective June
2018 and June 2017.
Other revenue includes rental revenue, revenue related to late payment charges, mutual assistance revenues, and recoveries of other taxes.
See Note 24 - Segment Information for the Combined Notes to Consolidated Financial Statements for the presentation of DPL's revenue disaggregation.
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The changes in Operating and maintenance expense consisted of the following:
Baseline
Merger costs (a)
Energy efficiency merger commitments customer credits (b)
BSC and PHISCO costs (c)
Labor, other benefits, contracting and materials
Write-off of construction work in progress (d)
Uncollectible accounts expense
Other
Regulatory required programs
Total increase (decrease)
Increase (Decrease)
2018 vs. 2017
Increase (Decrease)
2017 vs. 2016
$
$
7 $
5
4
4
3
1
6
30
(1)
29 $
(94)
—
(15)
8
(3)
(10)
(5)
(119)
(7)
(126)
_________
(a) Decrease in 2017 primarily due to merger-related commitments for customer rate credits and charitable contributions recognized in 2016. Increase in 2018 primarily due to
a deferral of accumulated merger integration costs as regulatory assets in 2017.
(b) Related to EmPower Maryland energy efficiency customer credits.
(c) Decrease in 2017 primarily related to merger severance and compensation costs recognized in 2016.
(d) Decrease in 2017 primarily related to a review of capital projects in 2016.
The changes in Depreciation and amortization expense consisted of the following:
Depreciation expense (a)
Regulatory asset amortization (b)
Regulatory required programs (c)
Total increase
Increase (Decrease)
2018 vs. 2017
Increase (Decrease)
2017 vs. 2016
$
$
6 $
18
(9)
15 $
14
—
(4)
10
_________
(a) Depreciation expense increased due to ongoing capital expenditures and higher depreciation rates in Maryland effective February 2017.
(b) Regulatory asset amortization increased due to additional regulatory assets related to rate case activity.
(c) Regulatory required programs decreased primarily due to an EmPower Maryland surcharge rate decrease effective January 2018 and 2017.
Gain on sales of assets for the year ended December 31, 2017 compared to the same period in 2016 decreased primarily due to the sale of land in July and
December 2016.
Interest expense, net for the year ended December 31, 2018 compared to the same period in 2017 increased primarily due to higher outstanding debt.
Other, net for the year ended December 31, 2018 compared to the same period in 2017 decreased primarily due to lower income from AFUDC equity.
Effective income tax rates for the years ended December 31, 2018 , 2017 and 2016 were 15.5% , 37.0% and 169.2% , respectively. The decrease in the
effective income tax rate for the year ended December 31, 2018 compared to the same period in 2017 is primarily due to the lower federal income tax rate as a
result of the TCJA. See Note 14 — Income Taxes of the Combined Notes to Consolidated Financial Statements for additional information regarding the
components of the change in effective income tax rates
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Results of Operations—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
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 (loss)
2018
2017
Favorable (unfavorable)
2018 vs. 2017 variance
2016
Favorable (unfavorable)
2017 vs. 2016 variance
$
1,236 $
1,186 $
50
$
1,257 $
616
620
330
136
5
471
—
149
(64)
2
(62)
87
12
570
616
307
146
6
459
—
157
(61)
7
(54)
103
26
(46)
4
(23)
10
1
(12)
—
(8)
(3)
(5)
(8)
(16)
14
651
606
428
165
7
600
1
7
(62)
9
(53)
(46)
(4)
$
75 $
77 $
(2)
$
(42) $
(71)
81
10
121
19
1
141
(1)
150
1
(2)
(1)
149
(30)
119
Year Ended December 31, 2018 Compared to Year Ended December 31, 2017 . Net income remained relatively consistent. The TCJA did not significantly
impact Net income as the favorable income tax impacts were predominately offset by lower revenues resulting from the pass back of the tax savings through
customer rates.
Year Ended December 31, 2017 Compared to Year Ended December 31, 2016 . Net Income increased by $119 million primarily due to merger-related costs
recognized in March 2016 and higher electric distribution base rates effective August 2016 and October 2017 and an increase in transmission formula rate
revenues, partially offset by lower customer usage. Income taxes expense included unrecognized tax benefits of $22 million for uncertain tax positions related to
the deductibility of certain merger commitments in the first quarter of 2017. This decrease was offset by an increase in income taxes due to the December 2017
impairment of certain transmission-related income tax regulatory assets of $7 million.
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.
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The changes in RNF , consisted of the following:
Weather
Volume
Distribution revenue
Regulatory required programs
Transmission revenues
Other
Total increase
Increase (Decrease)
2018 vs. 2017
Increase (Decrease)
2017 vs. 2016
$
$
12 $
14
2
(23)
(4)
3
4 $
(3)
(20)
40
(24)
22
(5)
10
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, 2018 compared to the same period in 2017 , RNF related to weather was
higher due to the impact of favorable weather conditions in ACE's service territory. During the year ended December 31, 2017 compared to the same period in
2016 , RNF related to weather was lower due to the impact of unfavorable winter weather conditions.
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 years ended December 31, 2018 and December 31, 2017 compared to same periods in 2017 and 2016 ,
respectively, and normal weather consisted of the following:
Heating and Cooling Degree-Days
2018
2017
Normal
2018 vs. 2017
2018 vs. Normal
Heating Degree-Days
Cooling Degree-Days
4,523
1,535
4,206
1,228
4,666
1,135
7.5 %
25.0 %
(3.1)%
35.2 %
For the Years Ended December 31,
% Change
Heating and Cooling Degree-Days
2017
2016
Normal
2017 vs. 2016
2017 vs. Normal
Heating Degree-Days
Cooling Degree-Days
4,206
1,228
4,487
1,303
4,713
1,115
(6.3)%
(5.8)%
(10.8)%
10.1 %
For the Years Ended December 31,
% Change
Volume, exclusive of the effects of weather, increased for the year ended December 31, 2018 compared to the same period in 2017 , primarily due to higher
average residential and commercial usage. Volume, exclusive of the effects of weather, decreased for the year ended December 31, 2017 compared to the
same period in 2016 , primarily due to lower average customer usage, partially offset by the impact of customer growth.
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Electric Retail Deliveries to Customers
(in GWhs)
2018
2017
% Change 2018 vs.
2017
Weather - Normal %
Change
2016
% Change 2017 vs.
2016
Weather - Normal %
Change
Retail Deliveries (a)
Residential
Small commercial & industrial
Large commercial & industrial
Public authorities & electric
railroads
Total retail deliveries
Number of Electric Customers
Residential
Small commercial & industrial
Large commercial & industrial
Public authorities & electric railroads
4,185
1,361
3,565
49
9,160
3,853
1,286
3,399
47
8,585
8.6%
5.8%
4.9%
4.3%
6.7%
4.0%
3.5%
3.7%
4.5%
3.8%
4,153
1,455
3,402
49
9,059
(7.2)%
(11.6)%
(0.1)%
(4.1)%
(5.2)%
(6.2)%
(11.1)%
0.4 %
(4.1)%
(4.5)%
As of December 31,
2018
2017
2016
490,975
61,386
3,515
656
487,168
61,013
3,684
636
484,240
61,008
3,763
610
Total
__________
(a) Reflects delivery volumes and revenues from customers purchasing electricity directly from ACE and customers purchasing electricity from a competitive electric
549,621
556,532
552,501
generation supplier as all customers are assessed distribution charges.
Distribution Revenue increased for the year ended December 31, 2018 compared to the same period in 2017 primarily due to higher electric distribution base
rates that became effective in November 2017, partially offset by the impact of reduced distribution rates to reflect the lower federal income tax rate . Distribution
revenue increased for the year ended December 31, 2017 compared to the same period in 2016 , primarily due to higher electric distribution base rates that
became effective in August 2016 and October 2017. See Note 4 — 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 amortization
expense and Taxes other than income. Revenues from regulatory programs decreased for the year ended December 31, 2018 compared to the same period in
2017 , and for the year ended 2017 compared to the same period in 2016 due to rate decreases effective October 2017 and 2016 respectively 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, the highest daily peak load, which is updated annually in January based on the prior calendar year. Generally,
increases/decreases in the highest daily peak load will result in higher/lower transmission revenue. Transmission revenue decreased for the year ended
December 31, 2018 compared to the same period in 2017 primarily due to the impact of the lower federal income tax rate. Transmission revenue increased for
the year ended December 31, 2017 compared to the same period in 2016 due to higher rates effective June 2017 and June 2016 related to increases in
transmission plant investment and operating expenses.
Other revenue includes rental revenue, revenue related to late payment charges, mutual assistance revenues and recoveries of other taxes.
See Note 24 - Segment Information of the Combined Notes to Consolidated Financial Statements for the presentation of ACE's revenue disaggregation.
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The changes in Operating and maintenance expense consisted of the following:
Baseline
Labor, other benefits, contracting and materials
BSC and PHISCO costs (a)
Merger costs (b)
Uncollectible accounts expense (c)
Other
Regulatory required programs
Total increase (decrease)
_________
Increase (Decrease)
2018 vs. 2017
Increase (Decrease)
2017 vs. 2016
$
$
17 $
10
7
(8)
(2)
24
(1)
23 $
9
(11)
(120)
—
1
(121)
—
(121)
(a) Decrease in 2017 primarily related to merger severance and compensation costs recognized in 2016.
(b) Decrease in 2017 primarily related to merger-related commitments for customer rate credits and charitable contributions recognized in 2016. Increase in 2018 primarily
related to a deferral of accumulated merger integration costs as regulatory assets in 2017.
(c) 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 (b)
Required regulatory programs (c)
Other
Total decrease
Increase (Decrease)
2018 vs. 2017
Increase (Decrease)
2017 vs. 2016
$
$
5 $
5
(20)
—
(10)
$
6
(2)
(24)
1
(19)
_________
(a) Depreciation expense increased due to ongoing capital expenditures.
(b) Regulatory asset amortization increased due to additional regulatory assets related to rate case activity.
(c) Regulatory required programs decreased due to rate decreases effective October 2017 and 2016 respectively for the ACE Transition Bonds.
Other, net for the year ended December 31, 2018 compared to the same period in 2017 decreased primarily due to lower income from AFUDC equity.
Effective income tax rates were 13.8% , 25.2% , and 8.7% for the years ended December 31, 2018 , 2017 and 2016 , respectively. The decrease for the year
ended December 31, 2018 compared to the same period in 2017 primarily due to the lower federal income tax rate as a result of the TCJA. See Note 14 —
Income Taxes of the Combined Notes to Consolidated Financial Statements for additional information regarding the components of the change in effective
income tax rates.
Liquidity and Capital Resources
Exelon activity presented below includes the activity of PHI, Pepco, DPL and ACE, from the PHI Merger effective date of March 24, 2016 through December 31,
2018 . Exelon prior year activity is unadjusted for the effects of the
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Table of Contents
PHI Merger. Due to the application of push-down accounting to the PHI entity, PHI's activity is presented in two separate reporting periods, the legacy PHI
activity through March 23, 2016 (Predecessor), and PHI activity for the remainder of the period after the PHI merger date (Successor). For each of Pepco, DPL
and ACE the activity presented below include its activity for the years ended December 31, 2018 , 2017 and 2016 . 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
Registrant’s access to external financing on reasonable terms depends on its credit ratings and current overall capital market business conditions, including that
of the utility industry in general. If these conditions deteriorate to the extent that the Registrants no longer have access to the capital markets at reasonable
terms, the Registrants have access to unsecured revolving credit facilities with aggregate bank commitments of $9 billion . In addition, Generation has $ 545
million in bilateral facilities with banks which have various expirations between October 2019 and April 2021 and $159 in credit facilities for project finance. 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 13 — 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 15 - Asset Retirement Obligations of the Combined Notes to Consolidated Financial
Statements for additional information on the NRC minimum funding requirements.
If a nuclear plant were to early retire there is a risk that it will no longer meet the NRC minimum funding requirements due to the earlier commencement of
decommissioning activities and a shorter time period over which the NDT funds could appreciate in value. A shortfall could require that Generation address the
shortfall by, among other things, obtaining a parental guarantee for Generation’s share of the funding assurance. However, the amount of any guarantees or
other assurance will ultimately depend on the decommissioning approach, the associated level of costs, and the NDT fund investment performance going
forward. Within two years after shutting down a plant, Generation must submit a post-shutdown decommissioning activities report (PSDAR) to the NRC that
includes the planned option for decommissioning the site. As discussed in Note 15 - Asset Retirement Obligations of the Combined Notes to Consolidated
Financial Statements, Generation filed its annual decommissioning funding status report with the NRC on March 28, 2018 for shutdown reactors and reactors
within five years of shutdown. As of December 31, 2018 , across the alternative decommissioning approaches available, Exelon would not be required to post a
parental guarantee for TMI or Oyster Creek. In the event PSEG decides to early retire Salem, Generation estimates a parental guarantee of up to $30 million
from Exelon could be required for Salem, dependent upon the ultimate decommissioning approach selected.
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 additional 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). While the ultimate amounts may vary
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greatly and could be reduced by alternate decommissioning scenarios and/or reimbursement of certain costs under the DOE reimbursement agreements or
future litigation, across the alternative decommissioning approaches available, if TMI were to fail to obtain the exemption, Generation estimates it could incur
spent fuel management and site restoration costs over the next ten years of up to $125 million net of taxes, dependent upon the ultimate decommissioning
approach selected. In the event PSEG decides to early retire Salem and Salem were to fail to obtain the exemption, Generation estimates it could incur spent
fuel management and site restoration costs over the next ten years of up to $90 million net of taxes. On October 19, 2018, the NRC granted Generation's
exemption request to use the Oyster Creek NDT funds for non-radiological decommissioning costs.
On July 31, 2018, Generation entered into an agreement for the sale of Oyster Creek which is expected to occur in the second half of 2019. See Note 5 -
Mergers, Acquisitions and Dispositions for additional information on the sale of Oyster Creek to Holtec.
Junior Subordinated Notes
In June 2014, Exelon issued $1.15 billion of junior subordinated notes in the form of 23 million equity units at a stated amount of $50.00 per unit. Each equity unit
represented an undivided beneficial ownership interest in Exelon’s $1.15 billion of 2.50% junior subordinated notes due in 2024 (“2024 notes”) and a forward
equity purchase contract. As contemplated in the June 2014 equity unit structure, in April 2017, Exelon completed the remarketing of the 2024 notes into $1.15
billion of 3.497% junior subordinated notes due in 2022 (“Remarketing”). Exelon conducted the Remarketing on behalf of the holders of equity units and did not
directly receive any proceeds therefrom. Instead, the former holders of the 2024 notes used debt remarketing proceeds towards settling the forward equity
purchase contract with Exelon on June 1, 2017. Exelon issued approximately 33 million shares of common stock from treasury stock and received $1.15 billion
upon settlement of the forward equity purchase contract. When reissuing treasury stock Exelon uses the average price paid to repurchase shares to calculate a
gain or loss on issuance and records gains or losses directly to retained earnings. A loss on reissuance of treasury shares of $1.05 billion was recorded to
retained earnings as of December 31, 2017 . See Note 20 — Earnings Per Share of the Combined Notes to Consolidated Financial Statements for additional
information on the issuance of common stock.
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 4 — Regulatory Matters and Note 22 — Commitments and Contingencies of the Combined Notes to Consolidated Financial Statements for additional
information of regulatory and legal proceedings and proposed legislation.
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The following table provides a summary of the major items affecting Exelon’s cash flows from operations for the years ended December 31, 2018 , 2017 and
2016 :
Net income
Add (subtract):
Non-cash operating activities (a)
Pension and non-pension
postretirement benefit
contributions
Income taxes
Changes in working capital and other
noncurrent assets and liabilities (b)
Option premiums received (paid), net
Collateral received
(posted), net
Deposit with IRS
2018
2017
2018 vs. 2017 Variance
2016
2017 vs. 2016 Variance
$
2,084 $
3,876 $
(1,792) $
1,196
$
2,680
7,580
5,445
2,135
7,714
(2,269)
(383)
340
(1,016)
(43)
82
—
(405)
299
(1,605)
28
(158)
—
22
41
589
(71)
240
—
(397)
576
(243)
(66) —
931
(1,250)
(8)
(277)
(1,362)
94
(1,089)
1,250
(981)
Net cash flows provided by operations
$
8,644 $
7,480 $
1,164 $
8,461
$
__________
(a) Represents depreciation, amortization, depletion and accretion, net fair value changes related to derivatives, deferred income taxes, provision for uncollectible accounts,
pension and non-pension postretirement benefit expense, equity in earnings and losses of unconsolidated affiliates and investments, decommissioning-related items,
stock compensation expense, impairment of long-lived assets, gain on sale of assets and businesses and other non-cash charges. See Note 23 — Supplemental
Financial Information of the Combined Notes to Consolidated Financial Statements for additional information on non-cash operating activity.
(b) Changes in working capital and other noncurrent assets and liabilities exclude the changes in commercial paper, income taxes and the current portion of long-term debt.
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 of contributing the greater of (1) $300 million until all the qualified plans are fully funded on an ABO basis,
and (2) the minimum amounts under ERISA to meet minimum contribution requirements and/or avoid benefit restrictions and at-risk status. This level funding
strategy helps minimize volatility of future period required pension contributions. 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 other postretirement benefit plans, including liabilities management, levels of benefit claims paid and regulatory implications (amounts
deemed prudent to meet regulatory expectations and best assure continued rate recovery). The amounts below include benefit payments related to unfunded
plans.
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The following table provides all registrants' planned contributions to the qualified pension plans, planned benefit payments to non-qualified pension plans, and
planned contributions to other postretirement plans in 2019:
Exelon
Generation
ComEd
PECO
BGE
BSC
PHI
Pepco
DPL
ACE
PHISCO
Qualified Pension Plans
Non-Qualified Pension Plans
Other
Postretirement
Benefits
$
301 $
135
65
25
34
41
1
—
—
—
1
25 $
7
1
1
1
7
8
2
1
—
5
44
13
2
—
15
2
12
10
—
1
1
To the extent interest rates decline significantly or the pension and OPEB plans earn less than the expected asset returns, annual pension contribution
requirements in future years could increase. Conversely, to the extent interest rates increase significantly or the pension and OPEB plans earn greater than the
expected asset returns, annual pension and OPEB contribution requirements in future years could decrease. Additionally, expected contributions could change if
Exelon changes its pension or OPEB funding strategy.
Cash flows provided by operating activities for the year ended December 31, 2018 , 2017 and 2016 by Registrant were as follows:
Exelon
Generation
ComEd
PECO
BGE
Pepco
DPL
ACE
PHI
$
2018
2017
2016
8,644 $
3,861
1,749
739
789
474
352
228
7,480 $
3,299
1,527
755
821
407
321
206
8,461
4,442
2,505
829
945
651
310
385
2018
Successor
2017
March 24, 2016 to December
31, 2016
January 1, 2016 to March 23,
2016
Predecessor
$
1,132 $
950 $
888 $
264
Changes in Registrants' cash flows from operations for 2018, 2017, and 2016 were generally consistent with changes in each Registrant’s respective results of
operations, as adjusted by changes in working capital in the normal course of business. In addition, significant operating cash flow impacts for the Registrants for
2018 , 2017 and 2016 were as follows:
Generation
•
Depending upon whether Generation is in a net mark-to-market liability or asset position, collateral may be required to be posted with 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
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markets. During 2018 , 2017 and 2016 , Generation had net collections (payments) of counterparty cash collateral of $64 million , $(129) million and
$923 million , respectively, primarily due to market conditions that resulted in changes to Generation’s net mark-to-market position.
•
During 2018 , 2017 and 2016 , Generation had net (payments) collections of approximately $(43) million , $28 million and $(66) million , respectively,
related to purchases and sales of options. The level of option activity in a given year may vary due to several factors, including changes in market
conditions as well as changes in hedging strategy.
For additional information regarding changes in non-cash operating activities, see Note 23 — Supplemental Financial Information of the Combined Notes to
Consolidated Financial Statements.
Cash Flows from Investing Activities
Cash flows used in investing activities for the year ended December 31, 2018 , 2017 and 2016 by Registrant were as follows:
Exelon
Generation
ComEd
PECO
BGE
Pepco
DPL
ACE
PHI
2018
2017
2016
$
(7,834) $
(7,971) $
(2,531)
(2,097)
(840)
(950)
(654)
(362)
(334)
(2,662)
(2,230)
(597)
(875)
(628)
(429)
(313)
(15,450)
(3,816)
(2,685)
(797)
(910)
(616)
(336)
(307)
2018
Successor
2017
March 24, 2016 to December
31, 2016
January 1, 2016 to March 23,
2016
Predecessor
$
(1,371) $
(1,397) $
(993) $
(346)
Significant investing cash flow impacts for the Registrants for 2018 , 2017 and 2016 were as follows:
Exelon
•
•
During 2016, Exelon had expenditures of $6.6 billion related to the PHI merger.
During 2016, Exelon had proceeds of $360 million as a result of early termination of direct financing leases.
Exelon and Generation
•
•
•
•
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, respectively.
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 additional expenditures of $23 million and $178 million related to the acquisitions of ConEdison Solutions
and the FitzPatrick nuclear generating station, respectively.
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.
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•
During 2016, Exelon and Generation had expenditures of $235 million and $58 million related to the acquisitions of ConEdison Solutions and the
FitzPatrick nuclear generating station, respectively.
Capital Expenditure Spending
Capital expenditures by Registrant for 2018 , 2017 and 2016 and projected amounts for 2019 are as follows:
Exelon (b)
Generation
ComEd
PECO
BGE
Pepco
DPL
ACE
Projected
2019 (a)
$
7,325 $
1,950
1,875
975
1,100
725
350
300
2018
2017
2016
7,594 $
2,242
2,126
849
959
656
364
335
7,584 $
2,259
2,250
732
882
628
428
312
Predecessor
8,553
3,078
2,734
686
934
586
349
311
Projected
2019 (a)
2018
Successor
2017
March 24, 2016 to December
31, 2016
January 1, 2016 to March 23,
2016
PHI (c)
$
1,375 $
1,375 $
1,396 $
1,008 $
273
__________
(a) Total projected capital expenditures do not include adjustments for non-cash activity. Amounts are rounded to the nearest $25 million.
(b)
(c)
Includes corporate operations, BSC and PHISCO.
Includes PHISCO.
Projected capital expenditures and other investments are subject to periodic review and revision to reflect changes in economic conditions and other factors.
Generation
Approximately 43% and 8% of the projected 2019 capital expenditures at Generation are for the acquisition of nuclear fuel, and the construction of new natural
gas plants and solar facilities, respectively, with the remaining amounts reflecting investment in renewable energy and additions and upgrades to existing
facilities (including material condition improvements during nuclear refueling outages). Generation anticipates that it will fund capital expenditures with internally
generated funds and borrowings.
ComEd, PECO, BGE, Pepco, DPL and ACE
Projected 2019 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 2019 capital expenditures
above reflect capital spending for remediation to be completed through 2019. 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 2019 .
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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.
Cash Flows from Financing Activities
Cash flows (used in) provided by financing activities for the year ended December 31, 2018 , 2017 and 2016 by Registrant were as follows:
Exelon
Generation
ComEd
PECO
BGE
Pepco
DPL
ACE
PHI
$
2018
2017
2016
(219) $
(981)
534
(39)
156
193
32
105
767 $
(531)
789
50
22
219
64
5
1,191
(734)
169
(263)
(21)
—
67
22
2018
Successor
2017
March 24, 2016 to December
31, 2016
January 1, 2016 to March 23,
2016
Predecessor
$
330 $
306 $
(7)
$
372
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Debt
See Note 13 — 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 2018 , 2017 and 2016 by Registrant was as follows:
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.
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Table of Contents
(b) See Note 13 — Debt and Credit Agreements of the Combined Notes to Consolidated Financial Statements for additional information of nonrecourse debt.
(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 5 — Mergers, Acquisitions and Dispositions of the Combined Notes to Consolidated Financial Statements for additional information.
During 2016 , the following long term-debt was issued:
Company
Type
Interest Rate
Maturity
Amount
Use of Proceeds
Exelon Corporate
Senior Unsecured Notes
2.45%
April 15, 2021
Exelon Corporate
Senior Unsecured Notes
3.40%
April 15, 2026
Exelon Corporate
Senior Unsecured Notes
4.45%
April 15, 2046
Generation
Generation
Generation
Generation
Generation
Generation
Generation
Generation
ComEd
ComEd
PECO
BGE
Renewable Power
Generation Nonrecourse
Debt (a)
Albany Green Energy
Project Financing (b)
Energy Efficiency Project
Financing (b)
Energy Efficiency Project
Financing (b)
Energy Efficiency Project
Financing (b)
SolGen Nonrecourse Debt (a)
Energy Efficiency Project
Financing (b)
Energy Efficiency Project
Financing (b)
First Mortgage Bonds,
Series 120
First Mortgage Bonds,
Series 121
First Mortgage Bonds
Notes
4.11%
March 31, 2035
LIBOR + 1.25%
November 17, 2017
3.17%
December 31, 2017
3.90%
January 31, 2018
3.52%
April 30, 2018
3.93%
3.46%
September 30, 2036
October 1, 2018
2.61%
September 30, 2018
2.55%
June 15, 2026
3.65%
June 15, 2046
1.70%
2.40%
September 15, 2021
August 15, 2026
146
$
$
$
$
$
$
$
$
$
$
$
$
$
$
$
300
750
750
150
98
16
19
14
Repay commercial paper issued by PHI and for
general corporate purposes.
Repay commercial paper issued by PHI and for
general corporate purposes.
Repay commercial paper issued by PHI and for
general corporate purposes.
Paydown long-term debt obligations at Sacramento
PV Energy and Constellation Solar Horizons and
for general corporate purposes.
Albany Green Energy biomass generation
development.
Funding to install energy conservation measures in
Brooklyn, NY.
Funding to install energy conservation measures
for the Naval Station Great Lakes project.
Funding to install energy conservation measures
for the Smithsonian Zoo project.
150 General corporate purposes.
36
4
500
700
Funding to install energy conservation measures or
the Marine Corps Logistics Base project.
Funding to install energy conservation measures
for the Pensacola project.
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.
300 Refinance maturing mortgage bonds.
350
Redeem the $190M of outstanding preference
shares and for general corporate purposes.
Table of Contents
BGE
Pepco
DPL
Notes
3.50%
August 15, 2046
500
Energy Efficiency Project
Financing (b)
First Mortgage Bonds
3.30%
December 15, 2017
4
4.15%
May 15, 2045
175
Redeem the $190M of outstanding preference
shares and for general corporate purposes.
Funding to install energy conservation measures
for the DOE Germantown project.
Refinance maturing mortgage bonds, repay
commercial paper and for general corporate
purposes.
__________
(a) See Note 13 — Debt and Credit Agreements of the Combined Notes to Consolidated Financial Statements for additional information of nonrecourse debt.
(b) For Energy Efficiency Project Financing, the maturity dates represent the expected date of project completion, upon which the respective customer assumes the
outstanding debt.
During 2018 , the following long-term debt was retired and/or redeemed:
Type
Interest Rate
Maturity
Amount
Company
Exelon Corporate
Generation
Generation
Generation
Generation
Generation
Generation
Generation
Generation
Generation
Generation
Generation
Generation
ComEd
ComEd
PECO
DPL
Pepco
Pepco
ACE
Long-Term Software License Agreement
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
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%
May 1, 2024
June 30, 2018
March 31, 2019
September 30, 2018
June 30, 2019
December 31, 2031
September 30, 2036
2.29% - 3.56%
January 5, 2037
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%
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 13 — 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
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 13 — 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 5 — Mergers, Acquisitions and Dispositions for additional information.
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Table of Contents
During 2016 , 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
ComEd
PECO
BGE
BGE
BGE
BGE
PHI
DPL
ACE
ACE
Antelope Valley DOE Nonrecourse Debt (a)
Kennett Square Capital Lease
Continental Wind Nonrecourse Debt (a)
CEU Upstream Nonrecourse Debt (a)
ExGen Texas Power Nonrecourse Debt (a)(b)
Sacramento Solar Nonrecourse Debt
Clean Horizons Nonrecourse Debt
ExGen Renewables I, Nonrecourse Debt
PES - PGOV Notes Payable
NUKEM
NUKEM
Renewable Power Generation Nonrecourse Debt (a)
SolGen Nonrecourse Debt (a)
First Mortgage Bonds, Series 104
First Mortgage Bonds, Series 111
First and Refunding Mortgage Bonds
Rate Stabilization Bonds
Rate Stabilization Bonds
Notes
Rate Stabilization Bonds
Senior Unsecured Notes
First Mortgage Bonds
Transition Bonds
Transition Bonds
First Mortgage Bonds
3.95%
4.95%
May 1, 2024
June 15, 2035
2.29% - 3.56%
January 5, 2037
7.83%
6.00%
LIBOR + 2.25%
5.00%
LIBOR + 2.25%
LIBOR + 2.25%
LIBOR + 4.25%
6.70% - 7.46%
3.35%
3.25%
4.11%
3.93%
5.95%
1.95%
1.20%
5.72%
5.82%
5.90%
5.82%
5.90%
5.22%
5.05%
5.55%
September 20, 2020
February 28, 2033
January 14, 2019
September 18, 2021
December 31, 2030
September 7, 2030
February 6, 2021
2017-2018
June 30, 2018
July 1, 2018
March 31, 2035
September 30, 2036
August 15, 2016
August 1, 2016
October 15, 2016
April 1, 2016
April 1, 2017
October 1, 2016
April 1, 2017
December 12, 2016
December 30, 2016
October 20, 2020
October 20, 2023
$
$
$
$
$
$
$
$
$
$
$
$
$
$
$
$
$
$
$
$
$
$
$
$
$
$
$
8
1
22
4
29
46
7
33
32
24
1
12
10
9
2
415
250
300
1
38
300
40
190
100
12
34
ACE
__________
(a) See Note 13 — 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
August 23, 2016
7.68%
2
statements. See Note 5 — 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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Dividends
Cash dividend payments and distributions for the year ended December 31, 2018 , 2017 and 2016 by Registrant were as follows:
Exelon
Generation
ComEd
PECO
BGE (a)
Pepco
DPL
ACE
PHI
__________
(a)
2018
2017
2016
$
1,332 $
1,001
459
306
209
169
96
59
1,236 $
1,166
659
422
288
198
133
112
68
922
369
277
187
136
54
63
2018
Successor
2017
March 24, 2016 to December 31,
2016
January 1, 2016 to March 23, 2016
Predecessor
$
326 $
311 $
273 $
—
Includes dividends paid on BGE's preference stock during 2016.
Quarterly dividends declared by the Exelon Board of Directors during the year ended December 31, 2018 and for the first quarter of 2019 were as follows:
Period
Declaration Date
Shareholder of Record Date
Dividend Payable Date
First Quarter 2018
Second Quarter 2018
Third Quarter 2018
Fourth Quarter 2018
January 30, 2018
February 15, 2018
May 1, 2018
July 24, 2018
May 15, 2018
August 15, 2018
September 24, 2018
November 15, 2018
March 9, 2018 $
Cash per Share (a)
0.3450
June 8, 2018 $
September 10, 2018 $
December 1, 2018 $
0.3450
0.3450
0.3450
First Quarter 2019
___________
(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, 2019
February 5, 2019
March 8, 2019 $
0.3625
March 2018 dividend.
Short-Term Borrowings
Short-term borrowings incurred (repaid) during 2018 , 2017 and 2016 by Registrant were as follows:
Exelon
Generation
ComEd
BGE
Pepco
DPL
ACE
2018
2017
2016
$
(338) $
—
—
(42)
14
(216)
(94)
(261) $
(620)
—
32
3
216
108
(353)
620
(294)
(165)
(41)
(105)
(5)
150
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PHI
$
(296) $
328 $
(515) $
(121)
Successor
Predecessor
2018
2017
March 24, 2016 to December 31,
2016
January 1, 2016 to March 23, 2016
Retirement of Long-Term Debt to Financing Affiliates
On August 28, 2017, BGE redeemed all of the outstanding shares of BGE Capital Trust II 6.20% Preferred Securities.
Contributions from Parent/Member
Contributions from Parent/Member (Exelon) during 2018 , 2017 and 2016 by Registrant were as follows:
Generation
ComEd (a)(b)
PECO (b)
BGE (b)
Pepco (c)
DPL (c)
ACE (c)
2018
2017
2016
$
155 $
102 $
500
89
109
166
150
67
672
16
184
161
—
—
142
473
18
61
187
152
139
2018
Successor
2017
March 24, 2016 to December 31,
2016
January 1, 2016 to March 23, 2016
Predecessor
PHI
__________
(a) Additional contributions from parent or external debt financing may be required as a result of increased capital investment in infrastructure improvements and
modernization pursuant to EIMA, transmission upgrades and expansions and Exelon's agreement to indemnify ComEd for any unfavorable after-tax impacts associated
with ComEd's LKE tax matter.
758 $
1,251 $
385 $
—
$
(b) Contribution paid by Exelon.
(c) Contribution paid by PHI.
Pursuant to the orders approving the PHI merger, Exelon made equity contributions of $73 million , $46 million and $49 million to Pepco, DPL and ACE,
respectively, in the second quarter of 2016 to fund the after-tax amount of the customer bill credit and the customer base rate credit.
Redemptions of Preference Stock. BGE had $190 million of cumulative preference stock that was redeemable at its option at any time after October 1, 2015 for
the redemption price of $100 per share, plus accrued and unpaid dividends. On July 3, 2016, BGE redeemed all 400,000 shares of its outstanding 7.125%
Cumulative Preference Stock, 1993 Series and all 600,000 shares of its outstanding 6.990% Cumulative Preference Stock, 1995 Series for $100 million , plus
accrued and unpaid dividends. On September 18, 2016, BGE redeemed the remaining 500,000 shares of its outstanding 6.970% Cumulative Preference Stock,
1993 Series and the remaining 400,000 shares of its outstanding 6.700% Cumulative Preference Stock, 1993 Series for $90 million , plus accrued and unpaid
dividends. As of December 31, 2018 , BGE no longer has any preferred stock outstanding.
Other
For the year ended December 31, 2018 , other financing activities primarily consists of debt issuance costs. See Note 13 — Debt and Credit Agreements of the
Combined Notes to Consolidated Financial Statements’ for additional information.
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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 $9.7 billion (including bilateral credit
facilities and credit facilities for project finance) in aggregate total commitments of which $8.0 billion was available as of December 31, 2018 , 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
2018 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, 2018 , it would have been required to provide incremental collateral of $2.1 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 $4.1 billion of available credit capacity of its revolver.
The following table presents the incremental collateral that each Utility Registrant would have been required to provide in the event each Utility Registrant lost its
investment grade credit rating at December 31, 2018 and available credit facility capacity prior to any incremental collateral at December 31, 2018 :
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
$
9 $
—
12
11
5
—
— $
39
69
—
11
—
998
600
599
292
299
300
Exelon Corporate, ComEd, BGE, Pepco, DPL and ACE 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 intercompany
money pool. P HI 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 13 — Debt and Credit Agreements of the Combined Notes to Consolidated Financial Statements for additional information of the Registrants’ credit
facilities and short term borrowing activity.
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Other Credit Matters
Capital Structure. At December 31, 2018 , 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
51%
1%
47%
—%
1%
32%
44%
44%
46%
40%
49%
50%
4%
—%
64%
1%
55%
—%
3%
53%
—%
—%
53%
—%
—%
—
59%
—%
50%
—
—%
50%
—
—%
—
—%
1%
1%
1%
—%
48%
—%
46%
—
6%
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 2 — Variable Interest Entities of
the Combined Notes to Consolidated Financial Statements for additional information regarding the authoritative guidance for VIEs.
Security Ratings
The Registrants’ access to the capital markets, including the commercial paper market, and their respective financing costs in those markets, may depend on
the securities ratings of the entity that is accessing the capital markets.
The Registrants’ borrowings are not subject to default or prepayment as a result of a downgrading of securities, although such a downgrading of a Registrant’s
securities could increase fees and interest charges under that Registrant’s credit agreements.
As part of the normal course of business, the Registrants enter into contracts that contain express provisions or otherwise permit the Registrants and their
counterparties to demand adequate assurance of future performance when there are reasonable grounds for doing so. In accordance with the contracts and
applicable contracts law, if the Registrants are downgraded by a credit rating agency, it is possible that a counterparty would attempt to rely on such a
downgrade as a basis for making a demand for adequate assurance of future performance, which could include the posting of collateral. See Note 12 —
Derivative Financial Instruments of the Combined Notes to Consolidated Financial Statements for additional information on collateral provisions.
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Intercompany Money Pool
To provide an additional short-term borrowing option that will generally be more favorable to the borrowing participants than the cost of external financing, both
Exelon and PHI operate an intercompany money pool. Maximum amounts contributed to and borrowed from the money pool by participant and the net
contribution or borrowing as of December 31, 2018 , 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)
PHI Corporate
PHISCO
For the Year Ended December 31, 2018
Maximum
Contributed
Maximum
Borrowed
As of
December 31, 2018
Contributed (Borrowed)
674 $
227
285
—
—
57
For the Year Ended December 31, 2018
Maximum
Contributed
Maximum
Borrowed
1 $
34
— $
(389)
(420)
(403)
(35)
(1)
— $
—
216
(100)
—
(173)
—
57
1
3
As of
December 31, 2018
Contributed (Borrowed)
$
$
Investments in NDT Funds. Exelon, Generation and CENG maintain trust funds, as required by the NRC, to fund certain costs of decommissioning nuclear
plants. The mix of securities in the trust funds is designed to provide returns to be used to fund decommissioning and to offset inflationary increases in
decommissioning costs. Generation actively monitors the investment performance of the trust funds and periodically reviews asset allocations in accordance
with Generation’s NDT fund investment policy. Generation’s and CENG's investment policies establish limits on the concentration of holdings in any one
company and also in any one industry. See Note 15 — Asset Retirement Obligations of the Combined Notes to Consolidated Financial Statements for additional
information regarding the trust funds, the NRC’s minimum funding requirements and related liquidity ramifications.
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 2019. 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)
Long-term Financing Authority (a)
Commission
Expiration Date
Amount
Commission
Expiration Date
Amount (c)
ComEd (b)
PECO
BGE
Pepco
DPL
FERC
FERC
FERC
FERC
FERC
December 31, 2019
$
December 31, 2019
December 31, 2019
December 31, 2019
December 31, 2019
ICC
PAPUC
MDPSC
2019 & 2021
$
December 31, 2021
N/A
MDPSC / DCPSC
December 31, 2020
MDPSC / DPSC
December 31, 2020
1,533
1,900
400
400
150
—
ACE
__________
(a) Generation currently has blanket financing authority it received from FERC in connection with its market-based rate authority.
December 31, 2019
NJBPU
NJBPU
December 31, 2019
2,500
1,500
700
500
500
350
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(b) ComEd had $440 million available in long-term debt refinancing authority and $1,093 million available in new money long-term debt financing authority from the ICC as of
December 31, 2018 and has an expiration date of June 1, 2019 and August 1, 2021, respectively.
(c) ACE is currently in the process of requesting its long-term debt financing authority.
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.
•
•
•
•
ComEd is subject to restrictions 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.
PECO is subject to restrictions 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.
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.
Pepco, DPL and ACE are subject to certain dividend restrictions established by settlements approved in the District of Columbia, Maryland,
Delaware, and New Jersey. Pepco, DPL and ACE are prohibited from paying a dividend on their common shares if (a) after the dividend payment,
Pepco's, DPL's or ACE's equity ratio would be below 48% as equity levels are calculated under the ratemaking precedents of the DCPSC, MDPSC,
DPSC, and NJBPU or (b) Pepco's, DPL's or 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% .
At December 31, 2018 , Exelon had retained earnings of $14,766 million , including Generation’s undistributed earnings of $3,724 million , ComEd’s retained
earnings of $1,337 million consisting of retained earnings appropriated for future dividends of $2,976 million partially offset by $1,639 million of unappropriated
retained deficit, PECO’s retained earnings of $1,242 million , BGE’s retained earnings $1,640 million , and PHI's undistributed earnings of $62 million . See Note
22 — Commitments and Contingencies of the Combined Notes to Consolidated Financial Statements for additional information regarding fund transfer
restrictions.
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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, 2018 under existing contractual obligations, including
payments due by period. See Note 22 — Commitments and Contingencies of the Combined Notes to Consolidated Financial Statements for additional
information regarding the Registrants’ commercial and other commitments, representing commitments potentially triggered by future events.
Exelon
Total
2019
2020 -
2021
2022 -
2023
Due 2024
and beyond
Payment due within
Long-term debt (a)
Interest payments on long-term debt (b)
$
35,265 $
1,328 $
5,033 $
3,933 $
22,840
1,446
2,689
2,372
Capital leases
Operating leases (c)(d)
Purchase power obligations (e)
Fuel purchase agreements (f)
Electric supply procurement (f)
AEC purchase commitments (f)
Curtailment services commitments (f)
Long-term renewable energy and REC commitments (g)
Other purchase obligations (h)
DC PLUG obligation (i)
Construction commitments (j)
PJM regional transmission expansion commitments (k)
SNF obligation (l)
ZEC commitments (m)
Pension contributions (n)
Total contractual obligations
36
1,378
1,121
5,984
2,836
2
129
1,838
6,626
160
21
396
1,171
1,404
2,276
21
140
365
1,235
1,828
1
29
137
4,676
30
21
141
—
168
301
6
292
484
2,078
1,008
1
74
265
1,323
60
—
237
—
337
616
1
223
98
1,269
—
—
26
274
247
60
—
18
—
332
752
24,971
16,333
8
723
174
1,402
—
—
—
1,162
380
10
—
—
1,171
567
607
$
83,483 $
11,867
$
14,503
$
9,605
$
47,508
__________
(a)
(b)
Includes $390 million due after 2024 to ComEd and PECO financing trusts.
Interest payments are estimated based on final maturity dates of debt securities outstanding at December 31, 2018 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, 2018 . Includes estimated interest payments due to
ComEd and PECO financing trusts.
Includes amounts related to shared use land arrangements.
(c)
(d) Excludes Generation's contingent operating lease payments associated with contracted generation agreements. These amounts are included within purchase power
obligations.
(e) Purchase power obligations include contingent operating lease payments associated with contracted generation agreements. Amounts presented represent Generation’s
expected payments under these arrangements at December 31, 2018 . Expected payments include certain fixed capacity charges which may be reduced based on plant
availability. Expected payments exclude renewable PPA contracts that are contingent in nature. Contained within Purchase power obligations are Net Capacity Purchases
of $126 million , $56 million , $35 million , $26 million , $20 million and $155 million for 2019 , 2020 , 2021 , 2022 , 2023 and thereafter, respectively.
(f) Represents commitments to purchase nuclear fuel, natural gas and related transportation, storage capacity and services, procure electric supply, and purchase AECs and
curtailment services.
(g) Primarily related to ComEd 20-year contracts for renewable energy and RECs beginning in June 2012. ComEd is permitted to recover its renewable energy and REC
costs from retail customers with no mark-up. The commitments represent the earliest and maximum settlements with suppliers for renewable energy and RECs under the
existing contract terms.
(h) Represents the future estimated value at December 31, 2018 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.
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Table of Contents
(i) Related to DC PLUG project costs for assets funded by the District of Columbia for which the District of Columbia has assessed a charge on Pepco. Pepco will recover
this charge from customers through a volumetric distribution rider. See Note 4 — Regulatory Matters of Combined Notes to Consolidated Financial Statements for
additional information.
(j) Represents commitments for Generation's ongoing investments in new natural gas generation construction. As of December 31, 2018, the commitments relate to the
construction of a new dual fuel, natural peaking facility in Massachusetts. Achievement of commercial operation related to this project is expected in 2019.
(k) Under their operating agreements with PJM, ComEd, PECO, BGE, DPL and ACE are committed to the construction of transmission facilities to maintain system reliability.
These amounts represent ComEd, PECO, BGE, DPL and ACE’s expected portion of the costs to pay for the completion of the required construction projects.
(l) See Note 22 — Commitments and Contingencies of the Combined Notes to Consolidated Financial Statements for additional information regarding SNF obligations.
(m) Annual ZEC commitment amounts will be published by the IPA each May prior to the start of the subsequent planning year. Amounts presented in the table represent
management's estimate of ComEd's obligation based on forward energy prices and load forecasts. ComEd is permitted to recover its ZEC costs from retail customers with
no mark-up.
(n) These amounts represent Exelon’s expected contributions to its qualified pension plans. The projected contributions reflect a funding strategy of contributing the greater of
$300 million until all the qualified plans are fully funded on an ABO basis, and the minimum amounts under ERISA to avoid benefit restrictions and at-risk status. This level
funding strategy helps minimize volatility of future period required pension contributions. These amounts represent estimates that are based on assumptions that are
subject to change. Qualified pension contributions for years after 2024 are not included. See Note 16 — Retirement Benefits of the Combined Notes to Consolidated
Financial Statements for additional information regarding estimated future pension benefit payments.
Generation
Long-term debt
Interest payments on long-term debt (a)
Capital leases
Operating leases (b)(c)
Purchase power obligations (d)
Fuel purchase agreements (e)
Other purchase obligations (f)
Construction commitments (g)
SNF obligation (h)
Total contractual obligations
Total
2019
2020 -
202 1
2022 -
202 3
Due 2024
and beyond
Payment due within
$
8,745 $
4,333
14
763
1,121
4,931
1,742
21
1,171
899 $
2,103 $
1,023 $
354
7
33
365
1,013
1,114
21
—
592
6
92
484
1,759
224
—
—
483
1
93
98
1,078
98
—
—
$
22,841 $
3,806
$
5,260
$
2,874
$
4,720
2,904
—
545
174
1,081
306
—
1,171
10,901
__________
(a)
Interest payments are estimated based on final maturity dates of debt securities outstanding at December 31, 2018 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, 2018 .
Includes amounts related to shared use land arrangements.
(b)
(c) Excludes Generation's contingent operating lease payments associated with contracted generation agreements. These amounts are included within purchase power
obligations.
(d) Purchase power obligations include contingent operating lease payments associated with contracted generation agreements. Amounts represent Generation’s expected
payments under these arrangements at December 31, 2018 . Expected payments include certain fixed capacity charges which may be reduced based on plant availability.
Expected payments exclude renewable PPA contracts that are contingent in nature. Contained within Purchase power obligations are Net Capacity Purchases of $126
million , $56 million , $35 million , $26 million , $20 million and $155 million for 2019 , 2020 , 2021 , 2022 , 2023 and thereafter, respectively.
(e) Primarily represents commitments to purchase fuel supplies for nuclear and fossil generation, including those related to CENG.
(f) Represents the future estimated value at December 31, 2018 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) Represents commitments for Generation's ongoing investments in new natural gas generation construction. As of December 31, 2018, the commitments relate to the
construction of a new dual fuel, natural peaking facility in Massachusetts. Achievement of commercial operation related to this project is expected in 2019.
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(h) See Note 22 — Commitments and Contingencies of the Combined Notes to Consolidated Financial Statements for additional information regarding SNF obligations.
ComEd
Long-term debt (a)
Interest payments on long-term debt (b)
Capital leases
Operating leases (c)
Electric supply procurement
Long-term renewable energy and REC commitments (d)
Other purchase obligations (e)
PJM regional transmission expansion commitments (f)
ZEC commitments (g)
Total contractual obligations
Total
2019
2020 -
202 1
2022 -
202 3
Due 2024
and beyond
Payment due within
$
8,385 $
6,512
300 $
339
850 $
646
— $
614
8
23
650
1,497
1,109
176
1,404
—
7
419
106
1,050
40
168
—
9
231
203
55
136
337
—
7
—
212
2
—
332
7,235
4,913
8
—
—
976
2
—
567
$
19,764 $
2,429
$
2,467
$
1,167
$
13,701
__________
(a)
(b)
Includes $206 million due after 2024 to a ComEd financing trust.
Interest payments are estimated based on final maturity dates of debt securities outstanding at December 31, 2018 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, 2018 . Includes estimated interest payments due to the
ComEd financing trust.
Includes amounts related to shared use land arrangements.
(c)
(d) Primarily related to ComEd 20-year contracts for renewable energy and RECs beginning in June 2012. ComEd is permitted to recover its renewable energy and REC
costs from retail customers with no mark-up. The commitments represent the maximum and earliest settlements with suppliers for renewable energy and RECs under the
existing contract terms.
(e) Represents the future estimated value at December 31, 2018 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.
(f) Under its operating agreement with PJM, ComEd is committed to the construction of transmission facilities to maintain system reliability. These amounts represent
ComEd’s expected portion of the costs to pay for the completion of the required construction projects.
(g) Annual ZEC commitment amounts will be published by the IPA each May prior to the start of the subsequent planning year. Amounts presented in the table represent
management's estimate of ComEd's obligation based on forward energy prices and load forecasts. ComEd is permitted to recover its ZEC costs from retail customers with
no mark-up.
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PECO
Long-term debt (a)
Interest payments on long-term debt (b)
Operating leases (c)(d)
Fuel purchase agreements (e)
Electric supply procurement (e)
AEC purchase commitments (e)
Other purchase obligations (f)
PJM regional transmission expansion commitments (g)
Total contractual obligations
Total
2019
2020 -
202 1
2022 -
202 3
Due 2024
and beyond
Payment due within
$
3,309 $
2,562
25
335
530
4
668
54
— $
300 $
131
5
116
453
2
501
27
261
10
151
77
2
156
18
400 $
242
2,609
1,928
10
33
—
—
10
9
—
35
—
—
1
—
$
7,487 $
1,235
$
975
$
704
$
4,573
__________
(a)
(b)
Includes $184 million due after 2024 to PECO financing trusts.
Interest payments are estimated based on final maturity dates of debt securities outstanding at December 31, 2018 and do not reflect anticipated future refinancing, early
redemptions or debt issuances.
Includes amounts related to shared use land arrangements.
(c)
(d) Amounts related to certain real estate leases and railroad licenses effectively have indefinite payment periods. As a result, PECO has excluded these payments from the
remaining years as such amounts would not be meaningful. PECO’s average annual obligation for these arrangements, included in each of the years 2019 - 2023 , was
$5 million . Also includes amounts related to shared use land arrangements.
(e) Represents commitments to purchase natural gas and related transportation, storage capacity and services, procure electric supply, and purchase AECs.
(f) Represents the future estimated value at December 31, 2018 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) Under its operating agreement with PJM, PECO is committed to the construction of transmission facilities to maintain system reliability. These amounts represent PECO’s
expected portion of the costs to pay for the completion of the required construction projects.
BGE
Long-term debt
Interest payments on long-term debt (a)
Operating leases (b)(c)(d)(e)
Fuel purchase agreements (f)
Electric supply procurement (f)
Curtailment services commitments (f)
Other purchase obligations (g)
PJM regional transmission expansion commitments (h)
Total contractual obligations
Total
2019
2020 -
202 1
2022 -
202 3
Due 2024
and beyond
Payment due within
$
2,900 $
1,971
143
434
1,070
61
584
89
— $
300 $
113
35
76
670
10
528
35
225
68
107
400
38
50
54
550 $
191
21
94
—
13
2
—
2,050
1,442
19
157
—
—
4
—
$
7,252 $
1,467
$
1,242
$
871
$
3,672
__________
(a)
Interest payments are estimated based on final maturity dates of debt securities outstanding at December 31, 2018 and do not reflect anticipated future refinancing, early
redemptions or debt issuances.
Includes amounts related to shared use land arrangements.
(b)
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(c) Amounts related to certain real estate leases and railroad licenses effectively have indefinite payment periods. As a result, BGE has excluded these payments from the
remaining years as such amounts would not be meaningful. BGE’s average annual obligation for these arrangements, included in each of the years 2019 - 2023 , was $1
million . 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 table above includes minimum future lease payments associated with a 6-year lease for the Baltimore City conduit system that became effective during the
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.
(f) Represents commitments to purchase natural gas and related transportation, storage capacity and services, procure electric supply, and curtailment services.
(g) Represents the future estimated value at December 31, 2018 of the cash flows associated with all contracts, both cancellable and non-cancellable, entered into between
the 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.
(h) Under its operating agreement with PJM, BGE is committed to the construction of transmission facilities to maintain system reliability. These amounts represent BGE’s
expected portion of the costs to pay for the completion of the required construction projects.
PHI
Long-term debt
Interest payments on long-term debt (a)
Capital leases
Operating leases (b)
Fuel purchase agreements (c)
Long-term renewable energy and REC commitments (c)
Electric supply procurement (c)
Curtailment services commitments (c)
Other purchase obligations (d)
DC PLUG obligation (e)
PJM regional transmission expansion commitments (f)
Total contractual obligations
Payment due within
Total
2019
2020 -
202 1
2022 -
202 3
Due 2024
and beyond
$
5,622 $
4,192
111 $
260
281 $
512
810 $
476
4,420
2,944
14
377
284
341
1,635
68
1,396
160
77
14
48
30
31
993
19
893
30
39
—
89
61
62
642
36
437
60
29
—
81
64
62
—
13
34
60
9
—
159
129
186
—
—
32
10
—
$
14,166 $
2,468 $
2,209 $
1,609 $
7,880
__________
(a)
Interest payments are estimated based on final maturity dates of debt securities outstanding at December 31, 2018 and do not reflect anticipated future refinancing, early
redemptions or debt issuances.
Includes amounts related to shared use land arrangements.
(b)
(c) Represents commitments to purchase natural gas and related transportation, storage capacity and services, procure electric renewable energy and RECs, procure electric
supply, and curtailment services.
(d) Represents the future estimated value at December 31, 2018 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.
(e) Related to DC PLUG project costs for assets funded by the District of Columbia for which the District of Columbia has assessed a charge on Pepco. Pepco will recover
this charge from customers through a volumetric distribution rider. See Note 4 — Regulatory Matters of Combined Notes to Consolidated Financial Statements for
additional information.
(f) Under its operating agreement with PJM, PHI is committed to the construction of transmission facilities to maintain system reliability. These amounts represent PHI’s
expected portion of the costs to pay for the completion of the required construction projects.
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Pepco
Long-term debt
Interest payments on long-term debt (a)
Capital leases
Operating leases (b)
Electric supply procurement (c)
Curtailment services commitments (c)
Other purchase obligations (d)
DC PLUG obligation (e)
Total contractual obligations
Total
2019
2020 -
202 1
2022 -
202 3
Due 2024
and beyond
Payment due within
$
2,737 $
2,488
14
86
663
33
908
160
1 $
1 $
138
14
11
407
4
509
30
276
—
19
256
20
337
60
310 $
256
2,425
1,818
—
16
—
9
31
60
—
40
—
—
31
10
$
7,089 $
1,114 $
969 $
682 $
4,324
__________
(a)
Interest payments are estimated based on final maturity dates of debt securities outstanding at December 31, 2018 and do not reflect anticipated future refinancing, early
redemptions or debt issuances.
Includes amounts related to shared use land arrangements.
(b)
(c) Represents commitments to purchase procure electric supply and curtailment services.
(d) Represents the future estimated value at December 31, 2018 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.
(e) Related to DC PLUG project costs for assets funded by the District of Columbia for which the District of Columbia has assessed a charge on Pepco. Pepco will recover
this charge from customers through a volumetric distribution rider. See Note 4 — Regulatory Matters of Combined Notes to Consolidated Financial Statements for
additional information.
DPL
Long-term debt
Interest payments on long-term debt (a)
Operating leases (b)
Fuel purchase agreements (c)
Long-term renewable energy and associated REC commitments (c)
Electric supply procurement (c)
Curtailment services commitments (c)
Other purchase obligations (d)
PJM regional transmission expansion commitments (e)
Total contractual obligations
Total
2019
2020 -
202 1
2022 -
202 3
Due 2024
and beyond
Payment due within
$
1,504 $
1,050
96
284
341
458
31
266
9
91 $
57
14
30
31
282
12
187
3
— $
113
500 $
111
25
61
62
176
15
77
3
22
64
62
—
4
1
3
913
769
35
129
186
—
—
1
—
$
4,039 $
707 $
532 $
767 $
2,033
__________
(a)
Interest payments are estimated based on final maturity dates of debt securities outstanding at December 31, 2018 and do not reflect anticipated future refinancing, early
redemptions or debt issuances.
Includes amounts related to shared use land arrangements.
(b)
(c) Represents commitments to purchase natural gas and related transportation, storage capacity and services, procure electric renewable energy and RECs, procure electric
supply, and curtailment services.
(d) Represents the future estimated value at December 31, 2018 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.
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(e) Under its operating agreement with PJM, DPL is committed to the construction of transmission facilities to maintain system reliability. These amounts represent DPL’s
expected portion of the costs to pay for the completion of the required construction projects.
ACE
Long-term debt
Interest payments on long-term debt (a)
Operating leases (b)
Electric supply procurement (c)
Curtailment services commitments (c)
Other purchase obligations (d)
PJM regional transmission expansion commitments (e)
Total contractual obligations
Total
2019
2020 -
202 1
2022 -
202 3
Due 2024
and beyond
Payment due within
$
1,196 $
18 $
280 $
— $
465
32
514
4
177
68
52
7
304
3
160
36
95
11
210
1
16
26
81
9
—
—
1
6
898
237
5
—
—
—
—
$
2,456 $
580 $
639 $
97 $
1,140
__________
(a)
Interest payments are estimated based on final maturity dates of debt securities outstanding at December 31, 2018 and do not reflect anticipated future refinancing, early
redemptions or debt issuances.
Includes amounts related to shared use land arrangements.
(b)
(c) Represents commitments to procure electric supply and curtailment services.
(d) Represents the future estimated value at December 31, 2018 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.
(e) Under its operating agreement with PJM, ACE is committed to the construction of transmission facilities to maintain system reliability. These amounts represent ACE’s
expected portion of the costs to pay for the completion of the required construction projects.
See Note 22 — Commitments and Contingencies of the Combined Notes to Consolidated Financial Statements for additional information of the Registrants’
other commitments potentially triggered by future events.
For additional information regarding:
•
•
•
•
•
•
•
commercial paper, see Note 13 — Debt and Credit Agreements of the Combined Notes to Consolidated Financial Statements.
long-term debt, see Note 13 — Debt and Credit Agreements of the Combined Notes to Consolidated Financial Statements.
liabilities related to uncertain tax positions, see Note 14 — Income Taxes of the Combined Notes to Consolidated Financial Statements.
capital lease obligations, see Note 13 — Debt and Credit Agreements of the Combined Notes to Consolidated Financial Statements.
operating leases and rate relief commitments, see Note 22 — Commitments and Contingencies of the Combined Notes to Consolidated Financial
Statements.
the nuclear decommissioning and SNF obligations, see Note 15 — Asset Retirement Obligations and Note 22 — Commitments and Contingencies of
the Combined Notes to Consolidated Financial Statements.
regulatory commitments, see Note 4 — Regulatory Matters of the Combined Notes to Consolidated Financial Statements.
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•
•
•
variable interest entities, see Note 2 — Variable Interest Entities of the Combined Notes to Consolidated Financial Statements.
nuclear insurance, see Note 22 — Commitments and Contingencies of the Combined Notes to Consolidated Financial Statements.
new accounting pronouncements, see Note 1 — Significant Accounting Policies of the Combined Notes to Consolidated Financial Statements.
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 2019 through 2021 .
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, 2018 , the percentage of expected generation hedged for the Mid-Atlantic, Midwest,
New York and ERCOT reportable segments is 89% - 92% , 56% - 59% and 32% - 35% for 2019 , 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 generating facilities 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,
2018 market conditions and hedged position would be decreases in pre-tax net income of approximately $57 million , $383 million and $618 million ,
respectively, for 2019 , 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
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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 12
— Derivative Financial Instruments of the Combined Notes to Consolidated Financial Statements for additional information.
Proprietary Trading Activities
Proprietary trading portfolio activity for the year ended December 31, 2018 , resulted in pre-tax gains of $42 million due to net mark-to-market gains of $17
million and realized gains of $25 million . Generation has not segregated proprietary trading activity within the following discussion because of the relative size of
the proprietary trading portfolio in comparison to Generation’s total Revenue net of purchased power and fuel expense. See Note 12 — 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 62% of Generation’s uranium concentrate requirements
from 2019 through 2023 are supplied by three producers. In the event of non-performance by these or other suppliers, Generation believes that replacement
uranium concentrates can be obtained, 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.
ComEd
ComEd entered into 20-year contracts for renewable energy and RECs beginning in June 2012. ComEd is permitted to recover its renewable energy and REC
costs from retail customers with no mark-up. The annual commitments represent the maximum settlements with suppliers for renewable energy and RECs under
the existing contract terms. Pursuant to the ICC’s Order on December 19, 2012, ComEd’s commitments under the existing long-term contracts were reduced for
the June 2013 through May 2014 procurement period. In addition, the ICC’s December 18, 2013 Order approved the reduction of ComEd’s commitments under
those contracts for the June 2014 through May 2015 procurement period, and the amount of the reduction was approved by the ICC in March 2014.
ComEd has block energy contracts to procure electric supply that are executed through a competitive procurement process, which is further discussed in Note 4
— Regulatory Matters of the Combined Notes to Consolidated Financial Statements. The block energy contracts are considered derivatives and qualify for the
normal purchases and normal sales scope exception under current derivative authoritative guidance, and as a result are accounted for on an accrual basis of
accounting. ComEd does not execute derivatives for speculative or proprietary trading purposes. For additional information on these contracts, see Note 12 —
Derivative Financial Instruments of the Combined Notes to Consolidated Financial Statements.
PECO, BGE, Pepco, DPL and ACE
PECO, BGE, Pepco, DPL and ACE have contracts to procure electric supply that are executed through a competitive procurement process, which are further
discussed in Note 4 — Regulatory Matters of the Combined Notes to Consolidated Financial Statements. PECO, BGE, Pepco, DPL and ACE have certain full
requirements contracts, which are considered derivatives and qualify for the normal purchases and normal sales scope exception under current derivative
authoritative guidance, and as a result are accounted for on an accrual basis of accounting. Other full requirements contracts are not derivatives.
PECO, BGE and DPL have also executed derivative natural gas contracts, which either qualify for the normal purchases and normal sales exception 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.
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PECO, BGE, Pepco, DPL and ACE do not execute derivatives for speculative or proprietary trading purposes. For additional information on these contracts, see
Note 12 — 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, 2016 to December 31, 2018 . 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
12 — 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, 2018 and 2017 .
Total mark-to-market energy contract net assets (liabilities) at December 31, 2016 (a)
Total change in fair value during 2017 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 received
Option premium amortization
Upfront payments and amortizations (c)
Other miscellaneous (d)
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 (e)
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
$
719
$
977 $
(258)
110
(273)
(1)
140
(28)
(7)
(24)
31
667
270
(570)
(19)
8
(110)
43
(10)
20
110
(273)
—
137
(28)
(7)
(24)
31
923
270
(570)
(19)
—
(109)
43
(10)
20
—
—
2
—
—
—
—
—
(256)
—
—
—
7
—
—
—
—
Total mark-to-market energy contract net assets (liabilities) at December 31, 2018 (a)
__________
(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, 2017 and 2018 , ComEd recorded a regulatory
liability of $256 million and $249 million , respectively, related to its mark-to-market derivative liabilities with Generation and unaffiliated suppliers. ComEd recorded $18
million of decreases in fair value and an increase for realized losses due to settlements of $20 million in purchased power expense associated with floating-to-fixed energy
swap suppliers for the year ended December 31, 2017 . ComEd recorded $24 million of decreases in fair value
548 $
299 $
(249)
$
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and 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 .
Includes derivative contracts acquired or sold by Generation through upfront payments or receipts of cash, excluding option premiums, and the associated amortizations.
(c)
(d) As a result of the bankruptcy filing for EGTP on November 7, 2017, the net mark-to-market commodity contracts were deconsolidated from Exelon's and Generation's
consolidated financial statements.
Includes fair value from contracts received at acquisition of the Everett Marine Terminal.
(e)
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 11 — 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
2019
2020
2021
2022
2023
2024 and Beyond
Total Fair
Value
Maturities Within
Normal Operations, Commodity derivative contracts (a)(b) :
Actively quoted prices (Level 1)
$
(11) $
(33) $
(6) $
(8) $
14 $
Prices provided by external sources (Level 2)
45
(33)
5
—
—
Prices based on model or other valuation methods (Level
3) (c)
Total
291
174
—
(63)
(23)
$
325 $
108 $
(1) $
(71) $
(9) $
— $
—
(53)
(53) $
(44)
17
326
299
__________
(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 $357 million at December 31,
2018 .
Includes ComEd’s net assets (liabilities) associated with the floating-to-fixed energy swap contracts with unaffiliated suppliers.
(c)
Generation
2019
2020
2021
2022
2023
2024 and Beyond
Total Fair
Value
Maturities Within
Normal Operations, Commodity derivative contracts (a)(b) :
Actively quoted prices (Level 1)
$
(11) $
(33) $
(6) $
(8) $
14 $
Prices provided by external sources (Level 2)
45
(33)
5
—
—
Prices based on model or other valuation methods (Level
3) (c)
Total
317
199
25
(37)
3
$
351 $
133 $
24 $
(45) $
17 $
— $
—
68
68 $
(44)
17
575
548
__________
(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 $357 million at December 31,
2018 .
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ComEd
2019
2020
2021
2022
2023
2024 and Beyond
Fair
Value
Maturities Within
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.
(26) $
(25) $
(25) $
$
(26) $
(26) $
(121) $
(249)
Credit Risk, Collateral and Contingent Related Features (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 12 — Derivative Financial
Instruments of the Combined Notes to Consolidated Financial Statements for a detailed discussion of credit risk, collateral, and contingent related features.
Generation
The following tables provide information on Generation’s credit exposure for all derivative instruments, normal purchases and normal sales agreements, and
applicable payables and receivables, net of collateral and instruments that are subject to master netting agreements, as of December 31, 2018 . 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 tables below exclude credit risk exposure from
individual retail customers, uranium procurement contracts, and exposure through RTOs, ISOs and commodity exchanges, which are discussed below.
Additionally, the figures in the tables below exclude exposures with affiliates, including net receivables with ComEd, PECO, BGE, Pepco, DPL and ACE of $43
million , $30 million , $24 million , $28 million , $7 million and $5 million respectively. See Note 25 — Related Party Transactions of the Combined Notes to
Consolidated Financial Statements for additional information.
Rating as of December 31, 2018
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
795 $
133
181
92
— $
45
1
6
795
88
180
86
1,201 $
52 $
1,149
167
1 $
—
—
—
1 $
153
—
—
—
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Rating as of December 31, 2018
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
$
$
755 $
131
126
82
1,094 $
23 $
2
26
5
56 $
17 $
—
29
5
51 $
As of December 31, 2018
$
$
795
133
181
92
1,201
12
737
324
76
1,149
__________
(a) As of December 31, 2018 , credit collateral held from counterparties where Generation had credit exposure included $17 million of cash and $ 35 million of letters of credit.
The Utility Registrants
Credit risk for the Utility Registrants is governed by credit and collection policies, which are aligned with state regulatory requirements. The Utility Registrants are
currently obligated to provide service to all electric customers within their franchised territories. The Utility Registrants record 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, 2018 . See Note 4 — Regulatory Matters of the Combined Notes to Consolidated
Financial Statements for additional information.
As of December 31, 2018 , ComEd, PECO, BGE, Pepco, DPL and ACE's net credit exposure to suppliers was immaterial. See Note 12 — Derivative Financial
Instruments of the Combined Notes to Consolidated Financial Statements.
Collateral (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 12 — Derivative Financial Instruments of the Combined Notes to Consolidated Financial Statements for additional
information regarding collateral requirements. See Note 22 — 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
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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, 2018 , ComEd held $38 million in collateral from suppliers in association with energy procurement contracts, approximately $31 million in
collateral from suppliers for REC contract obligations and approximately $ 19 million in collateral from suppliers for long-term renewable energy contracts. BGE
is not required to post collateral under its electric supply contracts but was holding an immaterial amount of collateral under its electric supply procurement
contracts. BGE was not required to post collateral under its natural gas procurement contracts, but was holding an immaterial amount of collateral under its
natural gas procurement contracts. Pepco and DPL were not required to post collateral under their energy and/or natural gas procurement contracts, but were
holding an immaterial amount of collateral under their respective electric supply procurement contracts. PECO and ACE were not required to post collateral
under their energy and/or natural gas procurement contracts. See Note 4 — Regulatory Matters and Note 12 — 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, ISO-NY, CAISO, MISO,
SPP, AESO, OIESO and ERCOT. ERCOT is not subject to regulation by FERC but performs a similar function in Texas to that performed by RTOs in markets
regulated by FERC. In these areas, power is traded through bilateral agreements between buyers and sellers and on the spot energy markets that are
administered by the RTOs or ISOs, as applicable. In areas where there is no spot energy market, electricity is purchased and sold solely through bilateral
agreements. For sales into the spot markets administered by an RTO or ISO, the RTO or ISO maintains financial assurance policies that are established and
enforced by those administrators. The credit policies of the RTOs and ISOs may, under certain circumstances, require that losses arising from the default of one
member on spot energy market transactions be shared by the remaining participants. Non-performance or non-payment by a major counterparty could result in a
material adverse impact on the Registrants’ financial statements.
Exchange Traded Transactions (Exelon, Generation, PHI and DPL)
Generation enters into commodity transactions on NYMEX, ICE, NASDAQ, NGX and the Nodal exchange ("the Exchanges"). DPL enters into commodity
transactions on ICE. The Exchange clearinghouses act as the counterparty to each trade. Transactions on the Exchanges must adhere to comprehensive
collateral and margining requirements. As a result, transactions on Exchanges are significantly collateralized and have limited counterparty credit risk.
Interest Rate and Foreign Exchange Risk (All Registrants)
The Registrants use a combination of fixed-rate and variable-rate debt to manage interest rate exposure. The Registrants may also utilize interest rate swaps to
manage their interest rate exposure. At December 31, 2018 , Exelon had $800 million of notional amounts of fixed-to-floating hedges outstanding and Exelon
and Generation had $622 million of notional amounts of floating-to-fixed hedges outstanding. 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 $6 million decrease in
Exelon Consolidated pre-tax income for the year ended December 31, 2018 . 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
12 — Derivative Financial Instruments of the Combined Notes to Consolidated Financial Statements for additional information.
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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, 2018 ,
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 $529 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 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 six reportable segments consisting of the Mid-Atlantic, Midwest, New England, New York,
ERCOT and Other Power Regions. These segments are discussed in further detail in ITEM 1. BUSINESS — Exelon Generation Company, LLC of this Form 10-
K.
Executive Overview
A discussion of items pertinent to Generation’s executive overview is set forth under ITEM 7. MANAGEMENT'S DISCUSSION 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, 2018 Compared to Year Ended December 31, 2017 and Year Ended December 31, 2017 Compared to Year Ended
December 31, 2016
A discussion of Generation’s results of operations for 2018 compared to 2017 and 2017 compared to 2016 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 13 — 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.
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Cash Flows from Financing Activities
A discussion of items pertinent to Generation’s cash flows from financing activities is set forth under Cash Flows from Financing Activities in EXELON
CORPORATION — Liquidity and Capital Resources of this Form 10-K.
Credit Matters
A discussion of credit matters pertinent to Generation is set forth under Credit Matters in EXELON CORPORATION — Liquidity and 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 commodity price, 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, 2018 Compared to Year Ended December 31, 2017 and Year Ended December 31, 2017 Compared to Year Ended
December 31, 2016
A discussion of ComEd’s results of operations for 2018 compared to 2017 and for 2017 compared to 2016 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, 2018 , ComEd had access to a revolving credit facility with aggregate bank commitments of $1 billion .
See EXELON CORPORATION — Liquidity and Capital Resources and Note 13 — 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, 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
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, 2018 Compared to Year Ended December 31, 2017 and Year Ended December 31, 2017 Compared to Year Ended
December 31, 2016
A discussion of PECO’s results of operations for 2018 compared to 2017 and for 2017 compared to 2016 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, 2018 , PECO had access to a revolving credit facility with aggregate bank commitments of $600 million
.
See EXELON CORPORATION — Liquidity and Capital Resources and Note 13 — 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.
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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.
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, 2018 Compared to Year Ended December 31, 2017 and Year Ended December 31, 2017 Compared to Year Ended
December 31, 2016
A discussion of BGE’s results of operations for 2018 compared to 2017 and for 2017 compared to 2016 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, 2018 , BGE had access to a revolving credit facility with aggregate bank commitments of $600 million .
See EXELON CORPORATION — Liquidity and Capital Resources and Note 13 — 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
Successor Period Year Ended December 31, 2018 Compared to Year Ended December 31, 2017 , Successor Period of March 24, 2016 to
December 31, 2016 and Predecessor Period of January 1, 2016 to March 23, 2016
A discussion of PHI’s results of operations for 2018 compared to 2017 , March 24, 2016 to December 31, 2016 and January 1, 2016 to March 23, 2016 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 13 — 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 commodity price, 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, 2018 Compared to Year Ended December 31, 2017 and Year Ended December 31, 2017 Compared to Year Ended
December 31, 2016
A discussion of Pepco’s results of operations for 2018 compared to 2017 and for 2017 compared to 2016 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, 2018 , Pepco had access to a revolving credit facility with aggregate bank commitments of $300 million .
See EXELON CORPORATION — Liquidity and Capital Resources and Note 13 — 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, 2018 Compared to Year Ended December 31, 2017 and Year Ended December 31, 2017 Compared to Year Ended
December 31, 2016
A discussion of DPL’s results of operations for 2018 compared to 2017 and for 2017 compared to 2016 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, 2018 , DPL had access to a revolving credit facility with aggregate bank commitments of $300 million .
See EXELON CORPORATION — Liquidity and Capital Resources and Note 13 — 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 commodity price, 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, 2018 Compared to Year Ended December 31, 2017 and Year Ended December 31, 2017 Compared to Year Ended
December 31, 2016
A discussion of ACE’s results of operations for 2018 compared to 2017 and for 2017 compared to 2016 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, 2018 , ACE had access to a revolving credit facility with aggregate bank commitments of $300 million .
See EXELON CORPORATION — Liquidity and Capital Resources and Note 13 — 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, 2018 . 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, 2018 , Exelon’s internal control over financial
reporting was effective.
The effectiveness of Exelon’s internal control over financial reporting as of December 31, 2018 , has been audited by PricewaterhouseCoopers LLP, an
independent registered public accounting firm, as stated in their report which appears herein.
February 8, 2019
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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, 2018 . 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, 2018 , Generation’s internal control
over financial reporting was effective.
The effectiveness of Generation’s internal control over financial reporting as of December 31, 2018 , has been audited by PricewaterhouseCoopers LLP, an
independent registered public accounting firm, as stated in their report which appears herein.
February 8, 2019
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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, 2018 . 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, 2018 , ComEd’s internal control over financial
reporting was effective.
The effectiveness of ComEd’s internal control over financial reporting as of December 31, 2018 , has been audited by PricewaterhouseCoopers LLP, an
independent registered public accounting firm, as stated in their report which appears herein.
February 8, 2019
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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, 2018 . 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, 2018 , PECO’s internal control over financial
reporting was effective.
The effectiveness of PECO’s internal control over financial reporting as of December 31, 2018 , has been audited by PricewaterhouseCoopers LLP, an
independent registered public accounting firm, as stated in their report which appears herein.
February 8, 2019
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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, 2018 . 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, 2018 , BGE’s internal control over financial
reporting was effective.
The effectiveness of BGE’s internal control over financial reporting as of December 31, 2018 , has been audited by PricewaterhouseCoopers LLP, an
independent registered public accounting firm, as stated in their report which appears herein.
February 8, 2019
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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, 2018 . 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, 2018 , PHI’s internal control over financial reporting
was effective.
The effectiveness of PHI’s internal control over financial reporting as of December 31, 2018 , has been audited by PricewaterhouseCoopers LLP, an
independent registered public accounting firm, as stated in their report which appears herein.
February 8, 2019
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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, 2018 . 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, 2018 , Pepco’s internal control over financial
reporting was effective.
February 8, 2019
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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, 2018 . 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, 2018 , DPL’s internal control over financial reporting
was effective.
February 8, 2019
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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, 2018 . 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, 2018 , ACE’s internal control over financial
reporting was effective.
February 8, 2019
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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, 2018, 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, 2018 and 2017 , and the results of its operations and its cash flows for each of the three years in the period ended December 31, 2018 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, 2018, based on criteria established in Internal Control - Integrated Framework (2013) issued
by the COSO.
Basis for Opinions
The Company's management is responsible for these consolidated financial statements, for maintaining effective internal control over financial reporting, and for
its assessment of the effectiveness of internal control over financial reporting, included in Management’s Report on Internal Control Over Financial Reporting
appearing under Item 8. Our responsibility is to express opinions on the Company’s consolidated financial statements and on the Company's internal control
over financial reporting based on our audits. We are a public accounting firm registered with the Public Company Accounting Oversight Board (United States)
(PCAOB) and are required to be independent with respect to the Company in accordance with the U.S. federal securities laws and the applicable rules and
regulations of the Securities and Exchange Commission and the PCAOB.
We conducted our audits in accordance with the standards of the PCAOB. Those standards require that we plan and perform the audits to obtain reasonable
assurance about whether the consolidated financial statements are free of material misstatement, whether due to error or fraud, and whether effective internal
control over financial reporting was maintained in all material respects.
Our audits of the consolidated financial statements included performing procedures to assess the risks of material misstatement of the consolidated financial
statements, whether due to error or fraud, and performing procedures that respond to those risks. Such procedures included examining, on a test basis,
evidence regarding the amounts and disclosures in the consolidated financial statements. Our audits also included evaluating the accounting principles used
and significant estimates made by management, as well as evaluating the overall presentation of the consolidated financial statements. Our audit of internal
control over financial reporting included obtaining an understanding of internal control over financial reporting, assessing the risk that a material weakness exists,
and testing and evaluating the design and operating effectiveness of internal control based on the assessed risk. Our audits also included performing such other
procedures as we considered necessary in the circumstances. We believe that our audits provide a reasonable basis for our opinions.
Definition and Limitations of Internal Control over Financial Reporting
A company’s internal control over financial reporting is a process designed to provide reasonable assurance regarding the reliability of financial reporting and the
preparation of financial statements for external purposes in accordance with generally accepted accounting principles. A company’s internal control over
financial reporting includes those policies and procedures that (i) pertain to the maintenance of records that, in reasonable detail, accurately and fairly reflect the
transactions and dispositions of the assets of the company; (ii) provide reasonable assurance that transactions are recorded as necessary to permit preparation
of financial statements in accordance with generally accepted accounting principles, and that receipts and expenditures of the company are being made only in
accordance with authorizations of management and directors of the company; and (iii) provide reasonable
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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.
/s/ PricewaterhouseCoopers LLP
Chicago, Illinois
February 8, 2019
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
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)(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”). We also have audited the Company's internal control over financial reporting as of December 31, 2018,
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, 2018 and 2017 , and the results of its operations and its cash flows for each of the three years in the period ended December 31, 2018 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, 2018, based on criteria established in Internal Control - Integrated Framework (2013) issued
by the COSO.
Basis for Opinions
The Company's management is responsible for these consolidated financial statements, for maintaining effective internal control over financial reporting, and for
its assessment of the effectiveness of internal control over financial reporting, included in Management’s Report on Internal Control Over Financial Reporting
appearing under Item 8. Our responsibility is to express opinions on the Company’s consolidated financial statements and on the Company's internal control
over financial reporting based on our audits. We are a public accounting firm registered with the Public Company Accounting Oversight Board (United States)
(PCAOB) and are required to be independent with respect to the Company in accordance with the U.S. federal securities laws and the applicable rules and
regulations of the Securities and Exchange Commission and the PCAOB.
We conducted our audits in accordance with the standards of the PCAOB. Those standards require that we plan and perform the audits to obtain reasonable
assurance about whether the consolidated financial statements are free of material misstatement, whether due to error or fraud, and whether effective internal
control over financial reporting was maintained in all material respects.
Our audits of the consolidated financial statements included performing procedures to assess the risks of material misstatement of the consolidated financial
statements, whether due to error or fraud, and performing procedures that respond to those risks. Such procedures included examining, on a test basis,
evidence regarding the amounts and disclosures in the consolidated financial statements. Our audits also included evaluating the accounting principles used
and significant estimates made by management, as well as evaluating the overall presentation of the consolidated financial statements. Our audit of internal
control over financial reporting included obtaining an understanding of internal control over financial reporting, assessing the risk that a material weakness exists,
and testing and evaluating the design and operating effectiveness of internal control based on the assessed risk. Our audits also included performing such other
procedures as we considered necessary in the circumstances. We believe that our audits provide a reasonable basis for our opinions.
Definition and Limitations of Internal Control over Financial Reporting
A company’s internal control over financial reporting is a process designed to provide reasonable assurance regarding the reliability of financial reporting and the
preparation of financial statements for external purposes in accordance with generally accepted accounting principles. A company’s internal control over
financial reporting includes those policies and procedures that (i) pertain to the maintenance of records that, in reasonable detail, accurately and fairly reflect the
transactions and dispositions of the assets of the company; (ii) provide reasonable assurance that transactions are recorded as necessary to permit preparation
of financial statements in accordance with generally accepted accounting principles, and that receipts and expenditures of the company are being made only in
accordance with authorizations of management and directors of the company; and (iii) provide reasonable
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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.
/s/ PricewaterhouseCoopers LLP
Baltimore, Maryland
February 8, 2019
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
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)(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”). We also have audited the Company's internal control over financial reporting as of December 31, 2018,
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, 2018 and 2017 , and the results of its operations and its cash flows for each of the three years in the period ended December 31, 2018 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, 2018, based on criteria established in Internal Control - Integrated Framework (2013) issued
by the COSO.
Basis for Opinions
The Company's management is responsible for these consolidated financial statements, for maintaining effective internal control over financial reporting, and for
its assessment of the effectiveness of internal control over financial reporting, included in Management’s Report on Internal Control Over Financial Reporting
appearing under Item 8. Our responsibility is to express opinions on the Company’s consolidated financial statements and on the Company's internal control
over financial reporting based on our audits. We are a public accounting firm registered with the Public Company Accounting Oversight Board (United States)
(PCAOB) and are required to be independent with respect to the Company in accordance with the U.S. federal securities laws and the applicable rules and
regulations of the Securities and Exchange Commission and the PCAOB.
We conducted our audits in accordance with the standards of the PCAOB. Those standards require that we plan and perform the audits to obtain reasonable
assurance about whether the consolidated financial statements are free of material misstatement, whether due to error or fraud, and whether effective internal
control over financial reporting was maintained in all material respects.
Our audits of the consolidated financial statements included performing procedures to assess the risks of material misstatement of the consolidated financial
statements, whether due to error or fraud, and performing procedures that respond to those risks. Such procedures included examining, on a test basis,
evidence regarding the amounts and disclosures in the consolidated financial statements. Our audits also included evaluating the accounting principles used
and significant estimates made by management, as well as evaluating the overall presentation of the consolidated financial statements. Our audit of internal
control over financial reporting included obtaining an understanding of internal control over financial reporting, assessing the risk that a material weakness exists,
and testing and evaluating the design and operating effectiveness of internal control based on the assessed risk. Our audits also included performing such other
procedures as we considered necessary in the circumstances. We believe that our audits provide a reasonable basis for our opinions.
Definition and Limitations of Internal Control over Financial Reporting
A company’s internal control over financial reporting is a process designed to provide reasonable assurance regarding the reliability of financial reporting and the
preparation of financial statements for external purposes in accordance with generally accepted accounting principles. A company’s internal control over
financial reporting includes those policies and procedures that (i) pertain to the maintenance of records that, in reasonable detail, accurately and fairly reflect the
transactions and dispositions of the assets of the company; (ii) provide reasonable assurance that transactions are recorded as necessary to permit preparation
of financial statements in accordance with generally accepted accounting principles, and that receipts and expenditures of the company are being made only in
accordance with authorizations of management and directors of the company; and (iii) provide reasonable
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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.
/s/ PricewaterhouseCoopers LLP
Chicago, Illinois
February 8, 2019
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
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)(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”). We also have audited the Company's internal control over financial reporting as of December 31, 2018, 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, 2018 and 2017 , and the results of its operations and its cash flows for each of the three years in the period ended December 31, 2018 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, 2018, based on criteria established in Internal Control - Integrated Framework (2013) issued
by the COSO.
Basis for Opinions
The Company's management is responsible for these consolidated financial statements, for maintaining effective internal control over financial reporting, and for
its assessment of the effectiveness of internal control over financial reporting, included in Management’s Report on Internal Control Over Financial Reporting
appearing under Item 8. Our responsibility is to express opinions on the Company’s consolidated financial statements and on the Company's internal control
over financial reporting based on our audits. We are a public accounting firm registered with the Public Company Accounting Oversight Board (United States)
(PCAOB) and are required to be independent with respect to the Company in accordance with the U.S. federal securities laws and the applicable rules and
regulations of the Securities and Exchange Commission and the PCAOB.
We conducted our audits in accordance with the standards of the PCAOB. Those standards require that we plan and perform the audits to obtain reasonable
assurance about whether the consolidated financial statements are free of material misstatement, whether due to error or fraud, and whether effective internal
control over financial reporting was maintained in all material respects.
Our audits of the consolidated financial statements included performing procedures to assess the risks of material misstatement of the consolidated financial
statements, whether due to error or fraud, and performing procedures that respond to those risks. Such procedures included examining, on a test basis,
evidence regarding the amounts and disclosures in the consolidated financial statements. Our audits also included evaluating the accounting principles used
and significant estimates made by management, as well as evaluating the overall presentation of the consolidated financial statements. Our audit of internal
control over financial reporting included obtaining an understanding of internal control over financial reporting, assessing the risk that a material weakness exists,
and testing and evaluating the design and operating effectiveness of internal control based on the assessed risk. Our audits also included performing such other
procedures as we considered necessary in the circumstances. We believe that our audits provide a reasonable basis for our opinions.
Definition and Limitations of Internal Control over Financial Reporting
A company’s internal control over financial reporting is a process designed to provide reasonable assurance regarding the reliability of financial reporting and the
preparation of financial statements for external purposes in accordance with generally accepted accounting principles. A company’s internal control over
financial reporting includes those policies and procedures that (i) pertain to the maintenance of records that, in reasonable detail, accurately and fairly reflect the
transactions and dispositions of the assets of the company; (ii) provide reasonable assurance that transactions are recorded as necessary to permit preparation
of financial statements in accordance with generally accepted accounting principles, and that receipts and expenditures of the company are being made only in
accordance with authorizations of management and directors of the company; and (iii) provide reasonable
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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.
/s/ PricewaterhouseCoopers LLP
Philadelphia, Pennsylvania
February 8, 2019
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
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)(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”). We also have audited the Company's internal control over financial reporting as of December
31, 2018, 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, 2018 and 2017 , and the results of its operations and its cash flows for each of the three years in the period ended December 31, 2018 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, 2018, based on criteria established in Internal Control - Integrated Framework (2013) issued
by the COSO.
Basis for Opinions
The Company's management is responsible for these consolidated financial statements, for maintaining effective internal control over financial reporting, and for
its assessment of the effectiveness of internal control over financial reporting, included in Management’s Report on Internal Control Over Financial Reporting
appearing under Item 8. Our responsibility is to express opinions on the Company’s consolidated financial statements and on the Company's internal control
over financial reporting based on our audits. We are a public accounting firm registered with the Public Company Accounting Oversight Board (United States)
(PCAOB) and are required to be independent with respect to the Company in accordance with the U.S. federal securities laws and the applicable rules and
regulations of the Securities and Exchange Commission and the PCAOB.
We conducted our audits in accordance with the standards of the PCAOB. Those standards require that we plan and perform the audits to obtain reasonable
assurance about whether the consolidated financial statements are free of material misstatement, whether due to error or fraud, and whether effective internal
control over financial reporting was maintained in all material respects.
Our audits of the consolidated financial statements included performing procedures to assess the risks of material misstatement of the consolidated financial
statements, whether due to error or fraud, and performing procedures that respond to those risks. Such procedures included examining, on a test basis,
evidence regarding the amounts and disclosures in the consolidated financial statements. Our audits also included evaluating the accounting principles used
and significant estimates made by management, as well as evaluating the overall presentation of the consolidated financial statements. Our audit of internal
control over financial reporting included obtaining an understanding of internal control over financial reporting, assessing the risk that a material weakness exists,
and testing and evaluating the design and operating effectiveness of internal control based on the assessed risk. Our audits also included performing such other
procedures as we considered necessary in the circumstances. We believe that our audits provide a reasonable basis for our opinions.
Definition and Limitations of Internal Control over Financial Reporting
A company’s internal control over financial reporting is a process designed to provide reasonable assurance regarding the reliability of financial reporting and the
preparation of financial statements for external purposes in accordance with generally accepted accounting principles. A company’s internal control over
financial reporting includes those policies and procedures that (i) pertain to the maintenance of records that, in reasonable detail, accurately and fairly reflect the
transactions and dispositions of the assets of the company; (ii) provide reasonable assurance that transactions are recorded as necessary to permit preparation
of financial statements in accordance with generally accepted accounting principles, and that receipts and expenditures of the company are being made only in
accordance with authorizations of management and directors of the company; and (iii) provide reasonable
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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.
/s/ PricewaterhouseCoopers LLP
Baltimore, Maryland
February 8, 2019
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
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)(6)(i), and the financial
statement schedule listed in the index appearing under Item 15(a)(6)(iii), of Pepco Holdings LLC and its subsidiaries (Successor) (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, 2018,
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, 2018 and 2017 , and the results of its operations and its cash flows for each of the two years in the period ended December 31, 2018 and for the
period from March 24, 2016 to December 31, 2016 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, 2018, based on criteria
established in Internal Control - Integrated Framework (2013) issued by the COSO.
Basis for Opinions
The Company's management is responsible for these consolidated financial statements, for maintaining effective internal control over financial reporting, and for
its assessment of the effectiveness of internal control over financial reporting, included in Management’s Report on Internal Control Over Financial Reporting
appearing under Item 8. Our responsibility is to express opinions on the Company’s consolidated financial statements and on the Company's internal control
over financial reporting based on our audits. We are a public accounting firm registered with the Public Company Accounting Oversight Board (United States)
(PCAOB) and are required to be independent with respect to the Company in accordance with the U.S. federal securities laws and the applicable rules and
regulations of the Securities and Exchange Commission and the PCAOB.
We conducted our audits in accordance with the standards of the PCAOB. Those standards require that we plan and perform the audits to obtain reasonable
assurance about whether the consolidated financial statements are free of material misstatement, whether due to error or fraud, and whether effective internal
control over financial reporting was maintained in all material respects.
Our audits of the consolidated financial statements included performing procedures to assess the risks of material misstatement of the consolidated financial
statements, whether due to error or fraud, and performing procedures that respond to those risks. Such procedures included examining, on a test basis,
evidence regarding the amounts and disclosures in the consolidated financial statements. Our audits also included evaluating the accounting principles used
and significant estimates made by management, as well as evaluating the overall presentation of the consolidated financial statements. Our audit of internal
control over financial reporting included obtaining an understanding of internal control over financial reporting, assessing the risk that a material weakness exists,
and testing and evaluating the design and operating effectiveness of internal control based on the assessed risk. Our audits also included performing such other
procedures as we considered necessary in the circumstances. We believe that our audits provide a reasonable basis for our opinions.
Definition and Limitations of Internal Control over Financial Reporting
A company’s internal control over financial reporting is a process designed to provide reasonable assurance regarding the reliability of financial reporting and the
preparation of financial statements for external purposes in accordance with generally accepted accounting principles. A company’s internal control over
financial reporting includes those policies and procedures that (i) pertain to the maintenance of records that, in reasonable detail, accurately and fairly reflect the
transactions and dispositions of the assets of the company; (ii) provide reasonable assurance that transactions are recorded as necessary to permit preparation
of financial statements in accordance with generally accepted accounting principles, and that receipts and expenditures of the company are being made only in
accordance with authorizations of management and directors of the company; and (iii) provide reasonable
206
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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.
/s/ PricewaterhouseCoopers LLP
Washington, DC
February 8, 2019
We have served as the Company’s auditor since 2001.
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To the Board of Directors and Member of Pepco Holdings LLC
Report of Independent Registered Public Accounting Firm
In our opinion, the consolidated financial statements listed in the index appearing under Item 15(a)(6)(ii) present fairly, in all material respects, the results of
operations and cash flows of Pepco Holdings LLC and its subsidiaries (formerly Pepco Holdings, Inc.) (Predecessor) for the period January 1, 2016 to March 23,
2016 in conformity with accounting principles generally accepted in the United States of America. In addition, in our opinion, the financial statement schedule for
the period January 1, 2016 to March 23, 2016 listed in the index appearing under Item 15(a)(6)(iv) presents fairly, in all material respects, the information set
forth therein when read in conjunction with the related consolidated financial statements. These financial statements and financial statement schedule are the
responsibility of the Company's management. Our responsibility is to express an opinion on these financial statements and financial statement schedule based
on our audit. We conducted our audit of these financial statements in accordance with the standards of the Public Company Accounting Oversight Board
(United States). Those standards require that we plan and perform the audit to obtain reasonable assurance about whether the financial statements are free of
material misstatement. An audit includes examining, on a test basis, evidence supporting the amounts and disclosures in the financial statements, assessing
the accounting principles used and significant estimates made by management, and evaluating the overall financial statement presentation. We believe that our
audit provides a reasonable basis for our opinion.
/s/ PricewaterhouseCoopers LLP
Washington, DC
February 13, 2017
208
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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, 2018 and
2017, and the results of its operations and its cash flows for each of the three years in the period ended December 31, 2018 in conformity with accounting
principles generally accepted in the United States of America.
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 8, 2019
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, 2018 and
2017, and the results of its operations and its cash flows for each of the three years in the period ended December 31, 2018 in conformity with accounting
principles generally accepted in the United States of America.
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 8, 2019
We have served as the Company's auditor since at least 1993. We have not been able to determine the specific year we began serving as auditor of the
Company.
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Report of Independent Registered Public Accounting Firm
To the Board of Directors and Shareholder of Atlantic City Electric Company
Opinion on the Financial Statements
We have audited the consolidated financial statements, including the related notes, as listed in the index appearing under Item 15(a)(9)(i), and the financial
statement schedule listed in the index appearing under Item 15(a)(9)(ii), of Atlantic City Electric Company and its subsidiary (the "Company") (collectively
referred to as the “consolidated financial statements”). In our opinion, the consolidated financial statements present fairly, in all material respects, the financial
position of the Company as of December 31, 2018 and 2017, and the results of its operations and its cash flows for each of the three years in the period ended
December 31, 2018 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
Washington, DC
February 8, 2019
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 Incom e
(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
Total 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, 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 and preference stock dividends
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 (loss) on investments in unconsolidated affiliates
Unrealized (loss) gain on foreign currency translation
Other comprehensive income (loss)
Comprehensive income
Comprehensive income attributable to noncontrolling interests and preference stock dividends
Comprehensive income attributable to common shareholders
Average shares of common stock outstanding:
Basic
Diluted
Earnings per average common share:
Basic
Diluted
See the Combined Notes to Consolidated Financial Statements
For the Years Ended December 31,
2018
2017
2016
19,168 $
16,879
(62)
35,985
17,394 $
15,964
207
33,565
11,679
4,991
9,337
4,353
1,783
32,143
56
—
—
9,668
4,367
10,025
3,828
1,731
29,619
3
233
213
16,330
14,988
48
31,366
8,817
3,823
9,954
3,936
1,576
28,106
(48)
—
—
3,898
4,395
3,212
(1,529)
(1,524)
(1,495)
(25)
(112)
(1,666)
2,232
120
(28)
2,084
74
(36)
947
(613)
3,782
(126)
(32)
3,876
90
2,010
$
3,786
$
(41)
297
(1,239)
1,973
753
(24)
1,196
75
1,121
2,084 $
3,876 $
1,196
(66)
247
(143)
12
—
2
(10)
42
2,126
75
2,051 $
(56)
197
10
3
6
4
7
171
4,047
88
(48)
184
(181)
2
1
(4)
10
(36)
1,160
75
3,959
$
1,085
967
969
947
949
2.08 $
2.07
$
4.00 $
3.99 $
924
927
1.21
1.21
$
$
$
$
$
$
212
Table of Contents
(In millions)
Cash flows from operating activities
Net income
Exelon Corporation and Subsidiary Companies
Consolidated Statements of Cash Flows
For the Years Ended December 31,
2018
2017
2016
$
2,084 $
3,876 $
1,196
Adjustments to reconcile net income to net cash flows provided by operating activities:
Depreciation, amortization and accretion, including nuclear fuel and energy contract amortization
Impairment losses of long-lived assets, intangibles and regulatory assets
Gain on deconsolidation of business
(Gain) loss on sales of assets and businesses
Bargain purchase gain
Deferred income taxes and amortization of investment tax credits
Net fair value changes related to derivatives
Net realized and unrealized losses (gains) 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 received (posted), net
Income taxes
Pension and non-pension postretirement benefit contributions
Deposit with IRS
Other assets and liabilities
Net cash flows provided by operating activities
Cash flows from investing activities
Capital expenditures
Proceeds from termination of direct financing lease investment
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
Redemption of preference 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
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
$
5,971
50
—
(56)
—
(106)
294
303
1,124
(565)
(37)
551
(43)
82
340
(383)
—
(965)
8,644
(7,594)
—
8,762
(8,997)
—
(154)
91
58
(7,834)
(338)
126
(1)
3,115
(1,786)
—
—
—
(1,332)
105
—
(108)
(219)
591
1,190
1,781
5,427
573
(213)
(3)
(233)
(362)
151
(616)
721
(470)
(72)
(388)
28
(158)
299
(405)
—
(675)
7,480
(7,584)
—
7,845
(8,113)
(87)
(208)
219
(43)
(7,971)
(261)
621
(700)
3,470
(2,490)
(250)
1,150
—
(1,236)
150
396
(83)
767
276
914
$
1,190
$
5,576
306
—
48
—
656
24
(229)
1,333
(432)
7
771
(66)
931
576
(397)
(1,250)
(589)
8,461
(8,553)
360
9,496
(9,738)
—
(6,923)
61
(153)
(15,450)
(353)
240
(462)
4,716
(1,936)
—
—
(190)
(1,166)
55
372
(85)
1,191
(5,798)
6,712
914
See the Combined Notes to Consolidated Financial Statements
213
Table of Contents
(In millions)
Current assets
Cash and cash equivalents
Restricted cash and cash equivalents
Accounts receivable, net
Customer
Other
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
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)
E xelon Corporation and Subsidiary Companies
Consolidated Balance Sheets
ASSETS
December 31,
2018
2017
$
1,349 $
247
4,607
1,256
804
48
334
1,351
1,222
904
1,238
13,360
76,707
8,237
11,661
625
6,677
452
372
1,575
29,599
See the Combined Notes to Consolidated Financial Statements
214
$
119,666
$
898
207
4,445
1,132
976
60
340
1,311
1,267
—
1,260
11,896
74,202
8,021
13,272
640
6,677
337
395
1,330
30,672
116,770
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, 968 shares and 963 shares outstanding at
December 31, 2018 and 2017, respectively)
Treasury stock, at cost (2 shares at December 31, 2018 and 2017)
Retained earnings
Accumulated other comprehensive loss, net
Total shareholders’ equity
Noncontrolling interests
Total equity
Total liabilities and equity
December 31,
2018
2017
$
714 $
1,349
3,800
2,112
5
644
475
149
344
777
1,035
11,404
34,075
390
11,330
9,679
3,988
1,928
1,171
9,559
479
463
2,130
40,727
86,596
19,116
(123)
14,766
(2,995)
30,764
2,306
33,070
929
2,088
3,532
1,837
5
523
232
231
352
—
1,069
10,798
32,176
389
11,235
10,029
3,736
2,093
1,147
9,865
409
609
2,097
41,220
84,583
18,964
(123)
14,081
(3,026)
29,896
2,291
32,187
$
119,666
$
116,770
__________
(a)
Exelon’s consolidated assets include $9,667 million and $9,597 million at December 31, 2018 and 2017 , respectively, of certain VIEs that can only be used to settle the
liabilities of the VIE. Exelon’s consolidated liabilities include $3,548 million and $3,618 million at December 31, 2018 and 2017 , respectively, of certain VIEs for which the
VIE creditors do not have recourse to Exelon. See Note 2 – Variable Interest Entities for additional information.
See the Combined Notes to Consolidated Financial Statements
215
Table of Contents
(In millions, shares in thousands)
Balance, December 31, 2015
Net income
Long-term incentive plan activity
Employee stock purchase plan issuances
Tax benefit on stock compensation
Changes in equity of noncontrolling
interests
Adjustment of contingently redeemable
noncontrolling interest to redemption value
Common stock dividends
($1.26/common share)
Preferred and preference stock
Sale of noncontrolling interests
Redemption of preference stock
Other comprehensive loss, net of income
taxes
Exelon Corporation and Subsidiary Companies
Consolidated Statements of Changes in Equity
Shareholders' Equity
Issued
Shares
Common
Stock
Treasury
Stock
Retained
Earnings
Accumulated
Other
Comprehensive
Loss
Noncontrolling
Interests
Preference
Stock
Total
Equity
954,668
$
18,676
$
(2,327)
$
12,104
$
(2,624)
$
1,308
$
193
$
—
—
2,868
1,242
—
—
—
—
—
—
—
—
85
55
(18)
—
—
—
—
(4)
—
—
—
—
—
—
—
—
—
—
—
—
—
1,121
—
—
—
—
—
(1,172)
—
—
—
—
—
—
—
—
—
—
—
—
—
—
(36)
67
—
—
—
5
157
—
—
243
—
—
Balance, December 31, 2016
958,778
$
18,794
$
(2,327)
$
12,053
$
(2,660)
$
1,780
$
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
—
5,066
1,324
—
—
—
—
—
—
—
56
150
—
(36)
—
—
—
—
—
—
—
3,786
—
—
2,204
(1,054)
—
—
—
—
—
—
—
(1,243)
—
539
—
—
—
—
—
—
—
173
(539)
90
—
—
—
443
(20)
—
(2)
—
Balance, December 31, 2017
965,168
$
18,964
$
(123)
$
14,081
$
(3,026)
$
2,291
$
Net income
Long-term incentive plan activity
Employee stock purchase plan issuances
Changes in equity of noncontrolling
interests
Sale 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
—
—
—
—
—
—
—
—
—
—
—
2,010
—
—
—
—
(1,339)
—
14
—
—
—
—
—
—
41
(10)
74
—
—
(60)
—
—
1
—
8
—
—
—
—
—
—
(8)
—
(193)
$
$
—
—
—
—
—
—
—
—
—
—
—
—
—
—
—
—
—
—
—
—
27,330
1,196
85
55
(18)
5
157
(1,172)
(8)
239
(193)
(36)
27,640
3,876
56
150
1,150
407
(20)
(1,243)
171
—
32,187
2,084
41
105
(60)
6
(1,339)
42
4
Balance, December 31, 2018
970,020
$
19,116
$
(123)
$
14,766
$
(2,995)
$
2,306
$
—
$
33,070
See the Combined Notes to Consolidated Financial Statements
216
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
Total 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, 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 (loss) on investments in unconsolidated affiliates
Unrealized (loss) gain on foreign currency translation
Unrealized gain on marketable securities
Other comprehensive income
Comprehensive income
Comprehensive income attributable to noncontrolling interests
Comprehensive income attributable to membership interest
For the Years Ended December 31,
2018
2017
2016
$
19,169 $
17,385 $
1,268
20,437
1,115
18,500
11,679
14
4,803
661
1,797
556
9,671
19
5,602
697
1,457
555
16,318
1,439
17,757
8,818
12
5,000
663
1,879
506
19,510
18,001
16,878
48
—
—
975
(396)
(36)
(178)
(610)
365
(108)
(30)
443
73
2
233
213
947
(401)
(39)
948
508
1,455
(1,376)
(33)
2,798
88
370
$
2,710
$
(59)
—
—
820
(325)
(39)
401
37
857
282
(25)
550
67
483
443 $
2,798 $
550
12
1
(10)
—
3
3
4
7
1
15
446
$
2,813
$
74
86
372 $
2,727 $
2
(4)
10
1
9
559
67
492
$
$
$
$
See the Combined Notes to Consolidated Financial Statements
217
Table of Contents
(In millions)
Cash flows from operating activities
Net income
Exelon Generation Company, LLC and Subsidiary Companies
Consolidated Statements of Cash Flows
Adjustments to reconcile net income to net cash flows provided by operating activities:
Depreciation, amortization and accretion, including nuclear fuel and energy contract amortization
Impairment losses of long-lived assets
Gain on deconsolidation of business
(Gain) loss on sales of assets and businesses
Bargain purchase gain
Deferred income taxes and amortization of investment tax credits
Net fair value changes related to derivatives
Net realized and unrealized losses (gains) 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 received (posted), net
Income taxes
Pension and non-pension postretirement benefit contributions
Other assets and liabilities
Net cash flows provided by operating activities
Cash flows from investing activities
Capital expenditures
Proceeds from NDT fund sales
Investment in NDT funds
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
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
See the Combined Notes to Consolidated Financial Statements
218
For the Years Ended December 31,
2018
2017
2016
$
443 $
2,798 $
550
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)
—
1
(1)
15
(141)
46
(1,001)
155
—
(55)
(981)
349
554
903
$
3,056
510
(213)
(2)
(233)
(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
$
$
3,519
243
—
59
—
(277)
40
(229)
15
(152)
(21)
(4)
29
(66)
923
182
(152)
(217)
4,442
(3,078)
9,496
(9,738)
—
37
(293)
(240)
(3,816)
620
240
(162)
388
(202)
(1,191)
(922)
142
372
(19)
(734)
(108)
556
448
Table of Contents
(In millions)
Current assets
Cash and cash equivalents
Restricted cash and cash equivalents
Accounts receivable, net
Customer
Other
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
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)
Exelon Generation Company, LLC and Subsidiary Companies
Consolidated Balance Sheets
December 31,
2018
2017
ASSETS
$
750 $
153
2,941
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
219
416
138
2,697
321
976
140
60
264
937
—
933
6,882
24,906
13,272
433
47
334
1,502
395
16
670
16,669
48,457
Table of Contents
Exelon Generation Company, LLC and Subsidiary Companies
Consolidated Balance Sheets
(In millions)
LIABILITIES AND EQUITY
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
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,
2018
2017
$
— $
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
$
2
346
1,773
1,022
123
54
211
43
352
—
265
4,191
7,734
910
3,811
9,844
916
1,147
3,065
174
48
658
19,663
32,498
9,357
4,349
(37)
13,669
2,290
15,959
48,457
__________
(a) Generation’s consolidated assets include $9,634 million and $9,556 million at December 31, 2018 and 2017 , respectively, of certain VIEs that can only be used to settle
the liabilities of the VIE. Generation’s consolidated liabilities include $3,480 million and $3,516 million at December 31, 2018 and 2017 , respectively, of certain VIEs for
which the VIE creditors do not have recourse to Generation. See Note 2 – Variable Interest Entities for additional information.
See the Combined Notes to Consolidated Financial Statements
220
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, 2015
$
8,997 $
2,737 $
(63)
$
1,307 $
12,978
Net income
Sale of noncontrolling interests
Adjustment of contingently redeemable
noncontrolling interests due to release of
contingency
Changes in equity of noncontrolling interests
Contributions from member
Distributions to member
Other comprehensive income, net of income
taxes
—
(4)
—
—
268
—
—
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
Contributions from member
Distributions to member
Other comprehensive income (loss), net of
income taxes
—
(36)
—
33
99
—
—
483
—
—
—
—
(922)
—
2,298
2,710
—
—
—
—
(659)
—
—
—
—
—
—
—
9
67
243
157
5
—
—
—
$
(54)
$
1,779
$
—
—
—
—
—
—
17
88
443
(18)
—
—
—
(2)
550
239
157
5
268
(922)
9
13,284
2,798
407
(18)
33
99
(659)
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
Contributions from member
Distributions to member
Other comprehensive income, net of income
taxes
Impact of adoption of Recognition and
Measurement of Financial Assets and Liabilities
standard
—
6
—
155
—
—
—
370
—
—
—
(1,001)
—
6
—
—
—
—
—
2
(3)
73
—
(60)
—
—
1
—
443
6
(60)
155
(1,001)
3
3
Balance, December 31, 2018
$
9,518 $
3,724 $
(38)
$
2,304 $
15,508
See the Combined Notes to Consolidated Financial Statements
221
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
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,
2018
2017
2016
$
5,884 $
5,478 $
5,263
(29)
27
43
15
(24)
15
5,882
5,536
5,254
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
$
$
664 $
664 $
567 $
567 $
1,411
47
1,303
227
775
293
4,056
7
1,205
(448)
(13)
(65)
(526)
679
301
378
378
See the Combined Notes to Consolidated Financial Statements
222
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
Contributions from parent
Dividends paid on common stock
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
For the Years Ended December 31,
2018
2017
2016
$
664 $
567 $
940
259
242
(136)
26
1
70
11
62
(42)
(348)
1,749
(2,126)
29
(2,097)
—
1,350
(840)
500
(459)
(17)
534
186
144
850
659
164
(59)
8
4
(297)
(26)
(308)
(41)
6
(2,250)
20
(2,230)
—
1,000
(425)
651
(422)
(15)
789
86
58
378
775
439
215
(25)
3
1
339
7
306
(38)
105
(2,734)
49
(2,685)
(294)
1,200
(665)
315
(369)
(18)
169
(11)
69
58
1,527
2,505
Cash, cash equivalents and restricted cash at end of period
$
330 $
144 $
See the Combined Notes to Consolidated Financial Statements
223
Table of Contents
(In millions)
Current assets
Commonwealth Edison Company and Subsidiary Companies
Consolidated Balance Sheets
ASSETS
Cash and cash equivalents
Restricted cash and cash equivalents
Accounts receivable, net
Customer
Other
Receivables from affiliates
Inventories, net
Regulatory assets
Other
Total current assets
Property, plant and equipment, net
Deferred debits and other assets
Regulatory assets
Investments
Goodwill
Receivables from affiliates
Prepaid pension asset
Other
Total deferred debits and other assets
Total assets
December 31,
2018
2017
$
135 $
29
539
320
20
148
293
86
1,570
22,058
1,307
6
2,625
2,217
1,035
395
7,585
76
5
559
266
13
152
225
68
1,364
20,723
1,054
6
2,625
2,528
1,188
238
7,639
See the Combined Notes to Consolidated Financial Statements
224
$
31,213 $
29,726
Table of Contents
(In millions)
Current liabilities
Commonwealth Edison Company and Subsidiary Companies
Consolidated Balance Sheets
LIABILITIES AND SHAREHOLDERS’ EQUITY
December 31,
2018
2017
Long-term debt due within one year
$
300 $
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
Other paid-in capital
Retained deficit unappropriated
Retained earnings appropriated
Total shareholders’ equity
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
Total liabilities and shareholders’ equity
$
31,213 $
See the Combined Notes to Consolidated Financial Statements
225
840
568
327
74
112
249
21
103
2,294
6,761
205
3,469
111
219
6,328
235
562
10,924
20,184
1,588
6,822
(1,639)
2,771
9,542
29,726
Table of Contents
(In millions)
Commonwealth Edison Company and Subsidiary Companies
Consolidated Statements of Changes in Shareholders’ Equity
Common
Stock
Other
Paid-In
Capital
Retained Deficit
Unappropriated
Retained
Earnings
Appropriated
Total
Shareholders’
Equity
Balance, December 31, 2015
$
1,588 $
5,677 $
(1,639) $
2,617 $
Net income
Common stock dividends
Contribution from parent
Parent tax matter indemnification
Appropriation of retained earnings for future dividends
—
—
—
—
—
—
—
315
158
—
378
—
—
—
(378)
—
(369)
—
—
378
Balance, December 31, 2016
$
1,588 $
6,150 $
(1,639) $
2,626 $
Net income
Common stock dividends
Contributions from parent
Parent tax matter indemnification
Appropriation of retained earnings for future dividends
Balance, December 31, 2017
Net income
Common stock dividends
Contributions from parent
Appropriation of retained earnings for future dividends
Balance, December 31, 2018
$
$
—
—
—
—
—
—
—
651
21
—
567
—
—
—
(567)
—
(422)
—
—
567
1,588 $
6,822 $
(1,639) $
2,771 $
—
—
—
—
—
—
500
—
664
—
—
(664)
—
(459)
—
664
1,588 $
7,322 $
(1,639) $
2,976 $
10,247
8,243
378
(369)
315
158
—
8,725
567
(422)
651
21
—
9,542
664
(459)
500
—
See the Combined Notes to Consolidated Financial Statements
226
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
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,
2018
2017
2016
$
2,469 $
2,369 $
568
(7)
8
494
—
7
2,524
462
—
8
3,038
2,870
2,994
734
230
126
742
156
301
163
648
186
135
657
149
286
154
2,452
2,215
1
587
(115)
(14)
8
(121)
466
6
—
655
(115)
(11)
9
(117)
538
104
$
$
460
460
$
$
434
434
$
$
598
162
287
665
146
270
164
2,292
—
702
(111)
(12)
8
(115)
587
149
438
438
See the Combined Notes to Consolidated Financial Statements
227
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
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
Contributions from parent
Dividends paid on common stock
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
For the Years Ended December 31,
2018
2017
2016
$
460 $
434 $
438
301
286
(5)
51
(74)
7
(14)
(3)
15
(28)
29
739
(849)
—
9
(840)
700
(500)
89
(306)
(22)
(39)
(140)
275
19
54
(44)
(6)
1
6
34
(24)
(5)
755
(732)
131
4
(597)
325
—
16
(288)
(3)
50
208
67
$
135
$
275
$
270
78
65
(71)
6
6
67
8
(30)
(8)
829
(686)
(131)
20
(797)
300
(300)
18
(277)
(4)
(263)
(231)
298
67
See the Combined Notes to Consolidated Financial Statements
228
Table of Contents
(In millions)
Current assets
Cash and cash equivalents
Restricted cash and cash equivalents
Accounts receivable, net
Customer
Other
Inventories, net
Fossil fuel
Materials and supplies
Prepaid utility taxes
Regulatory assets
Other
Total current assets
Property, plant and equipment, net
Deferred debits and other assets
Regulatory assets
Investments
Receivables from affiliates
Prepaid pension asset
Other
Total deferred debits and other assets
Total assets
PECO Energy Company and Subsidiary Companies
Consolidated Balance Sheets
ASSETS
December 31,
2018
2017
$
130 $
5
321
151
38
37
—
81
19
782
8,610
460
25
389
349
27
1,250
See the Combined Notes to Consolidated Financial Statements
229
$
10,642
$
271
4
327
105
31
30
8
29
17
822
8,053
381
25
537
340
12
1,295
10,170
Table of Contents
(In millions)
Current liabilities
PECO Energy Company and Subsidiary Companies
Consolidated Balance Sheets
LIABILITIES AND SHAREHOLDER'S EQUITY
December 31,
2018
2017
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
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
Retained earnings
Accumulated other comprehensive income, net
Total shareholder's equity
Total liabilities and shareholder's equity
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
$
See the Combined Notes to Consolidated Financial Statements
230
500
370
114
53
66
141
23
1,267
2,403
184
1,789
27
288
549
86
2,739
6,593
2,489
1,087
1
3,577
10,170
Table of Contents
(In millions)
Balance, December 31, 2015
Net income
Common stock dividends
Contributions from parent
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
PECO Energy Company and Subsidiary Companies
Consolidated Statements of Changes in Shareholder's Equity
Common
Stock
Retained
Earnings
Accumulated
Other
Comprehensive
Income
Total
Shareholder's
Equity
$
$
$
$
2,455 $
—
—
18
780 $
438
(277)
—
2,473
$
941
$
—
—
16
434
(288)
—
2,489
$
1,087
$
—
—
89
—
460
(306)
—
1
2,578
$
1,242
$
1
$
—
—
—
1
$
—
—
—
1
$
—
—
—
(1)
—
$
3,236
438
(277)
18
3,415
434
(288)
16
3,577
460
(306)
89
—
3,820
See the Combined Notes to Consolidated Financial Statements
231
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
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
Preference stock dividends
Net income attributable to common shareholder
Comprehensive income
Comprehensive income attributable to preference stock dividends
Comprehensive income attributable to common shareholder
For the Years Ended December 31,
2018
2017
2016
$
2,428 $
2,384 $
738
(26)
29
652
124
16
2,531
628
53
21
3,169
3,176
3,233
671
254
257
615
162
483
254
566
183
384
563
153
473
240
2,696
2,562
1
474
(106)
—
19
(87)
387
74
313
—
—
614
(95)
(10)
16
(89)
525
218
307
—
$
$
$
313
$
307
$
313
$
—
313 $
307
$
—
307 $
528
162
604
605
132
423
229
2,683
—
550
(87)
(16)
21
(82)
468
174
294
8
286
294
8
286
See the Combined Notes to Consolidated Financial Statements
232
Table of Contents
(In millions)
Cash flows from operating activities
Net income
Baltimore Gas and Electric Company and Subsidiary Companies
Consolidated Statements of Cash Flows
For the Years Ended December 31,
2018
2017
2016
$
313 $
307 $
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 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
Redemption of preference stock
Dividends paid on preference stock
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
483
—
76
58
8
12
2
(1)
4
(20)
(54)
(92)
789
(959)
9
(950)
(42)
300
—
—
—
—
(209)
109
(2)
156
(5)
18
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
Cash, cash equivalents and restricted cash at end of period
$
13
$
18
$
See the Combined Notes to Consolidated Financial Statements
233
294
423
52
118
88
(98)
3
1
138
—
18
(49)
(43)
945
(934)
24
(910)
(165)
850
(379)
—
(190)
(8)
(179)
61
(11)
(21)
14
36
50
Table of Contents
(In millions)
Current assets
Cash and cash equivalents
Restricted cash and cash equivalents
Accounts receivable, net
Customer
Other
Receivables from affiliates
Inventories, net
Gas held in storage
Materials and supplies
Prepaid utility taxes
Regulatory assets
Other
Total current assets
Property, plant and equipment, net
Deferred debits and other assets
Regulatory assets
Investments
Prepaid pension asset
Other
Total deferred debits and other assets
Total assets
Baltimore Gas and Electric Company and Subsidiary Companies
Consolidated Balance Sheets
ASSETS
December 31,
2018
2017
$
7 $
6
353
90
1
36
39
74
177
3
786
8,243
398
5
279
5
687
17
1
375
94
1
37
40
69
174
3
811
7,602
397
5
285
4
691
See the Combined Notes to Consolidated Financial Statements
234
$
9,716
$
9,104
Baltimore Gas and Electric Company and Subsidiary Companies
Consolidated Balance Sheets
LIABILITIES AND SHAREHOLDER'S EQUITY
December 31,
2018
2017
$
35 $
Table of Contents
(In millions)
Current liabilities
Short-term borrowings
Accounts payable
Accrued expenses
Payables to affiliates
Customer deposits
Regulatory liabilities
Other
Total current liabilities
Long-term debt
Deferred credits and other liabilities
Deferred income taxes and unamortized investment tax credits
Asset retirement obligations
Non-pension postretirement benefits obligations
Regulatory liabilities
Other
Total deferred credits and other liabilities
Total liabilities
Commitments and contingencies
Shareholder's equity
Common stock
Retained earnings
Total shareholder's equity
Total liabilities and shareholder's equity
See the Combined Notes to Consolidated Financial Statements
235
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
$
77
265
164
52
116
62
24
760
2,577
1,244
23
202
1,101
56
2,626
5,963
1,605
1,536
3,141
9,104
Table of Contents
(In millions)
Balance, December 31, 2015
Net income
Preference stock dividends
Common stock dividends
Distributions to parent
Contributions from parent
Redemption of preference stock
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
Baltimore Gas and Electric Company and Subsidiary Companies
Consolidated Statements of Changes in Shareholder's Equity
Common
Stock
Retained
Earnings
Total
Shareholder's
Equity
Preference
stock
not subject to
mandatory
redemption
Total
Equity
$
1,367 $
1,320 $
2,687 $
190 $
2,877
—
—
—
(7)
61
—
294
(8)
(179)
—
—
—
294
(8)
(179)
(7)
61
—
1,421
$
1,427
$
2,848
$
—
—
184
307
(198)
—
307
(198)
184
—
—
—
—
(190)
— $
—
—
—
294
(8)
(179)
(7)
61
(190)
2,848
307
(198)
184
1,605
$
1,536
$
3,141
$
— $
3,141
—
—
109
313
(209)
—
313
(209)
109
—
—
—
313
(209)
109
1,714
$
1,640
$
3,354
$
— $
3,354
$
$
$
See the Combined Notes to Consolidated Financial Statements
236
Table of Contents
Pepco Holdings LLC and Subsidiary Companies
Consolidated Statements of Operations and Comprehensive Income (Loss)
(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
Total operating expenses
Gain (loss) 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
Equity in earnings of unconsolidated affiliates
Net income (loss)
Successor
Predecessor
For the Years Ended
December 31,
March 24 to December
31,
January 1 to March 23,
2018
2017
2016
2016
$
4,609 $
4,428 $
3,463 $
1,122
181
—
15
4,805
161
40
50
4,679
92
43
45
57
(26)
—
3,643
1,153
1,387
1,182
89
355
978
152
740
455
4,156
1
650
(261)
43
(218)
432
35
1
398
71
463
918
150
675
452
3,911
1
769
(245)
54
(191)
578
217
1
362
925
36
486
1,144
89
515
354
3,549
(1)
93
(195)
44
(151)
(58)
3
—
(61)
471
26
—
294
—
152
105
1,048
—
105
(65)
(4)
(69)
36
17
—
19
19
19
1
1
20
Net income (loss) attributable to membership interest/common
shareholders
Comprehensive income (loss), net of income taxes
Net income (loss)
Other comprehensive income (loss), net of income taxes
Pension and non-pension postretirement benefit plans:
Actuarial loss reclassified to periodic cost
Other comprehensive income
Comprehensive income (loss)
$
$
$
398 $
362 $
(61) $
398 $
362 $
(61) $
—
—
—
—
—
—
398 $
362 $
(61) $
See the Combined Notes to Consolidated Financial Statements
237
Table of Contents
Pepco Holdings LLC and Subsidiary Companies
Consolidated Statements of Cash Flows
Successor
Predecessor
For the Years Ended
December 31,
March 24 to December
31,
January 1 to March 23,
2018
2017
2016
2016
$
398 $
362 $
(61)
$
(In millions)
Cash flows from operating activities
Net income (loss)
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
Net fair value changes related to derivatives
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
Purchases of investments
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
Common stock issued for the Direct Stock Purchase and Dividend Reinvestment Plan and
employee-related compensation
Distributions to member
Contributions from member
Change in Exelon intercompany money pool
Other financing activities
Net cash flows provided by (used in) 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
$
740
—
32
—
143
(2)
8
(14)
45
34
(74)
(178)
1,132
675
52
252
—
58
(26)
(2)
(37)
(106)
79
(99)
(258)
950
515
—
295
—
515
(21)
42
3
19
(22)
(86)
(311)
888
(1,375)
(1,396)
(1,008)
—
4
—
(1)
—
15
(1,371)
(1,397)
(993)
(296)
125
—
750
(299)
—
(326)
385
—
(9)
330
91
95
186 $
328
—
(500)
202
(169)
—
(311)
758
—
(2)
306
(141)
236
95
$
(515)
—
(300)
179
(338)
—
(273)
1,251
(6)
(5)
(7)
(112)
348
236
$
See the Combined Notes to Consolidated Financial Statements
238
19
152
—
19
18
46
(28)
—
(4)
42
12
(4)
(8)
264
(273)
(68)
(5)
(346)
(121)
500
—
—
(11)
2
—
—
—
2
372
290
58
348
Table of Contents
(In millions)
Current assets
Cash and cash equivalents
Restricted cash and cash equivalents
Accounts receivable, net
Customer
Other
Inventories, net
Gas held in storage
Materials and supplies
Regulatory assets
Other
Total current assets
Property, plant and equipment, net
Deferred debits and other assets
Regulatory assets
Investments
Goodwill
Long-term note receivable
Prepaid pension asset
Deferred income taxes
Other
Pepco Holdings LLC and Subsidiary Companies
Consolidated Balance Sheets
ASSETS
December 31,
2018
2017
$
124 $
43
453
177
9
163
489
75
1,533
13,446
2,312
130
4,005
—
486
12
60
Total deferred debits and other assets
Total assets (a)
$
7,005
21,984 $
See the Combined Notes to Consolidated Financial Statements
239
30
42
486
206
7
151
554
75
1,551
12,498
2,493
132
4,005
4
490
4
70
7,198
21,247
Table of Contents
(In millions)
Current liabilities
Short-term borrowings
Long-term debt due within one year
Accounts payable
Accrued expenses
Payables to affiliates
Regulatory liabilities
Unamortized energy contract liabilities
Customer deposits
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 gains (losses)
Total member's equity
Total liabilities and member's equity
Pepco Holdings LLC and Subsidiary Companies
Consolidated Balance Sheets
LIABILITIES AND EQUITY
December 31,
2018
2017
$
179 $
125
496
256
94
84
119
116
123
1,592
6,134
2,146
52
103
1,864
442
369
4,976
12,702
9,220
62
9,282
$
21,984 $
350
396
348
261
90
56
188
119
123
1,931
5,478
2,070
16
105
1,872
561
389
5,013
12,422
8,835
(10)
8,825
21,247
_____________
(a)
PHI’s consolidated total assets include $33 million and $41 million at December 31, 2018 and 2017 , respectively, of PHI's consolidated VIE that can only be used to
settle the liabilities of the VIE. PHI’s consolidated total liabilities include $69 million and $102 million at December 31, 2018 and 2017 , respectively, of PHI's consolidated
VIE for which the VIE creditors do not have recourse to PHI. See Note 2 - Variable Interest Entities for additional information.
See the Combined Notes to Consolidated Financial Statements
240
Table of Contents
Pepco Holdings LLC and Subsidiary Companies
Consolidated Statements of Changes in Equity
(In millions, except share data)
Common Stock (a)
Retained Earnings
Accumulated Other
Comprehensive Loss, net
Total Shareholders'
Equity
Predecessor
Balance, December 31, 2015
Net income
Original issue shares, net
Net activity related to stock-based awards
Other comprehensive income, net of income taxes
Balance, March 23, 2016
Successor
Balance, March 24, 2016 (b)
Net loss
Distributions to member (c)
Contributions from member
Measurement period adjustment of Exelon’s deferred tax
liabilities to reflect unitary state income tax consequences of the
merger
Distribution of net retirement benefit obligation to member
Assumption of member liabilities (d)
Balance, December 31, 2016
Net Income
Distributions to member
Contributions from member
Balance, December 31, 2017
Net Income
Distributions to member
Contributions from member
Balance, December 31, 2018
$
$
$
$
$
$
3,832 $
617
$
(36)
$
—
3
3
—
19
—
—
—
—
—
—
1
4,413
19
3
3
1
3,838
$
636
$
(35)
$
4,439
Membership Interest
Undistributed
Gains/(Losses)
Accumulated Other
Comprehensive Loss, net
Total
Member's Equity
7,200 $
—
(400)
1,251
35
53
(62)
— $
(61)
—
—
—
—
—
8,077
$
(61)
$
—
—
758
8,835
$
—
—
385
9,220
$
362
(311)
—
(10)
$
398
(326)
—
62
$
— $
—
—
—
—
—
—
—
$
—
—
—
—
$
—
—
—
—
$
7,200
(61)
(400)
1,251
35
53
(62)
8,016
362
(311)
758
8,825
398
(326)
385
9,282
__________
(a)
At March 23, 2016 and December 31, 2015 , PHI's (predecessor) shareholders' equity included $3,835 million and $3,829 million of other paid-in capital, and $3 million
and $3 million of common stock, respectively.
The March 24, 2016 , beginning balance differs from the PHI Merger total purchase price by $59 million related to an acquisition accounting adjustment recorded at
Exelon Corporate to reflect unitary state income tax consequences of the merger.
Distribution to member includes $235 million of net assets associated with PHI's unregulated business interests and $165 million of cash, each of which were distributed
by PHI to Exelon.
The liabilities assumed include $29 million for PHI stock-based compensation awards and $33 million for a merger related obligation, each assumed by PHI from Exelon.
See Note 5 — Mergers, Acquisitions and Dispositions .
(b)
(c)
(d)
See the Combined Notes to Consolidated Financial Statements
241
Table of Contents
Potomac Electric Power Company
Statements of Operations and Comprehensive Income
(In millions)
Operating revenues
Electric operating revenues
Revenues from alternative revenue programs
Operating revenues from affiliates
Total operating revenues
Operating expenses
Purchased power
Purchased power from affiliates
Operating and maintenance
Operating and maintenance from affiliates
Depreciation and amortization
Taxes other than income
Total operating expenses
Gain on sales of assets
Operating income
Other income and (deductions)
Interest expense, net
Other, net
Total other income and (deductions)
Income before income taxes
Income taxes
Net income
Comprehensive income
For the Years Ended December 31,
2018
2017
2016
$
2,233 $
2,126 $
2,167
—
6
26
6
14
5
2,239
2,158
2,186
448
206
275
226
385
379
1,919
—
320
(128)
31
(97)
223
13
210 $
210 $
359
255
396
58
321
371
1,760
1
399
(121)
32
(89)
310
105
205 $
205 $
411
295
607
35
295
377
2,020
8
174
(127)
36
(91)
83
41
42
42
$
$
See the Combined Notes to Consolidated Financial Statements
242
Table of Contents
(In millions)
Cash flows from operating activities
Net income
Potomac Electric Power Company
Statements of Cash Flows
For the Years Ended December 31,
2018
2017
2016
$
210 $
205 $
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
Purchases of investments
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
385
—
(18)
60
(5)
(17)
(6)
59
(13)
(17)
(164)
474
(656)
—
2
(654)
14
200
(14)
(169)
166
(4)
193
13
40
321
14
113
(6)
(20)
—
(24)
(63)
81
(72)
(142)
407
(628)
—
—
(628)
3
202
(13)
(133)
161
(1)
219
(2)
42
Cash, cash equivalents and restricted cash at end of period
$
53 $
40 $
See the Combined Notes to Consolidated Financial Statements
243
42
295
—
153
175
(41)
44
1
32
110
(32)
(128)
651
(586)
(30)
—
(616)
(41)
4
(11)
(136)
187
(3)
—
35
7
42
Table of Contents
(In millions)
Current assets
Cash and cash equivalents
Restricted cash and cash equivalents
Accounts receivable, net
Customer
Other
Receivables from affiliates
Inventories, net
Regulatory assets
Other
Total current assets
Property, plant and equipment, net
Deferred debits and other assets
Regulatory assets
Investments
Prepaid pension asset
Other
Total deferred debits and other assets
Total assets
Potomac Electric Power Company
Balance Sheets
ASSETS
December 31,
2018
2017
$
$
16 $
37
225
81
1
93
270
37
760
6,460
643
105
316
15
1,079
8,299 $
5
35
250
87
—
87
213
33
710
6,001
678
102
322
19
1,121
7,832
See the Combined Notes to Consolidated Financial Statements
244
Table of Contents
(In millions)
Potomac Electric Power Company
Balance Sheets
LIABILITIES AND SHAREHOLDER'S EQUITY
December 31,
2018
2017
Current liabilities
Short-term borrowings
Long-term debt due within one year
Accounts payable
Accrued expenses
Payables to affiliates
Regulatory liabilities
Customer deposits
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
Non-pension postretirement benefit obligations
Regulatory liabilities
Other
Total deferred credits and other liabilities
Total liabilities
Commitments and contingencies
Shareholder's equity
Common stock
Retained earnings
Total shareholder's equity
Total liabilities and shareholder's equity
$
$
40
15
214
126
62
7
54
38
30
42
628 —
2,704
1,064
29
822
312
2,227
5,559
1,636
1,104
2,740
26
19
139
137
74
3
54
42
28
28
550
2,521
1,063
36
829
300
2,228
5,299
1,470
1,063
2,533
7,832
See the Combined Notes to Consolidated Financial Statements
245
$
8,299
$
Table of Contents
(In millions)
Balance, December 31, 2015
Net income
Common stock dividends
Contributions from parent
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
Potomac Electric Power Company
Statements of Changes in Shareholder's Equity
Common Stock
Retained Earnings
Total Shareholder's Equity
2,240
1,118 $
$
$
$
$
1,122 $
—
—
187
1,309 $
—
—
161
42
(169)
—
991 $
205
(133)
—
1,470 $
1,063 $
—
—
166
210
(169)
—
1,636 $
1,104 $
42
(169)
187
2,300
205
(133)
161
2,533
210
(169)
166
2,740
See the Combined Notes to Consolidated Financial Statements
246
Table of Contents
Delmarva Power & Light Company
Statements of Operations and Comprehensive Income (Loss)
(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
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 (loss)
Comprehensive income (loss)
For the Years Ended December 31,
2018
2017
2016
$
1,139 $
1,125 $
181
4
8
161
6
8
1,128
148
(6)
7
1,332
1,300
1,277
352
89
120
182
162
182
56
282
71
179
283
32
167
57
369
60
154
422
19
157
55
1,143
1,071
1,236
1
190
(58)
10
(48)
142
22
120
120
$
$
—
229
(51)
14
(37)
192
71
121
121
$
$
9
50
(50)
13
(37)
13
22
(9)
(9)
$
$
See the Combined Notes to Consolidated Financial Statements
247
Table of Contents
(In millions)
Cash flows from operating activities
Net income (loss)
Delmarva Power & Light Company
Statements of Cash Flows
For the Years Ended December 31,
2018
2017
2016
$
120 $
121 $
(9)
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
Collateral 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
Change in short-term borrowings
Issuance of long-term debt
Retirement of long-term debt
Dividends paid on common stock
Contributions from parent
Other financing activities
Net cash flows provided by financing activities
Increase (decrease) in cash, cash equivalents and restricted cash
Cash, cash equivalents and restricted cash at beginning of period
182
—
24
24
8
(9)
(3)
11
—
2
—
(7)
352
(364)
2
(362)
(216)
200
(4)
(96)
150
(2)
32
22
2
167
6
89
9
(22)
11
(5)
(8)
—
26
(2)
(71)
321
(428)
(1)
(429)
216
—
(40)
(112)
—
—
64
(44)
46
Cash, cash equivalents and restricted cash at end of period
$
24
$
2
$
See the Combined Notes to Consolidated Financial Statements
248
157
—
109
114
(5)
13
—
(4)
1
28
(22)
(72)
310
(349)
13
(336)
(105)
175
(100)
(54)
152
(1)
67
41
5
46
Table of Contents
(In millions)
Current assets
Cash and cash equivalents
Restricted cash and cash equivalents
Accounts receivable, net
Customer
Other
Inventories, net
Gas held in storage
Materials and supplies
Regulatory assets
Other
Total current assets
Property, plant and equipment, net
Deferred debits and other assets
Regulatory assets
Goodwill
Prepaid pension asset
Other
Total deferred debits and other assets
Total assets
Delmarva Power & Light Company
Balance Sheets
ASSETS
December 31,
2018
2017
$
23 $
1
134
46
9
37
59
27
336
3,821
231
8
186
6
431
2
—
146
38
7
36
69
27
325
3,579
245
8
193
7
453
See the Combined Notes to Consolidated Financial Statements
249
$
4,588
$
4,357
Table of Contents
(In millions)
Delmarva Power & Light Company
Balance Sheets
LIABILITIES AND SHAREHOLDER'S EQUITY
December 31,
2018
2017
Current liabilities
Short-term borrowings
Long-term debt due within one year
Accounts payable
Accrued expenses
Payables to affiliates
Regulatory liabilities
Customer deposits
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
Retained earnings
Total shareholder's equity
Total liabilities and shareholder's equity
$
$
— $
91
111
39
33
59
35
7
375
1,403
628
17
606
50
1,301
3,079
914
595
1,509
4,588
$
216
83
82
35
46
42
35
8
547
1,217
603
14
593
48
1,258
3,022
764
571
1,335
4,357
See the Combined Notes to Consolidated Financial Statements
250
Table of Contents
(In millions)
Balance, December 31, 2015
Net loss
Common stock dividends
Contributions from parent
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
Delmarva Power & Light Company
Statements of Changes in Shareholder's Equity
Common Stock
Retained Earnings
$
$
$
$
612 $
—
—
152
764 $
—
—
764 $
—
—
150
914 $
See the Combined Notes to Consolidated Financial Statements
251
Total Shareholder's Equity
1,237
625 $
(9)
(54)
—
562
$
121
(112)
571
$
120
(96)
—
595
$
(9)
(54)
152
1,326
121
(112)
1,335
120
(96)
150
1,509
Table of Contents
Atlantic City Electric Company and Subsidiary Company
Consolidated Statements of Operations and Comprehensive Income (Loss)
(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
Total operating expenses
Gain on sale of assets
Operating income
Other income and (deductions)
Interest expense, net
Other, net
Total other income and (deductions)
Income (loss) before income taxes
Income taxes
Net income (loss)
Comprehensive income (loss)
For the Years Ended December 31,
2018
2017
2016
$
1,237 $
1,176 $
1,245
(4)
3
8
2
9
3
1,236
1,186
1,257
587
29
188
142
136
5
541
29
279
28
146
6
614
37
410
18
165
7
1,087
1,029
1,251
—
149
(64)
2
(62)
87
12
$
$
75
75
$
$
—
157
(61)
7
(54)
103
26
77
77
$
$
1
7
(62)
9
(53)
(46)
(4)
(42)
(42)
See the Combined Notes to Consolidated Financial Statements
252
Table of Contents
(In millions)
Cash flows from operating activities
Net income (loss)
Atlantic City Electric Company and Subsidiary Company
Consolidated Statements of Cash Flows
For the Years Ended December 31,
2018
2017
2016
$
75 $
77 $
(42)
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
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
136
—
25
24
(8)
1
(4)
(7)
(2)
(6)
(6)
228
(335)
1
(334)
(94)
125
350
(281)
(59)
67
(3)
105
(1)
31
146
7
32
17
14
—
(7)
(2)
(11)
(20)
(47)
206
(312)
(1)
(313)
108
—
—
(35)
(68)
—
—
5
(102)
133
Cash, cash equivalents and restricted cash at end of period
$
30
$
31
$
See the Combined Notes to Consolidated Financial Statements
253
165
—
22
155
(8)
13
(1)
9
174
(17)
(85)
385
(311)
4
(307)
(5)
—
—
(48)
(63)
139
(1)
22
100
33
133
Table of Contents
(In millions)
Current assets
Cash and cash equivalents
Restricted cash and cash equivalents
Accounts receivable, net
Customer
Other
Receivables from affiliates
Inventories, net
Regulatory assets
Other
Total current assets
Property, plant and equipment, net
Deferred debits and other assets
Regulatory assets
Long-term note receivable
Prepaid pension asset
Other
Total deferred debits and other assets
Total assets (a)
Atlantic City Electric Company and Subsidiary Company
Consolidated Balance Sheets
ASSETS
December 31,
2018
2017
$
7 $
4
95
55
1
33
40
5
240
2,966
386
—
67
40
493
See the Combined Notes to Consolidated Financial Statements
254
$
3,699
$
2
6
92
56
—
29
71
2
258
2,706
359
4
73
45
481
3,445
Table of Contents
(In millions)
Atlantic City Electric Company and Subsidiary Company
Consolidated Balance Sheets
LIABILITIES AND SHAREHOLDER'S EQUITY
December 31,
2018
2017
Current liabilities
Short-term borrowings
Long-term debt due within one year
Accounts payable
Accrued expenses
Payables to affiliates
Regulatory liabilities
Customer deposits
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
Retained earnings
Total shareholder's equity
Total liabilities and shareholder's equity
$
$
139 $
18
154
35
28
18
26
4
422
1,170
535
17
402
27
981
2,573
979
147
1,126
3,699
$
108
281
118
33
29
11
31
8
619
840
493
14
411
25
943
2,402
912
131
1,043
3,445
_____________
(a)
ACE’s consolidated assets include $23 million and $29 million at December 31, 2018 and 2017 , respectively, of ACE’s consolidated VIE that can only be used to settle
the liabilities of the VIE. ACE’s consolidated liabilities include $59 million and $90 million at December 31, 2018 and 2017 , respectively, of ACE’s consolidated VIE for
which the VIE creditors do not have recourse to ACE. See Note 2 - Variable Interest Entities for additional information.
See the Combined Notes to Consolidated Financial Statements
255
Table of Contents
(In millions)
Balance, December 31, 2015
Net loss
Common stock dividends
Contributions from parent
Balance, December 31, 2016
Net income
Common stock dividends
Balance, December 31, 2017
Net income
Common stock dividends
Contribution from parent
Balance, December 31, 2018
Atlantic City Electric Company and Subsidiary Company
Consolidated Statements of Changes in Shareholder's Equity
Common Stock
Retained Earnings
$
$
$
$
773 $
—
—
139
912
$
—
—
912
$
—
—
67
979
$
See the Combined Notes to Consolidated Financial Statements
256
Total Shareholder's Equity
1,000
227 $
(42)
(63)
—
122 $
77
(68)
131 $
75
(59)
—
147 $
(42)
(63)
139
1,034
77
(68)
1,043
75
(59)
67
1,126
Table of Contents
Index to Combined Notes to Consolidated Financial Statements
Combined Notes to Consolidated Financial Statements
(Dollars in millions, except per share data unless otherwise noted)
The notes to the consolidated financial statements that follow are a combined presentation. The following list indicates the Registrants to which the footnotes
apply:
Applicable Notes
Registrant
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
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Table of Contents
Combined Notes to Consolidated Financial Statements - (Continued)
(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. On March 23, 2016 , Exelon completed the merger with PHI, which became a
wholly owned subsidiary of Exelon. PHI is a utility services holding company engaged through its principal wholly owned subsidiaries, Pepco, DPL and ACE, in
the energy distribution and transmission businesses. See Note 5 — Mergers, Acquisitions and Dispositions for additional information regarding the merger
transaction.
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.
Six reportable segments: Mid-Atlantic, Midwest, New England, 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.
As a result of the merger with PHI, Exelon’s financial reporting reflects PHI’s consolidated financial results subsequent to the March 23, 2016 , acquisition date.
Exelon has accounted for the merger transaction applying the acquisition method of accounting, which it has pushed-down to the consolidated financial
statements of PHI such that the assets and liabilities of PHI are recorded at their respective fair values, and goodwill has been established as of the acquisition
date. Accordingly, the consolidated financial statements of PHI for periods before and after the March 23, 2016 , acquisition date reflect different bases of
accounting, and the results of operations and the financial positions of the predecessor and successor periods are not comparable. The acquisition method of
accounting has not been pushed down to PHI’s wholly owned subsidiary utility registrants, Pepco, DPL and ACE.
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Combined Notes to Consolidated Financial Statements - (Continued)
(Dollars in millions, except per share data unless otherwise noted)
For financial statement purposes, beginning on March 24, 2016 , disclosures related to Exelon also apply to PHI, Pepco, DPL and ACE, unless otherwise noted.
Through its business services subsidiary, BSC, Exelon provides its subsidiaries with a variety of support services at cost, including legal, human resources,
financial, information technology and supply management services. PHI also has a business services subsidiary, PHISCO, which provides a variety of support
services at cost, including legal, accounting, engineering, customer operations, distribution and transmission planning, asset management, system operations,
and power procurement, to PHI operating companies. The costs of BSC and PHISCO are directly charged or allocated to the applicable subsidiaries. The results
of Exelon’s corporate operations are presented as “Other” within the consolidated financial statements and include intercompany eliminations unless otherwise
disclosed.
Exelon owns 100% of Generation, PECO, BGE and PHI and more than 99% of ComEd. PHI owns 100% of Pepco, DPL and ACE. Generation owns 100% of its
significant consolidated subsidiaries, either directly or 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 2 — 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 other postretirement benefits, 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 (All Registrants)
Certain prior year amounts in the Registrants' Consolidated Statements of Operations and Comprehensive Incom e, Consolidated Statements of Cash Flows,
Consolidated Balance Sheets and Consolidated Statements of Changes in Shareholders' Equity have been recasted to reflect new accounting standards issued
by the FASB and adopted as of January 1, 2018. See New Accounting Standards below for additional information.
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Combined Notes to Consolidated Financial Statements - (Continued)
(Dollars in millions, except per share data unless otherwise noted)
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 4 — 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 alternative revenue programs (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 4 — Regulatory Matters and Note 23 — Supplemental Financial Information 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 4
— Regulatory Matters and Note 12 — Derivative Financial Instruments for additional information.
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Combined Notes to Consolidated Financial Statements - (Continued)
(Dollars in millions, except per share data unless otherwise noted)
Taxes Directly Imposed on Revenue-Producing Transactions. The Registrants collect certain taxes from customers such as sales and gross receipts taxes,
along with other taxes, surcharges and fees, that are levied by state or local governments on the sale or distribution of 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. Se e 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.
Income Taxes (All Registrants)
Deferred Federal and state income taxes are recorded on significant temporary differences between the book and tax basis of assets and liabilities and for tax
benefits carried forward. Investment tax credits have been deferred in the Registrants’ Consolidated Balance Sheets and are recognized in book income over
the life of the related property. The Registrants account for uncertain income tax positions using a benefit recognition model with a two-step approach; a more-
likely-than-not recognition criterion; and a measurement approach that measures the position as the largest amount of tax benefit that is greater than 50% likely
of being realized upon ultimate settlement. If it is not more-likely-than-not that the benefit of the tax position will be sustained on its technical merits, no benefit is
recorded. Uncertain tax positions that relate only to timing of when an item is included on a tax return are considered to have met the recognition threshold. The
Registrants recognize accrued interest related to unrecognized tax benefits in Interest expense 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.
Pursuant to the IRC and relevant state taxing authorities, Exelon and its subsidiaries file consolidated or combined income tax returns for Federal and certain
state jurisdictions where allowed or required. See Note 14 — Income Taxes for additional information.
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, 2018 and 2017 , 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.
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Combined Notes to Consolidated Financial Statements - (Continued)
(Dollars in millions, except per share data unless otherwise noted)
Restricted cash and cash equivalents not available to satisfy current liabilities are classified as noncurrent assets. As of December 31, 2018 and 2017 , 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 4 — Regulatory Matters for additional information regarding the regulatory
recovery of uncollectible accounts receivable at ComEd and ACE.
Variable Interest Entities (All Registrants)
Exelon accounts for its investments in and arrangements with VIEs based on the following specific requirements:
•
•
•
requires an entity to qualitatively assess whether it should consolidate a VIE based on whether the entity has a controlling financial interest,
requires an ongoing reconsideration of this assessment instead of only upon certain triggering events, and
requires the entity that consolidates a VIE (the primary beneficiary) to disclose (1) the assets of the consolidated VIE, if they can be used to only settle
specific obligations of the consolidated VIE, and (2) the liabilities of a consolidated VIE for which creditors do not have recourse to the general credit of
the primary beneficiary.
See Note 2 — 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 and 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 4 — Regulatory Matters for additional information regarding ComEd’s and
PECO’s regulatory assets and liabilities and Note 11 —
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Combined Notes to Consolidated Financial Statements - (Continued)
(Dollars in millions, except per share data unless otherwise noted)
Fair Value of Financial Assets and Liabilities and Note 15 — 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 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. 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 6 — Property, Plant and Equipment , Note 9 — 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 22 — Commitments and Contingencies for additional information regarding the
cost of SNF storage and disposal.
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Combined Notes to Consolidated Financial Statements - (Continued)
(Dollars in millions, except per share data unless otherwise noted)
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 8 — Early Plant Retirements for additional information on the impacts of expected and potential early plant retirements.
See Note 6 — Property, Plant and Equipment for additional information regarding depreciation.
Amortization of regulatory assets and liabilities are recorded over the recovery or refund period specified in the related legislation or regulatory order or
agreement. When the recovery or refund period is less than one year, amortization is recorded to the line item in which the deferred cost or income would have
originally been recorded in the Utility Registrants’ Consolidated Statements of Operations and Comprehensive Income. Amortization of ComEd’s electric
distribution and energy efficiency formula rate regulatory assets and the Utility Registrants' transmission formula rate regulatory assets is recorded to Operating
revenues.
Amortization of income tax related regulatory assets and liabilities is generally recorded to Income tax expense. With the exception of the regulatory assets and
liabilities discussed above, when the recovery period is more than one year, the amortization is generally recorded to Depreciation and amortization in the
Registrants’ Consolidated Statements of Operations and Comprehensive Income.
See Note 4 — 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 or, in the case of the Utility Registrants' accretion, through an increase to regulatory assets. See Note 15
— 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 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
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Combined Notes to Consolidated Financial Statements - (Continued)
(Dollars in millions, except per share data unless otherwise noted)
amortization method over the term of the guarantee. See Note 22 — Commitments and Contingencies for additional information.
Asset Impairments
Long-Lived Assets (All Registrants). The Registrants evaluate the carrying value of their long-lived assets or asset groups, excluding goodwill, when
circumstances indicate 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
7 — Impairment of Long-Lived Assets and Intangibles 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 10 — Intangible
Assets for additional information.
Equity Method Investments (Exelon and Generation). Exelon and Generation regularly monitor and evaluate equity method investments to determine
whether they are impaired. An impairment is recorded when the investment has experienced a decline in value that is other-than-temporary in nature.
Additionally, if the entity in which Generation holds an investment recognizes an impairment loss, Exelon and Generation would record their proportionate share
of that impairment loss and evaluate the investment for an other-than-temporary decline in value.
Debt Security Investments (Exelon and Generation). Declines in the fair value of debt security investments below the cost basis are reviewed to determine if
such 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 normal purchases and normal sales
exception. 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 4 — Regulatory Matters and Note 12 — 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. Normal purchases and normal sales 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 normal purchases and normal sales are recognized when the underlying physical
transaction is
265
Table of Contents
Combined Notes to Consolidated Financial Statements - (Continued)
(Dollars in millions, except per share data unless otherwise noted)
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 12 — Derivative Financial Instruments for additional information.
Retirement Benefits (All Registrants)
Exelon sponsors defined benefit pension plans and other postretirement benefit plans for essentially all employees.
The measurement of the plan obligations and costs of providing benefits under these plans involve various factors assumptions, and accounting elections. The
impact of assumption changes or experience different from that assumed on pension and other postretirement benefit 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 16
— Retirement Benefits for additional information.
New Accounting Standards (All Registrants)
New Accounting Standards Adopted in 2018: In 2018, the Registrants adopted the following new authoritative accounting guidance issued by the FASB.
Defined Benefit Plan Disclosures (Issued August 2018). Eliminates existing disclosure requirements related to amounts in Accumulated other comprehensive
income expected to be recognized in Net periodic benefit cost over the next year and the effects of a one-percentage-point change in the assumed health care
cost trend rates. In addition, new disclosures were added such as the weighted-average interest crediting rates for cash balance plans and an explanation for
the reasons for significant gains and losses related to changes in the benefit obligation. The standard is effective January 1, 2021, with early adoption permitted,
and must be applied retrospectively. Exelon early adopted this standard in the fourth quarter of 2018. See Note 16 — Retirement Benefits for additional
information.
Fair Value Measurement Disclosures (Issued August 2018). Updates the disclosure requirements for fair value measurements to improve the usefulness of
information for financial statement users. The guidance removes the requirements to disclose (1) the amount of and reasons for transfers between Level 1 and
Level 2, (2) the policy for timing of transfers between levels, and (3) the valuation processes for Level 3 fair value measurements and adds a requirement to
disclose the range and weighted average of significant unobservable inputs used to develop Level 3 fair value measurements. The standard is effective January
1, 2020, with early adoption permitted. The amendments to remove disclosures must be applied retrospectively and can be early adopted, while the
amendments to add disclosures must be applied prospectively and adoption can be delayed until the effective date. The Registrants early adopted, in the fourth
quarter of 2018, the amendments to remove disclosures and will adopt the amendments to add disclosures in the first quarter of 2020. The impact of the new
disclosures is not expected to be material to the Registrants’ consolidated financial statements. See Note 11 — Fair Value of Financial Assets and Liabilities for
additional information.
Reclassification of Certain Tax Effects from Accumulated Other Comprehensive Income (Issued February 2018). Provides an election for a reclassification from
AOCI to Retained earnings to eliminate the stranded tax effects resulting from the TCJA. This standard is effective January 1, 2019, with early adoption
permitted, and may be applied either in the period of adoption or retrospective to each period in which the effects of the TCJA were recognized. Exelon early
adopted this standard and elected to apply the guidance retrospectively as of December 31, 2017, which resulted in an increase to Exelon’s Retained earnings
and Accumulated other comprehensive loss of $539 million in its Consolidated Balance Sheet and Consolidated Statement of Changes in Shareholders' Equity
related to deferred income taxes associated with Exelon’s pension and OPEB obligations. There was no impact for Generation or the Utility Registrants. Exelon's
accounting policy is to release the stranded tax effects from AOCI related to its pension and OPEB plans under a portfolio (or aggregate) approach as an entire
pension or OPEB plan is liquidated or terminated. See Note 21 — Changes in Accumulated Other Comprehensive Income for additional information.
Improving the Presentation of Net Periodic Pension Cost and Net Periodic Postretirement Benefit Cost (Issued March 2017). Changes the accounting and
presentation of pension and OPEB costs at the plan sponsor (i.e., Exelon) level. The guidance requires plan sponsors to report the service cost and other non-
service cost components of net periodic pension cost and net periodic OPEB cost (together, net benefit cost) separately. Under the new guidance,
266
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Combined Notes to Consolidated Financial Statements - (Continued)
(Dollars in millions, except per share data unless otherwise noted)
service cost is presented as part of income from operations and the other non-service cost components are classified outside of income from operations in the
Consolidated Statements of Operations and Comprehensive Income. Additionally, service cost is the only component eligible for capitalization on a prospective
basis beginning on January 1, 2018. Under prior GAAP, the total amount of net benefit cost was recorded as part of income from operations and all components
were eligible for capitalization. Exelon applied the presentation of the service component and the other non-service cost components of net benefit costs
retrospectively and, accordingly, have recasted those amounts, which were not material, in its Consolidated Statement of Operations and Comprehensive
Income in prior periods presented. Exelon elected the practical expedient that permits an employer to use the amounts disclosed in its pension and other
postretirement benefit plan note for the comparative periods as the estimation basis for applying the retrospective presentation requirements. In Exelon’s
consolidated financial statements, non-service cost components of pension and OPEB cost capitalizable under a regulatory framework were prospectively
reported as regulatory assets (previously, they were capitalizable under pension and OPEB accounting guidance and reported as PP&E). These regulatory
assets are amortized outside of operating income. See Note 16 — Retirement Benefits for additional information.
Generation, ComEd, PECO, BGE, BSC, PHI, Pepco, DPL, ACE and PHISCO participate in Exelon’s single employer pension and OPEB plans and apply multi-
employer accounting. Multi-employer accounting was not impacted by this standard; therefore, Exelon's subsidiary financial statements did not change upon its
adoption.
Statement of Cash Flows: Classification of Restricted Cash (Issued November 2016). The standard states that amounts generally described as restricted cash
and restricted cash equivalents should be included with cash and cash equivalents when reconciling the beginning-of-period and end-of-period total amounts
shown on the statement of cash flows (instead of being presented as cash flow activities). The Registrants applied the new guidance using the full retrospective
method and, accordingly, have recasted the presentation of restricted cash in their Consolidated Statements of Cash Flows in the prior periods presented. See
Note 23 — Supplemental Financial Information for additional information.
Recognition and Measurement of Financial Assets and Financial Liabilities (Issued January 2016). Eliminates the available-for-sale and cost method
classification for equity securities and requires that all equity investments (other than those accounted for using the equity method of accounting) be measured
and recorded at fair value with any changes in fair value recorded through earnings and, for equity investments without a readily determinable fair value,
provides a measurement alternative of cost less impairment plus or minus adjustments for observable price changes in identical or similar assets. In addition,
equity investments without readily determinable fair values must be qualitatively assessed for impairment each reporting period and fair value determined if any
significant impairment indicators exist. If fair value is less than carrying value, the impairment is recorded through net income immediately in the period in which
it is identified. The guidance does not impact the classification or measurement of investments in debt securities. The guidance also amends several disclosure
requirements, including requiring i) financial assets and financial liabilities to be presented separately in the balance sheet or note, grouped by measurement
category and form, ii) disclosure of the methods and significant assumptions used to estimate fair value or a description of the changes in the methods and
assumptions used to estimate fair value, and iii) for financial assets and liabilities measured at amortized cost, disclosure of the fair value of the amount that
would be received to sell the asset or paid to transfer the liability. The guidance was applied using a modified retrospective transition approach with a cumulative
effect adjustment to retained earnings for initial application of the guidance at the date of adoption. The Registrants recorded an insignificant adjustment to
opening retained earnings as of January 1, 2018 related to unrealized gains/losses on available for sale equity securities. See Note 21 — Changes in
Accumulated Other Comprehensive Income for additional information.
Revenue from Contracts with Customers (Issued May 2014 and subsequently amended to address implementation questions). Changes the criteria for
recognizing revenue from a contract with a customer. The new standard replaces existing guidance on revenue recognition, including most industry specific
guidance, with a five-step model for recognizing and measuring revenue from contracts with customers. The objective of the new standard is to provide a single,
comprehensive revenue recognition model for all contracts with customers to improve comparability within industries, across industries, and across capital
markets. The underlying principle is that an entity will recognize revenue to depict the transfer of goods or services to customers at an amount that the entity
expects to be entitled to in exchange for those goods or services. The guidance also requires a number of disclosures regarding the nature, amount, timing, and
uncertainty of revenue and the related cash flows. The guidance can be applied retrospectively to each prior reporting period presented (full retrospective
method) or retrospectively with a cumulative effect adjustment to retained earnings for initial application of the guidance at the date of initial adoption (modified
retrospective method). The Registrants applied the new guidance using the full retrospective method
267
Table of Contents
Combined Notes to Consolidated Financial Statements - (Continued)
(Dollars in millions, except per share data unless otherwise noted)
and, accordingly, have recasted certain amounts in their Consolidated Statements of Operations and Comprehensive Income, Consolidated Statements of Cash
Flows, Consolidated Balance Sheets, Consolidated Statements of Changes in Shareholders' Equity and Combined Notes to Consolidated Financial Statements
in the prior periods presented. The amounts recasted in the Registrants' 2017 and 2016 Consolidated Statements of Operations and Comprehensive Income are
shown in the table below. The amounts recasted in the Registrants’ Consolidated Statements of Cash Flows, Consolidated Balance Sheets, Consolidated
Statements of Changes in Shareholders' Equity and Combined Notes to Consolidated Financi al Statements were not material. See Note 3 — Revenue from
Contracts with Customers for additional information.
268
Table of Contents
For the year ended December
31, 2017
Operating Revenues - As
reported
Competitive business
revenues $
Rate-regulated utility
revenues
Operating revenues
Electric operating revenues
Natural gas operating
revenues
Operating revenues from
affiliates
Operating Revenues -
Adjustments
Competitive business
revenues $
Rate-regulated utility
revenues
Operating revenues
Electric operating revenues
Natural gas operating
revenues
Revenues from alternative
revenue programs
Operating revenues from
affiliates
Total operating revenues $
Operating Revenues -
Retrospective application
Competitive business
revenues $
Rate-regulated utility
revenues
Operating revenues
Electric operating revenues
Natural gas operating
revenues
Revenues from alternative
revenue programs
Operating revenues from
affiliates
Combined Notes to Consolidated Financial Statements - (Continued)
(Dollars in millions, except per share data unless otherwise noted)
Exelon
Generation
ComEd
PECO
BGE
PHI
Pepco
DPL
ACE
Successor
17,360 $
— $
— $
— $
— $
— $
— $
— $
16,171
—
—
—
—
—
17,351
—
—
1,115
—
—
—
—
—
—
—
—
—
—
—
—
5,521
2,369
2,484
4,468
2,152
1,131
1,184
—
15
494
676
7
16
161
50
—
6
161
8
—
2
Total operating revenues $
33,531 $
18,466 $
5,536 $
2,870 $
3,176 $
4,679 $
2,158 $
1,300 $ 1,186
34 $
— $
— $
— $
— $
— $
— $
— $
(207)
—
—
—
207
—
34 $
—
34
—
—
—
—
—
—
(43)
—
43
—
—
—
(100)
(24)
124
—
—
—
—
—
—
—
—
(40)
—
40
—
—
—
(26)
—
26
—
34 $
— $
— $
— $
— $
— $
—
—
(6)
—
6
—
— $
17,394 $
— $
— $
— $
— $
— $
— $
— $
15,964
—
—
—
207
—
—
17,385
—
—
—
—
—
—
—
—
—
—
—
—
—
—
—
1,115
5,478
2,369
2,384
4,428
2,126
1,125
1,176
—
43
15
494
—
7
652
124
16
161
40
50
—
26
6
161
6
8
—
8
2
Total operating revenues $
33,565 $
18,500 $
5,536 $
2,870 $
3,176 $
4,679 $
2,158 $
1,300 $ 1,186
269
—
—
—
—
—
—
(8)
—
8
—
—
—
—
—
Table of Contents
For the year ended December 31,
2016
Operating Revenues - As
reported
Combined Notes to Consolidated Financial Statements - (Continued)
(Dollars in millions, except per share data unless otherwise noted)
Exelon
Generation
ComEd
PECO
BGE
Pepco
DPL
ACE
PHI
PHI
Successor
Predecessor
March 24, 2016 to
December 31, 2016
January 1, 2016 to
March 23, 2016
Competitive business revenues
$
16,324
$
Rate-regulated utility revenues
15,036
Operating revenues
Electric operating revenues
Natural gas operating revenues
Operating revenues from
affiliates
Total operating revenues
—
—
—
—
— $
—
16,312
—
—
— $
—
—
— $
—
—
— $
—
—
— $
—
—
— $
—
—
— $
—
—
— $
—
—
5,239
—
2,524
462
8
2,603
2,181
1,122
1,254
3,506
609
21
—
5
148
7
—
3
92
45
1,439
15
$
31,360
$
17,751
$
5,254
$
2,994
$
3,233
$
2,186
$
1,277
$
1,257
$
3,643
$
Operating Revenues -
Adjustments
Competitive business revenues $
6
$
Rate-regulated utility revenues
Operating revenues
Electric operating revenues
Natural gas operating revenues
Revenues from alternative
revenue programs
Operating revenues from
affiliates
(48)
—
—
—
48
—
— $
—
6
—
—
—
—
Total operating revenues $
6
$
6
$
— $
—
—
24
—
(24)
—
— $
— $
—
—
—
—
—
—
— $
— $
—
—
(72)
19
53
— $
—
—
(14)
—
14
—
— $
—
— $
— $
—
—
6
—
(6)
—
— $
— $
—
—
(9)
—
9
—
— $
Operating Revenues -
Retrospective application
Competitive business revenues $
16,330
$
Rate-regulated utility revenues
14,988
Operating revenues
Electric operating revenues
Natural gas operating revenues
Revenues from alternative
revenue programs
Operating revenues from
affiliates
—
—
—
48
—
— $
—
16,318
— $
—
—
— $
—
—
— $
—
—
— $
—
—
— $
—
—
— $
—
—
—
—
—
1,439
5,263
—
2,524
462
(24)
15
—
8
2,531
2,167
1,128
1,245
3,463
1,122
628
53
21
—
14
5
148
(6)
7
—
9
3
92
43
45
57
(26)
—
Total operating revenues $
31,366
$
17,757
$
5,254
$
2,994
$
3,233
$
2,186
$
1,277
$
1,257
$
3,643
$
1,153
270
—
—
—
1,096
57
—
1,153
—
—
—
26
—
(26)
—
—
—
—
—
— $
—
—
(43)
—
43
—
— $
— $
—
—
Table of Contents
Combined Notes to Consolidated Financial Statements - (Continued)
(Dollars in millions, except per share data unless otherwise noted)
New Accounting Standards Adopted as of January 1, 2019: The following new authoritative accounting guidance issued by the FASB was adopted as of
January 1, 2019 and will be reflected by the Registrants in their consolidated financial statements beginning in the first quarter of 2019.
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 is effective January
1, 2020, with early adoption permitted, 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 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 is not expected to have a material impact on the Registrants’ financial statements.
Leases (Issued February 2016). Increases transparency and comparability among organizations by recognizing lease assets and lease liabilities on the balance
sheet and disclosing key information about leasing arrangements. The Registrants adopted the standard on January 1, 2019.
The new standard requires lessees to recognize both the right-of-use assets and lease liabilities in the balance sheet for most leases, whereas under previous
GAAP only finance lease liabilities (referred to as capital leases) were recognized in the balance sheet. In addition, the definition of a lease has been revised
which may result in changes to the classification of an arrangement as a lease. Under the new standard, an arrangement that conveys the right to control the
use of an identified asset by obtaining substantially all of its economic benefits and directing how it is used is a lease, whereas the previous definition focuses on
the ability to control the use of the asset or to obtain its output. Quantitative and qualitative disclosures related to the amount, timing and judgments of an entity’s
accounting for leases and the related cash flows are expanded. Disclosure requirements apply to both lessees and lessors, whereas previous disclosures
related only to lessees. The recognition, measurement, and presentation of expenses and cash flows arising from a lease by a lessee have not significantly
changed from previous GAAP. Lessor accounting is also largely unchanged.
The new standard provides a number of transition practical expedients, which the Registrants have elected, including:
•
•
•
a "package of three" expedients that must be taken together and allow entities to (1) not reassess whether existing contracts contain leases, (2)
carryforward 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 Registrants have assessed the lease standard and executed a detailed implementation plan in preparation for adoption, which included the following key
activities:
•
•
•
•
Developed a complete lease inventory and abstracted the required data attributes into a lease accounting system that supports the Registrants' lease
portfolios and integrates with existing systems.
Evaluated the transition practical expedients available under the standard.
Identified, assessed and documented technical accounting issues, policy considerations and financial reporting implications.
Identified and implemented changes to processes and controls to ensure all impacts of the new standard are effectively addressed.
The adoption of the new standard is expected to result in right of use assets and lease obligations for operating leases recorded in the Registrants’ Consolidated
Balance Sheets on January 1, 2019 of approximately:
271
Table of Contents
Combined Notes to Consolidated Financial Statements - (Continued)
(Dollars in millions, except per share data unless otherwise noted)
ROU Assets
Lease Liabilities
Exelon
Generation
ComEd
PECO
$1,400-$1,500
$1,600-$1,700
$1,000-$1,100
$1,200-$1,300
$5-$10
$5-$10
$1-$5
$1-$5
BGE
$100-$120
$100-$120
PHI
Pepco
DPL
ACE
$250-$270
$300-$320
$60-$65
$60-$65
$70-$75
$75-$80
$20-$25
$20-$25
The impact of adopting the new standard on retained earnings as of January 1, 2019 is expected to be immaterial.
New Accounting Standards Issued and Not Yet Adopted as of December 31, 2018: The following new authoritative accounting guidance issued by the
FASB has not yet been adopted and reflected by the Registrants in their consolidated financial statements as of December 31, 2018. Unless otherwise
indicated, the Registrants are currently assessing the impacts such guidance may have (which could be material) in their Consolidated Balance Sheets,
Consolidated Statements of Operations and Comprehensive Income, Consolidated Statements of Cash Flows and disclosures, as well as the potential to early
adopt where applicable. The Registrants have assessed other FASB issuances of new standards which are not listed below given the current expectation that
such standards will not significantly impact the Registrants' financial reporting.
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. Exelon, Generation, ComEd, PHI and DPL have goodwill
as of December 31, 2018. This updated guidance is not currently expected to impact the Registrants’ financial reporting. The standard is effective January 1,
2020, with early adoption permitted, and must be applied on a prospective basis.
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 the entity’s current
estimate of credit losses expected to be incurred over the life of the financial instrument. The standard does not make changes to the existing impairment
models for non-financial assets such as fixed assets, intangibles and goodwill. The standard will be effective January 1, 2020 (with early adoption as of January
1, 2019 permitted) and requires a modified retrospective transition approach through a cumulative-effect adjustment to retained earnings as of the beginning of
the period of adoption. The Registrants are currently assessing the impacts of this standard.
2. Variable Interest Entities (All Registrants)
A VIE is a legal entity that possesses any of the following characteristics: an insufficient amount of equity at risk to finance its activities, equity owners who do
not have the power to direct the significant activities of the entity (or have voting rights that are disproportionate to their ownership interest), or equity owners
who do not have the obligation to absorb expected losses or the right to receive the expected residual returns of the entity. Companies are required to
consolidate a VIE if they are its primary beneficiary, which is the enterprise that has the power to direct the activities that most significantly affect the entity’s
economic performance.
At December 31, 2018 and 2017 , Exelon, Generation, PHI and ACE collectively consolidated five VIEs or VIE groups for which the applicable Registrant was
the primary beneficiary (see Consolidated Variable Interest Entities below). As of December 31, 2018 and 2017 , Exelon and Generation collectively had
significant interests in seven 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 Variable Interest Entities below).
272
Table of Contents
Consolidated Variable Interest Entities
Combined Notes to Consolidated Financial Statements - (Continued)
(Dollars in millions, except per share data unless otherwise noted)
The carrying amounts and classification of the consolidated VIEs’ assets and liabilities included in the Registrants' consolidated financial statements at
December 31, 2018 and 2017 are as follows:
Current assets
Noncurrent assets
Total assets
Current liabilities
Noncurrent liabilities
Total liabilities
Current assets
Noncurrent assets
Total assets
Current liabilities
Noncurrent liabilities
Total liabilities
$
$
$
$
$
$
$
$
December 31, 2018
Exelon (a)
Generation
PHI (a)
ACE
938
$
931
$
9,071
9,045
7
26
9,976
$
33
$
10,009
274
$
$
252
$
22
47
3,280
3,233
3,554
$
3,485
$
69
$
December 31, 2017
Exelon (a)
Generation
PHI (a)
ACE
662
$
652
$
10
$
9,317
9,286
31
9,979
308
$
$
9,938
$
41
$
272
$
36
$
3,316
3,250
66
3,624
$
3,522
$
102
$
4
19
23
19
40
59
6
23
29
32
58
90
__________
(a)
Includes certain purchase accounting adjustments not pushed down to the ACE standalone entity.
Except as specifically noted below, the assets in the table above are restricted for settlement of the VIE obligations and the liabilities in the table can only be
settled using VIE resources.
As of December 31, 2018 and 2017 , Exelon's and Generation's consolidated VIEs consist of:
Investments in Other Energy Related Companies
During 2015, Generation sold 69% of its equity interest in a company to a tax equity investor. The company holds an equity method investment in a distributed
energy company that is an unconsolidated VIE (see unconsolidated VIE section for additional details). Generation and the tax equity investor contributed a total
of $227 million of equity in proportion to their ownership interests to the company. The company meets the definition of a VIE because it has a similar structure
to a limited partnership and the limited partners do not have kick-out rights with respect to the general partner. Generation is the primary beneficiary because
Generation manages the day-to-day activities of the entity.
During the fourth quarter of 2017 Generation acquired a controlling financial interest in an energy development company. The company is in the development
stage and requires additional subordinated financial support from the equity holders to fund activities. Generation is the majority owner with a 62% equity interest
and has the power to direct the activities that most significantly affect the economic performance of the company.
Renewable Energy Project Companies
In July 2017, Generation sold a 49% interest in EGRP to an outside investor for $400 million of cash plus immaterial working capital and other customary post-
closing adjustments. EGRP meets the definition of a VIE because the EGRP has a similar structure to a limited partnership and the limited partners do not have
kick out rights with respect to the general partner. Generation is the primary beneficiary because Generation manages the day-to-day activities of the entity;
therefore, Generation will continue to consolidate EGRP. EGRP is a collection of wind and solar project entities and some of these project entities are VIEs that
are consolidated by EGRP. The details relating to these VIEs are discussed below.
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Combined Notes to Consolidated Financial Statements - (Continued)
(Dollars in millions, except per share data unless otherwise noted)
Generation owns a number of limited liability companies that build, own, and operate solar and wind power facilities some of which are owned by EGRP. While
Generation or EGRP owns 100% of the solar entities and 100% of the majority of the wind entities, it has been determined that certain of the solar and wind
entities are VIEs because the entities require additional subordinated financial support in the form of a parental guarantee of debt, loans from the customers in
order to obtain the necessary funds for construction of the solar facilities, or the customers absorb price variability from the entities through the fixed price power
and/or REC purchase agreements. Generation is the primary beneficiary of these solar and wind entities that qualify as VIEs because Generation controls the
design, construction, and operation of the facilities. 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.
While Generation or EGRP owns 100% of the majority of the wind entities, four of the projects have noncontrolling equity interests of 1% held by third parties
and one of the projects has noncontrolling equity interests related to its Class B Membership Interest (see additional details below). The entities with
noncontrolling equity interests of 1% held by third parties meet the definition of a VIE because the entities have noncontrolling equity interest holders that absorb
variability from the wind projects. Generation’s or the EGRP's current economic interests in three of these projects is significantly greater than its stated
contractual governance rights and all of these projects have reversionary interest provisions that provide the noncontrolling interest holder with a purchase
option, certain of which are considered bargain purchase prices, which, if exercised, transfers ownership of the projects to the noncontrolling interest holder upon
either the passage of time or the achievement of targeted financial returns. The ownership agreements with the noncontrolling interests state that Generation or
EGRP are to provide financial support to the projects in proportion to its current 99% economic interests in the projects. Generation provides operating and
capital funding to the wind project entities for ongoing construction, operations and maintenance and there is limited recourse to Generation related to certain
wind project entities. However, no additional support to these projects beyond what was contractually required has been provided. Generation is the primary
beneficiary of these wind entities because Generation controls the design, construction, and operation of the facilities.
In December 2016, Generation sold 100% of the Class B Membership Interests to a tax equity investor and retained 100% of the Class A Membership Interests
of its equity interest in one of its wind entities that was previously consolidated under the voting interest model and was subsequently contributed to EGRP in
2017. The wind entity meets the definition of a VIE because the company has a similar structure to a limited partnership and the limited partners do not have
kick-out rights with respect to the general partner. While Generation is the minority interest holder, Generation is the primary beneficiary, because Generation
manages the day-to-day activities of the entity. Therefore, the entity continues to be consolidated by Generation.
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 13 — Debt and Credit Agreements for additional information on ExGen Renewables IV and ITEM 2. PROPERTIES for additional details on the specific
projects included within EGRP.
Retail Power and Gas Companies
In March 2014, Generation began consolidating retail power and gas VIEs for which Generation is the primary beneficiary as a result of energy supply contracts
that give Generation the power to direct the activities that most significantly affect the economic performance of the entities. Generation does not have an equity
ownership interest in these entities, but provides approximately $34 million in credit support for the retail power and gas companies for which Generation is the
sole supplier of energy. These entities are included in Generation’s consolidated financial statements, and the consolidation of the VIEs do not have a material
impact on Generation’s financial results or financial condition.
CENG
CENG is a joint venture between Generation and EDF. On April 1, 2014, Generation, CENG, and subsidiaries of CENG executed the Nuclear Operating
Services Agreement (NOSA) pursuant to which Generation now 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. As a result of executing the NOSA, CENG qualifies as a VIE due to the disproportionate relationship between
Generation’s 50.01% equity ownership interest and its role in conducting the operational activities of CENG and the CENG fleet conveyed through the NOSA.
Further, since
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Combined Notes to Consolidated Financial Statements - (Continued)
(Dollars in millions, except per share data unless otherwise noted)
Generation is conducting the operational activities of CENG and the CENG fleet, Generation qualifies as the primary beneficiary of CENG and, therefore, is
required to consolidate the results of operations and financial position of CENG.
Exelon and Generation, where indicated, provide the following support to CENG:
•
•
•
•
•
under power purchase agreements with CENG, Generation purchased or will purchase 50.01% of the available output generated by the CENG
nuclear plants not subject to other contractual agreements from January 2015 through the end of the operating life of each respective plant. However,
pursuant to amendments dated March 31, 2015, the energy obligations under the Ginna Nuclear Power Plant (Ginna) PPAs were suspended during
the term of the RSSA, through the end of March 31, 2017. With the expiration of the RSSA, the PPA was reinstated beginning April 1, 2017. (see
Note 4 — Regulatory Matters for additional details),
Generation provided a $400 million loan to CENG. As of December 31, 2018 , the remaining obligation is $196 million , including accrued interest.
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 22 — 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.
As of December 31, 2018 and 2017 , Exelon's, PHI's and ACE's consolidated VIE consists of:
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. During the three years ended
December 31, 2018 , 2017 and 2016 , ACE transferred $30 million , $48 million and $60 million to ATF, respectively.
As of December 31, 2018 and 2017 , ComEd, PECO, BGE, Pepco and DPL do not have any material consolidated VIEs.
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Combined Notes to Consolidated Financial Statements - (Continued)
(Dollars in millions, except per share data unless otherwise noted)
Assets and Liabilities of Consolidated VIEs
Included within the balances above are assets and liabilities of certain consolidated VIEs for which the assets can only be used to settle obligations of those
VIEs, and liabilities that creditors, or beneficiaries, do not have recourse to the general credit of the Registrants. As of December 31, 2018 and 2017 , these
assets and liabilities primarily consisted of the following:
Cash and cash equivalents
Restricted cash and cash equivalents
Accounts receivable, net
Customer
Other
Inventory
Materials and supplies
Other current assets
Total current assets
Property, plant and equipment, net
Nuclear decommissioning trust funds
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
Unamortized energy contract liabilities
Other noncurrent liabilities
Total noncurrent liabilities
Total liabilities
December 31, 2018
Exelon (a)
Generation
PHI (a)
ACE
414 $
66
414 $
62
— $
4
146
23
212
52
913
6,145
2,351
258
8,754
146
23
212
49
906
6,145
2,351
232
8,728
9,667
$
9,634
$
—
—
—
3
7
—
—
26
26
33
$
87 $
66 $
21 $
$
$
$
96
72
15
3
273
1,072
2,160
1
42
3,275
96
72
15
3
252
1,025
2,160
1
42
3,228
$
3,548
$
3,480
$
—
1
—
—
22
47
—
—
—
47
69
$
—
4
—
—
—
—
4
—
—
19
19
23
18
—
1
—
—
19
40
—
—
—
40
59
__________
(a)
Includes certain purchase accounting adjustments not pushed down to the ACE standalone entity.
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Table of Contents
Cash and cash equivalents
Restricted cash and cash equivalents
Accounts receivable, net
Customer
Other
Inventory
Materials and supplies
Other current assets
Total current assets
Property, plant and equipment, net
Nuclear decommissioning trust funds
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
Other noncurrent liabilities
Total noncurrent liabilities
Total liabilities
Combined Notes to Consolidated Financial Statements - (Continued)
(Dollars in millions, except per share data unless otherwise noted)
$
$
$
December 31, 2017
Exelon (a)
Generation
PHI (a)
ACE
126 $
64
126 $
58
— $
6
170
25
205
45
635
6,186
2,502
274
8,962
170
25
205
41
625
6,186
2,502
243
8,931
—
—
—
4
10
—
—
31
31
9,597 $
9,556 $
41 $
102 $
114
67
18
7
308
1,154
2,035
121
3,310
67 $
114
66
18
7
272
1,088
2,035
121
3,244
35 $
—
1
—
—
36
66
—
—
66
$
3,618 $
3,516 $
102 $
—
6
—
—
—
—
6
—
—
23
23
29
31
—
1
—
—
32
58
—
—
58
90
__________
(a)
Includes certain purchase accounting adjustments not pushed down to the ACE standalone entity.
Unconsolidated Variable Interest Entities
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. Further, Exelon and Generation have not
provided material debt or equity support, liquidity arrangements or performance guarantees associated with these commercial agreements.
As of December 31, 2018 and 2017 , Exelon and Generation had significant unconsolidated variable interests in seven VIEs for which Exelon or Generation, as
applicable, was not the primary beneficiary. These interests include certain equity method investments and certain commercial agreements. Exelon and
Generation only include unconsolidated VIEs that are individually material in the tables below. However, Exelon and Generation have several individually
immaterial VIEs that in aggregate represent a total investment of $15 million and $13 million , respectively,
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Combined Notes to Consolidated Financial Statements - (Continued)
(Dollars in millions, except per share data unless otherwise noted)
as of December 31, 2018 . These immaterial VIEs are equity and debt securities in energy development companies. As of December 31, 2018 , the maximum
exposure to loss related to these securities included in Investments in Exelon's and Generation's Consolidated Balance Sheets is limited to the $15 million and
$13 million , respectively.
The following tables present summary information about Exelon and Generation’s significant unconsolidated VIE entities:
December 31, 2018
$
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
Contract intangible asset
Net assets pledged for Zion Station decommissioning (b)
Commercial
Agreement
VIEs
Equity
Investment
VIEs
597 $
37
—
560
—
7
—
Total
472 $
1,069
222
223
27
223
—
—
259
223
587
223
7
—
December 31, 2017
Commercial
Agreement
VIEs
Equity
Investment
VIEs
Total
$
625 $
509 $
1,134
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
Contract intangible asset
Net assets pledged for Zion Station
decommissioning (b)
37
—
588
—
8
2
228
251
30
251
—
—
265
251
618
251
8
2
__________
(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.
(b) These items represent amounts in Exelon’s and Generation’s Consolidated Balance Sheets related to the asset sale agreement with ZionSolutions, LLC. The net assets
pledged for Zion Station decommissioning includes gross pledged assets of $9 million and $39 million as of December 31, 2018 and December 31, 2017 , respectively;
offset by payables to ZionSolutions LLC of $9 million and $37 million as of December 31, 2018 and December 31, 2017 , respectively. These items are included to provide
information regarding the relative size of the ZionSolutions, LLC unconsolidated VIE.
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. In addition, there are no material
agreements with, or commitments by, third parties that would materially affect the fair value or risk of their variable interests in these VIEs.
As of December 31, 2018 and 2017 , Exelon's and Generation's unconsolidated VIEs consist of:
Energy Purchase and Sale Agreements
Generation has several energy purchase and sale agreements with generating facilities. Generation has evaluated the significant agreements, ownership
structures and risks of each entity, and determined that certain of the entities are VIEs because the entity absorbs risk through the sale of fixed price power and
renewable energy credits. Generation has reviewed the entities and has determined that Generation is not the primary beneficiary of the VIEs
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Combined Notes to Consolidated Financial Statements - (Continued)
(Dollars in millions, except per share data unless otherwise noted)
because Generation does not have the power to direct the activities that most significantly impact the VIEs economic performance.
ZionSolutions
Generation has an asset sale agreement with EnergySolutions, Inc. and certain of its subsidiaries, including ZionSolutions, LLC (ZionSolutions), which is further
discussed in Note 15 — Asset Retirement Obligations . Under this agreement, ZionSolutions can put the assets and liabilities back to Generation when
decommissioning activities under the asset sale agreement are complete. Generation has evaluated this agreement and determined that, through the put option,
it has a variable interest in ZionSolutions but is not the primary beneficiary. As a result, Generation has concluded that consolidation is not required. Other than
the asset sale agreement, Exelon and Generation do not have any contractual or other obligations to provide additional financial support and ZionSolutions’
creditors do not have any recourse to Exelon’s or Generation’s general credit.
Investment in Distributed Energy Companies
In July 2014, Generation entered into an arrangement to purchase a 90% equity interest and 90% of the tax attributes of a distributed energy company.
Generation contributed a total $85 million of equity. The distributed energy company meets the definition of a VIE because the company has a similar structure
to a limited partnership and the limited partners do not have kick-out rights of the general partner. Generation is not the primary beneficiary; therefore, the
investment continues to be recorded using the equity method.
During 2015, a company that is consolidated by Generation as a VIE entered into an arrangement to purchase a 90% equity interest and 99% of the tax
attributes of another distributed energy company (see additional details in the Consolidated Variable Interest Entities section above). The equity holders (of
which Generation is one) contributed to the distributed energy company a total of $227 million of equity in proportion to their ownership interests. The equity
holders provided a parental guarantee of up to $275 million in support of equity contributions to the distributed energy company. As all equity contributions were
made as of the first quarter of 2017, there is no further payment obligation under the parental guarantee. The distributed energy company meets the definition of
a VIE because the company has a similar structure to a limited partnership and the limited partners do not have kick-out rights of the general partner. Generation
is not the primary beneficiary; therefore, the investment is recorded using the equity method.
Both distributed energy companies from the 2015 and 2014 arrangements are considered related parties to Generation.
ComEd and PECO
The financing trust of ComEd, ComEd Financing III, and the financing trusts of PECO, PECO Trust III and PECO Trust IV, are not consolidated in Exelon’s,
ComEd’s, or PECO’s financial statements. These financing trusts were created to issue mandatorily redeemable trust preferred securities. ComEd and PECO
have concluded that they do not have a significant variable interest in ComEd Financing III, PECO Trust III, or PECO Trust IV as each Registrant financed its
equity interest in the financing trusts through the issuance of subordinated debt and, therefore, has no equity at risk. See Note 13 — Debt and Credit
Agreements for additional information.
3. 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 associated with these sources of revenue are further discussed 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 have elected to use the right to invoice practical expedient for the contracts within these revenue categories and generally
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Combined Notes to Consolidated Financial Statements - (Continued)
(Dollars in millions, except per share data unless otherwise noted)
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.
Competitive Power Sales (Exelon and Generation)
Generation sells power and other energy-related commodities to both wholesale and retail customers across multiple geographic regions through its customer-
facing business, Constellation. Power sale contracts generally contain various performance obligations including the delivery of power and other energy-related
commodities such as capacity, ZECs, RECs or other ancillary services. Certain performance obligations such as power and capacity are generally delivered
over time whereas other performance obligations such as RECs and ZECs are generally delivered at a point in time. In either case, revenues related to all of the
performance obligations in such bundled power sale contracts are generally recognized concurrently as the power is generated. Except as noted in the
paragraph below, there are no significant judgments in allocating the transaction price since all performance obligations are satisfied simultaneously upon the
generation of power. Payment terms generally require that the customers pay for the power or the energy-related commodity within the month following delivery
to the customer and there are generally no significant financing components.
Certain contracts may contain limits on the total amount of revenue we are able to collect over the entire term of the contract. In such cases, the Registrants
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.
Competitive Natural Gas Sales (Exelon and Generation)
Generation sells natural gas on a full requirements basis or for an agreed upon volume to both commercial and residential customers. The primary performance
obligation associated with natural gas sale contracts is the delivery of the natural gas to the customer. Revenues related to the sale of natural gas are
recognized over time as the natural gas is delivered to and consumed by the customer. Payment from customers is typically due within the month following
delivery of the natural gas to the customer and there are generally no significant financing components.
Other Competitive Products and Services (Exelon and Generation)
Generation also sells 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. These contracts generally contain a single performance obligation, which is the
construction and/or installation of the asset for the customer. The average contract term for these projects is approximately 18 months. Revenues, and
associated costs, are recognized throughout the contract term using an input method to measure progress towards completion. 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. Payments from customers are typically due within 30 or 45 days from the date the
invoice is generated and sent to the customer.
Regulated Electric and Gas Tariff Sales (Exelon and the Utility Registrants)
The Utility Registrants sell electricity and electricity distribution services to residential, commercial, industrial and governmental customers through regulated
tariff rates approved by their state regulatory commissions. PECO, BGE and DPL also sell natural gas and gas distribution services to residential, commercial,
and industrial customers through regulated tariff rates approved by their state regulatory commissions. The performance obligation associated with these tariff
sale contracts is the delivery of electricity and/or natural gas. Tariff sales are generally considered daily contracts given that customers can discontinue service
at any time. Revenues are generally recognized over time (each day) as the electricity and/or natural gas is delivered to customers. Payment terms generally
require that customers pay for the services within the month following delivery of the electricity or natural gas to the customer and there are generally no
significant financing components or variable consideration.
Electric and natural gas utility customers have the choice to purchase electricity or natural gas from competitive electric generation and natural gas suppliers.
While the Utility Registrants are required under state legislation to bill their customers for the supply and distribution of electricity and/or natural gas, they
recognize revenue related only to the distribution services when customers purchase their electricity or natural gas from competitive suppliers.
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Combined Notes to Consolidated Financial Statements - (Continued)
(Dollars in millions, except per share data unless otherwise noted)
Regulated Transmission Services (Exelon and the Utility Registrants)
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 are members of PJM, the regional transmission
organization designated by FERC to coordinate the movement of wholesale electricity in PJM’s region, which includes portions of the mid-Atlantic and Midwest.
In accordance with FERC-approved rules, the Utility Registrants and other transmission owners in the PJM region make their transmission facilities available to
PJM, which directs and controls the operation of these transmission facilities and accordingly compensates the Utility Registrants and other transmission
owners. The performance obligations associated with the Utility Registrants’ contract with PJM include (i) Network Integration Transmission Services (NITS), (ii)
scheduling, system control and dispatch services, and (iii) access to the wholesale grid. These performance obligations are satisfied over time, and Utility
Registrants utilize output methods to measure the progress towards their completion. 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. PJM pays the Utility Registrants for these
services on a weekly basis and there are no financing components or variable consideration.
Costs to Obtain or Fulfill a Contract with a Customer (Exelon and Generation)
Generation incurs incremental costs in order to execute certain retail power and gas sales contracts. These costs primarily relate to retail broker fees and sales
commissions. Generation has capitalized such contract acquisition costs in the amount of $32 million and $26 million as of December 31, 2018 and
December 31, 2017 , respectively, within Other current assets and Other deferred debits in Exelon’s and Generation’s Consolidated Balance Sheets. These
costs are capitalized when incurred and amortized using the straight-line method over the average length of such retail contracts, which is approximately 2
years. Exelon and Generation recognized amortization expense associated with these costs in the amount of $22 million and $30 million for the twelve months
ended December 31, 2018 , and December 31, 2017 , respectively, within Operating and maintenance expense in Exelon’s and Generation’s Consolidated
Statements of Operations and Comprehensive Income. Generation does not incur material costs to fulfill contracts with customers that are not already
capitalized under existing guidance. In addition, the Utility Registrants do not incur any material costs to obtain or fulfill contracts with customers.
Contract Balances (All Registrants)
Contract Assets
Generation records contract assets for the revenue recognized on the construction and installation of energy efficiency assets and new power generating
facilities before Generation has an unconditional right to bill for and receive the consideration from the customer. These contract assets are subsequently
reclassified to receivables when the right to payment becomes unconditional. Generation records contract assets and contract receivables within Other current
assets and Accounts receivable, net - Customer, respectively, within Exelon’s and Generation’s Consolidated Balance Sheets. The following table provides a
rollforward of the contract assets reflected in Exelon's and Generation's Consolidated Balance Sheets from January 1, 2018 to December 31, 2018 :
Contract Assets
Balance as of January 1, 2018
Increases as a result of changes in the estimate of the stage of completion
Amounts reclassified to receivables
Balance at December 31, 2018
The Utility Registrants do not have any contract assets.
281
Exelon and Generation
283
50
(146)
187
$
$
Table of Contents
Contract Liabilities
Combined Notes to Consolidated Financial Statements - (Continued)
(Dollars in millions, except per share data unless otherwise noted)
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 liabilities reflected in Exelon's and Generation's Consolidated Balance Sheet from January 1, 2018 to December 31, 2018 :
Contract Liabilities
Balance as of January 1, 2018
Increases as a result of additional cash received or due
Amounts recognized into revenues
Balance at December 31, 2018
Exelon
Generation
$
$
35 $
179
(187)
27 $
35
465
(458)
42
The Utility Registrants also record contract liabilities when consideration is received prior to the satisfaction of the performance obligations. As of December 31,
2018 and December 31, 2017 , 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, 2018 . Generation has elected the exemption which permits the exclusion from this disclosure of certain variable contract
consideration. As such, the majority of Generation’s power and gas sales contracts are excluded from this disclosure as they contain variable volumes and/or
variable pricing. Thus, 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.
The majority of the Utility Registrants’ tariff sale contracts are generally day-to-day contracts and, therefore, do not contain any future, unsatisfied performance
obligations to be included in this disclosure. Further, the Utility Registrants have elected the exemption to not disclose the transaction price allocation to
remaining performance obligations for contracts with an original expected duration of one year or less. As such, gas and electric tariff sales contracts and
transmission revenue contracts are excluded from this disclosure.
Exelon
Generation
Revenue Disaggregation (All Registrants)
2019
2020
2021
2022
2023 and
thereafter
$
631 $
631
329 $
329
119 $
119
47 $
47
138 $
138
Total
1,264
1,264
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 24 — Segment Information for the presentation of the Registrant's revenue disaggregation.
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Combined Notes to Consolidated Financial Statements - (Continued)
(Dollars in millions, except per share data unless otherwise noted)
4. 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 2018.
Completed Distribution Base Rate Case Proceedings
Registrant/Jurisdiction
Filing Date
Requested Revenue
Requirement Increase
(Decrease)
Approved Revenue
Requirement Increase
(Decrease)
Approved ROE
Approval Date
Rate Effective Date
ComEd - Illinois (Electric) (b)
PECO - Pennsylvania (Electric) (c) March 29, 2018 $
April 16, 2018 $
(23)
(a) $
82 (a) $
(24)
(a)
25 (a)
8.69%
December 4, 2018
January 1, 2019
N/A
December 20, 2018
January 1, 2019
June 8, 2018
(amended
August 24,
2018 and
October 12,
2018)
January 2, 2018
(amended
February 5,
2018)
December 19,
2017 (amended
February 9,
2018)
July 14, 2017
(amended
November 16,
2017)
August 17,
2017 (amended
February 9,
2018)
$
$
$
$
$
BGE - Maryland (Natural Gas)
Pepco - Maryland (Electric)
Pepco - District of Columbia
(Electric) (d)
DPL - Maryland (Electric) (e)
DPL - Delaware (Electric)
61
$
43
9.8%
January 4, 2019
January 4, 2019
3 (a) $
(15)
(a)
9.5%
May 31, 2018
June 1, 2018
66
$
(24)
(a)
9.525%
August 9, 2018
August 13, 2018
19
$
13
9.5%
February 9, 2018
February 9,
2018
12 (a) $
(7)
(a)
9.7%
August 21, 2018
March 17, 2018
August 17,
2017 (amended
February 9,
2018)
Includes the annual ongoing TCJA tax savings further discussed below.
DPL - Delaware (Natural Gas)
__________
(a)
(b) 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 1 st , 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).
November 8, 2018
March 17, 2018
4 (a) $
9.7%
(4)
$
(a)
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Table of Contents
Combined Notes to Consolidated Financial Statements - (Continued)
(Dollars in millions, except per share data unless otherwise noted)
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% inclusive of an allowed ROE of 8.69% , 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.
(c) The PECO base rate case proceeding was resolved through a settlement agreement, which did not specify an approved ROE.
(d) On September 7, 2018, Pepco submitted an updated filing for an increase of $4 million to the customer base rate credit established in connection with the merger between
Exelon and PHI for residential customers, representing the TCJA benefits for the period January 1, 2018 through August 12, 2018.
(e) The DPL Maryland base rate case proceeding was resolved through a settlement agreement, which did not specify an overall ROE. The settlement agreement included
an ROE of 9.5% solely for purposes of calculating AFUDC and regulatory asset carrying costs.
In the second quarter of 2018, DPL discovered a rate design issue in Maryland such that the current rates were not sufficient to collect the full amount of the $13 million
revenue increase agreed to by the parties in the recent settlement. On September 5, 2018, the MDPSC approved DPL’s proposed revisions to resolve the rate design
issue on a prospective basis, effective September 5, 2018.
Pending Distribution Base Rate Case Proceedings
Registrant/Jurisdiction
Filing Date
Requested Revenue Requirement
Increase
Requested ROE
Expected Approval Timing
ACE - New Jersey (Electric)
August 21, 2018
(amended November 19,
2018)
$
122 (a)
30
10.1%
Third quarter of 2019 (b)
Pepco - Maryland (Electric)
__________
(a) Requested increase is before New Jersey sales and use tax and includes $40 million of higher depreciation expense related to its updated depreciation study and the
Third quarter of 2019
January 15, 2019
10.3%
$
annual ongoing TCJA tax savings further discussed below.
(b) ACE plans to put interim rates in effect on or around May 21, 2019, subject to refund, as allowed by the regulation.
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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Combined Notes to Consolidated Financial Statements - (Continued)
(Dollars in millions, except per share data unless otherwise noted)
For 2018, 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
Initial Revenue
Requirement
(Decrease) Increase (b)
Annual Reconciliation
Increase/(Decrease)
Total Revenue
Requirement (Decrease)
Increase
Allowed Return on Rate
Base (d)
Allowed ROE (e)
ComEd (a)
BGE (a)
Pepco
DPL
$
(44) $
18
$
10
6
14
4
2
13
(26)
26 (c)
8
27
8.32%
7.61%
7.82%
7.29%
11.50%
10.50%
10.50%
10.50%
ACE (a)
__________
(a) The time period for any formal challenges to the annual transmission formula rate update filings expired with no formal challenges submitted.
(b) The initial revenue requirement changes reflect the annual benefit of lower income tax rates effective January 1, 2018 resulting from the enactment of the TCJA of $69
million , $18 million , $13 million , $12 million and $11 million for ComEd, BGE, Pepco, DPL and ACE, respectively. They do not reflect the pass back or recovery of
income tax-related regulatory liabilities or assets, including those established upon enactment of the TCJA. See further discussion below.
10.50%
8.02%
(4)
—
4
(c) The change in BGE's transmission revenue requirement includes a FERC approved dedicated facilities charge of $12 million to recover the costs of providing transmission
service to specifically designated load by BGE.
(d) Represents the weighted average debt and equity return on transmission rate bases.
(e) 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.
Pending 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. The formula rate filing includes a requested increase of $22 million
to PECO’s annual transmission revenues and a requested rate of return on common equity of 11% , inclusive of a 50 basis point adder for being a member of a
regional transmission organization. PECO requested that the new transmission rate be effective as of July 2017. 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 May 4, 2018, the Chief Administrative Law Judge terminated settlement judge procedures and designated a new presiding judge. PECO cannot
predict the outcome of this proceeding, or the transmission formula FERC may approve.
On May 11, 2018, pursuant to the transmission formula rate request discussed above, PECO made its first annual formula rate update, which included a
revenue decrease of $6 million. The revenue decrease of $6 million included an approximately $20 million reduction as a result of the tax savings associated
with the TCJA. The updated transmission rate was effective June 1, 2018, subject to refund.
Tax Cuts and Jobs Act
The Utility Registrants have made filings with their state regulatory commissions to pass back tax savings related to TCJA to their distribution customers, which
are detailed below. The tax savings include the benefit of lower federal income tax rates and the settlement of a portion of the deferred income tax regulatory
liabilities established upon the enactment of the TCJA. The ongoing annual TCJA tax savings in the table below represent the annual savings for distribution
customers reflected in the initial customers rates approved after the TCJA. Subsequent annual TCJA tax savings will be approved as part of the annual update
to the electric distribution formula rate for ComEd or base rate case proceedings for PECO, BGE, Pepco, DPL and ACE.
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Combined Notes to Consolidated Financial Statements - (Continued)
(Dollars in millions, except per share data unless otherwise noted)
Registrant/Jurisdiction
Amount
Approval Date
Rate Effective Date
Stub Period
Approval Date
Refund Amount/Period
Ongoing TCJA Tax Savings
Stub Period Bill Credit from TCJA Tax Savings
ComEd - Illinois
(Electric)
PECO - Pennsylvania
(Electric)
PECO - Pennsylvania
(Natural Gas)
BGE - Maryland
(Electric)
BGE - Maryland (Natural
Gas)
Pepco - Maryland
(Electric)
Pepco - District of
Columbia (Electric)
DPL - Maryland
(Electric)
DPL - Delaware
(Electric)
DPL - Delaware (Natural
Gas)
$
$
$
$
$
$
$
$
$
$
201
January 18, 2018
February 1, 2018
Not applicable
71 December 20, 2018
January 1, 2019
January 1, 2018 -
December 31, 2018 December 20, 2018
$67 / 2019 (majority
in January)
4
(a)
July 1, 2018
Not applicable
72
January 31, 2018
February 1, 2018
January 1, 2018 -
January 31, 2018
January 1, 2018 -
January 31, 2018
To be addressed in next electric distribution
base rate case
31
January 31, 2018
February 1, 2018
January 4, 2019
$2 / Q1 2019
May 31, 2018
$10 / July 2018
31
May 31, 2018
June 1, 2018
January 1, 2018 -
June 1, 2018
January 1, 2018 -
August 12, 2018
39
August 9, 2018
August 13, 2018
September 7, 2018
January 1, 2018 -
March 31, 2018
14
April 18, 2018
April 20, 2018
April 18, 2018
$2 / June 2018
February 1, 2018 -
March 17, 2018
19
August 21, 2018
March 17, 2018
August 21, 2018
$3 / Q4 2018
7
November 8, 2018
March 17, 2018
November 8, 2018
$1 / Q4 2018
February 1, 2018 -
March 17, 2018
$20 / September
2018
ACE - New Jersey
(Electric)
__________
(a) On May 17, 2018, the PAPUC issued an order directing Pennsylvania utility companies without an existing base rate case, including PECO’s gas distribution business, to
start passing back the savings from January 1, 2018 onward through a negative surcharge mechanism to be effective on July 1, 2018. Pursuant to that order, PECO filed
a negative surcharge mechanism and began on July 1, 2018, to return the estimated annual 2018 tax savings above to its natural gas distribution customers.
September 8, 2018
August 29, 2018
August 29, 2018
$6 / Q4 2018
23
$
January 1, 2018 -
June 30, 2018
As discussed above, ComEd’s, BGE’s, Pepco’s, DPL’s and ACE’s transmission formula rates currently do not provide for the pass back or recovery of income
tax-related regulatory liabilities or assets, including those established upon enactment of the TCJA. On December 13, 2016 (as amended on March 13, 2017)
and on February 23, 2018 (as amended on July 9, 2018), BGE and ComEd, Pepco, DPL and ACE, respectively, each filed with FERC to revise their
transmission formula rate mechanisms to provide for pass back and recovery of transmission-related income tax-related regulatory liabilities and assets,
including those established upon enactment of the TCJA. See discussion below for additional information regarding these filings.
See Note 14 - Income Taxes for additional information on Corporate Tax Reform.
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Other State Regulatory Matters
Illinois Regulatory Matters
Combined Notes to Consolidated Financial Statements - (Continued)
(Dollars in millions, except per share data unless otherwise noted)
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 cumulative persisting annual MWh savings
falls short of or exceeds specified percentage benchmarks of its annual incremental savings goal. ComEd is required to file an update to its energy efficiency
formula rate on or before June 1 st 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 2018, the ICC approved the following total increases in ComEd's requested energy efficiency revenue requirement:
Filing Date
June 1, 2018
$
Requested Revenue
Requirement Increase
Approved Revenue Requirement
Increase
Approved ROE
Approval Date
39 $
42 (a)
8.69%
December 4, 2018
Rate Effective Date
January 1, 2019
_________
(a) ComEd’s 2018 approved revenue requirement above reflects an increase of $41 million for the initial year revenue requirement for 2018 and 2019 and an increase of $1
million related to the annual reconciliation for 2017. The revenue requirement for 2018 and 2019 and the annual reconciliation for 2017 provides for a weighted average
debt and equity return on distribution rate base of 6.52% inclusive of an allowed ROE of 8.69% , 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
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 Commission 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. The Commission ruled that the level of the administrative adjustment will be determined in BGE’s next rate case.
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. BGE cannot predict the outcome of this appeal.
Smart Meter and Smart Grid Investments (Exelon and BGE). In August 2010, the MDPSC approved a comprehensive smart grid initiative for BGE that
included the planned installation of 2 million residential and commercial electric and natural gas smart meters at an expected total cost of $480 million of which
$200 million was funded by SGIG. The MDPSC’s approval ordered BGE to defer the associated incremental costs, depreciation and amortization, and an
appropriate return, in a regulatory asset until such time as a cost-effective advanced metering system is implemented. See AMI programs in the Regulatory
Assets and Liabilities section below for additional information.
As part of the 2015 electric and natural gas distribution rate case filed on November 6, 2015, BGE sought recovery of its smart grid initiative costs, supported by
evidence demonstrating that BGE had, in fact, implemented a cost-
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Combined Notes to Consolidated Financial Statements - (Continued)
(Dollars in millions, except per share data unless otherwise noted)
beneficial advanced metering system. On June 3, 2016, the MDPSC issued an order concluding that the smart grid initiative overall is cost beneficial to its
customers. However, the June 3 rd order contained several cost disallowances and adjustments including disallowances of certain program and meter installation
costs and denial of recovery of any return on unrecovered costs for non-AMI meters replaced under the program. BGE and the residential consumer advocate
subsequently both filed a petition for rehearing of the June 3 rd order. On July 29, 2016, the MDPSC issued an order on the petitions for rehearing that reversed
certain of its prior cost disallowances and adjustments related to the smart grid initiative.
As a combined result of the MDPSC orders in BGE's 2015 electric and natural gas distribution base rate case, BGE recorded a $52 million charge in June 2016
to Operating and maintenance expense in Exelon’s and BGE’s Consolidated Statements of Operations and Comprehensive Income reducing certain regulatory
assets and other long-lived assets and reclassified $56 million of legacy meter costs from Property, plant and equipment, net to Regulatory assets in Exelon's
and BGE's Consolidated Balance Sheets. In BGE’s 2018 natural gas distribution base rate case, the MDPSC allowed BGE to recover the gas portion of the
post-test year regulatory asset, including a return thereon, over three years. The electric portion of the same regulatory asset will be addressed in BGE’s next
electric distribution base rate case.
The Maryland Strategic Infrastructure Development and Enhancement Program (Exelon and BGE). In 2013, legislation in Maryland was signed into law to
establish a mechanism, separate from base rate proceedings, for gas companies to promptly recover reasonable and prudent costs of eligible infrastructure
replacement projects incurred after June 1, 2013. The monthly surcharge and infrastructure replacement costs must be approved by the MDPSC and are subject
to a cap and require an annual true-up of the surcharge revenues against actual expenditures. Investment levels in excess of the cap would be recoverable in a
subsequent gas base rate proceeding at which time all costs for the infrastructure replacement projects would be rolled into gas distribution base rates.
Irrespective of the cap, BGE is required to file a gas rate case every five years under this legislation.
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 will be effective in rates beginning in January 2019. The new five-year plan calls for capital expenditures over the 2019-2023 timeframe of $732
million, with an associated revenue requirement of $200 million.
District of Columbia Regulatory Matters
District of Columbia Power Line Undergrounding Initiative (Exelon, PHI and Pepco). The District of Columbia government enacted on a permanent basis
(effective July 11, 2017) legislation to amend the Electric Company Infrastructure Improvement Financing Act of 2014 (as amended) (the Infrastructure
Improvement Financing Act) to authorize the District of Columbia Power Line Undergrounding (DC PLUG) initiative, 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.
The $250 million of project costs funded by Pepco will earn a return and be recovered through a volumetric surcharge on the electric bill of Pepco's customers in
the District of Columbia.
The $250 million of project costs funded by the District of Columbia will come from two sources. Project costs of $187.5 million will be funded through a charge
assessed on Pepco by the District of Columbia; Pepco will recover this charge from customers through a volumetric distribution rider. The remaining costs up to
$62.5 million are to be funded by the existing capital projects program of the District Department of Transportation (DDOT). Ownership and responsibility for the
operation and maintenance of assets funded by the District of Columbia will be transferred to Pepco for a nominal amount upon completion, and Pepco will not
recover or earn a return on the cost of these assets.
In accordance with the Infrastructure Improvement Financing Act, Pepco filed an application for approval of the first two-year plan in the DC PLUG initiative (the
First Biennial Plan) on July 3, 2017. Pepco will then be required to make two additional applications. On November 9, 2017, the DCPSC issued an order
approving the First Biennial Plan and the application for a financing order. Pursuant to that order, Pepco is obligated to pay $187.5 million to the District of
Columbia over the six-year project term, of which it expects to pay $30 million in 2019. Pepco recorded
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Combined Notes to Consolidated Financial Statements - (Continued)
(Dollars in millions, except per share data unless otherwise noted)
an obligation and offsetting regulatory asset in November. Rates for the DC PLUG initiative went into effect on February 7, 2018.
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. ACE currently expects a decision in this matter in the second quarter of 2019 but cannot predict if the NJBPU will approve the application as filed.
New Jersey Consolidated Tax Adjustment (Exelon, PHI and ACE). The Consolidated Tax Adjustment (CTA) is a ratemaking policy that requires utilities that
are part of a consolidated tax group to share with customers the tax benefits that came from losses at unregulated affiliates through a reduction in rate base.
After opening a generic proceeding to review the policy, in 2014, the NJBPU issued a decision which retained the CTA, but in a modified format that significantly
reduced the impact of the CTA to ACE. On September 18, 2017, the Appellate Division of the Superior Court of New Jersey reversed the NJBPU’s decision in
adopting the revised CTA policy and held that NJBPU’s actions related to the CTA constituted a rulemaking that should have been undertaken pursuant to the
requirements of the Administrative Procedures Act. The Court did not address the merits of the CTA methodology itself. The NJBPU issued a proposed rule for
comment, consistent with the requirements of the Administrative Procedures Act. On January 17, 2019, the NJBPU adopted the proposed CTA regulations,
which do not have a material impact on ACE. The CTA regulations will be sent to the Office of Administrative Law for publication in the New Jersey Register,
which is expected on or before March 4, 2019.
New Jersey Clean Energy Legislation (Exelon and ACE). On May 23, 2018, the Governor of New Jersey signed new legislation, effective immediately, that
established and modified New Jersey’s clean energy and energy efficiency programs and solar and renewable energy portfolio standards. The new legislation
expands the state's renewable portfolio standard to require that 50% of electric generation sold be from renewable energy sources by 2030; modifies the New
Jersey solar renewable energy portfolio standard to require that 5.1% of electric generation sold in New Jersey be from solar electric power by 2021; lowers the
solar alternative compliance payment amount starting in 2019 and requires the NJBPU to adopt rules to replace the current solar renewable energy credit
program; and requires the NJBPU to increase its offshore wind energy credit program to 3,500 MW. The new legislation further imposes an energy efficiency
standard that each electric public utility will be required to reduce annual usage by 2% and provides for utilities to annually file for recovery of the costs of the
programs, including the revenue impact of sales losses resulting from the programs. The NJBPU is required to initiate a study to determine the savings targets
for each public utility, to adopt other rules regarding the programs, and to approve energy efficiency and peak demand reduction programs for each utility. The
new legislation also requires the NJBPU to conduct an energy storage analysis including the potential costs and benefits and to initiate a proceeding to establish
a goal of achieving 2,000 MW of energy storage by 2030; requires the utilities to conduct a study on voltage optimization on their distribution system; and
requires the NJBPU to establish a community solar program to permit customers to participate in a solar project that is not located on the customer’s property
which the NJBPU issued regulations on January 17, 2019.
On the same day, the Governor of New Jersey also signed new legislation, effective immediately, that will establish a ZEC program providing 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, will be authorized to collect from
retail distribution customers through a non-bypassable charge all costs associated with the utility’s procurement of the ZECs. 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 (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
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Combined Notes to Consolidated Financial Statements - (Continued)
(Dollars in millions, except per share data unless otherwise noted)
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. FERC’s rejection order focused on the lack of timeliness of BGE’s request to recover amounts that would have been
previously amortized but indicated that ongoing recovery of certain transmission-related income tax regulatory assets would provide for a more accurate revenue
requirement. Based on FERC’s order, management of each company concluded that the portion of the total transmission-related income tax regulatory assets
that would have been previously amortized and recovered through rates had the transmission formula rate provided for such recovery was no longer probable of
recovery. As a result, Exelon, ComEd, BGE, PHI, Pepco, DPL and ACE recorded the following charges 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.
Similar regulatory assets and liabilities at PECO are not subject to the same FERC transmission rate recovery formula and, thus, are not impacted by BGE’s
November 16, 2017 FERC order. See above for additional information regarding PECO's transmission formula rate filing.
Exelon
ComEd
BGE
PHI
Pepco
DPL
ACE
$
For the year ended December 31, 2017
35
3
5
27
14
6
7
On December 18, 2017, BGE filed for clarification and rehearing of FERC’s order, still seeking full recovery of its existing transmission-related income tax
regulatory asset amounts, including those amounts that would have been previously amortized and recovered through rates had the transmission formula rate
provided for such recovery. On February 27, 2018 (and updated on March 26, 2018), BGE submitted a letter to FERC advising that the lower federal corporate
income tax rate effective January 1, 2018 provided for in the TCJA will be reflected in BGE’s annual formula rate update effective June 1, 2018, but that the
deferred income tax benefits will not be passed back to customers unless BGE’s formula rate is revised to provide for pass back and recovery of transmission-
related income tax-related regulatory liabilities and assets.
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 facilitate passing back to customers ongoing annual TCJA tax savings and 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, again 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. The orders did not address the remittance of TCJA transmission-related income tax regulatory liabilities, but rather referenced FERC’s
separate Notice of Inquiry of such amounts issued on March 15, 2018.
On October 1, 2018, ComEd, BGE, Pepco, DPL, and ACE submitted new 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. FERC issued deficiency letters requesting additional
information on November 21, 2018 and January 28, 2019. ComEd, BGE, Pepco, DPL, and ACE responded to the November 21, 2018 deficiency letter on
November 29, 2018 but cannot predict the outcome of these FERC 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 up to
approximately $76 million , $51 million , $15 million , $10 million , $3 million , $5 million and $2 million , respectively, as of December 31, 2018.
290
Table of Contents
Combined Notes to Consolidated Financial Statements - (Continued)
(Dollars in millions, except per share data unless otherwise noted)
On October 9, 2018, ComEd, Pepco, DPL, and ACE sought rehearing of FERC's September 7, 2018 order, still seeking full recovery of their existing
transmission-related income tax regulatory asset amounts, including those amounts that would have been previously amortized and recovered through rates had
the transmission formula rate provided for such recovery. ComEd, Pepco, DPL, and ACE cannot predict the outcome of this rehearing request. 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.
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 and directed PJM to adjust wholesale transmission rates within 30 days. Pursuant to the
order, similar charges for the period January 1, 2016 through June 30, 2018 will 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 expect
to refund or recover these settlement amounts through prospective electric distribution customer rates. On July 2, 2018, several parties filed petitions for
rehearing or clarification.
Pursuant to the FERC approval of the settlement and the expected refund or recovery of the associated amounts from electric distribution customers, in the
second quarter of 2018 and as adjusted in the third quarter of 2018, the Utility Registrants recorded the following payables to/receivables from PJM and related
regulatory assets/liabilities. 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
291
Table of Contents
Regulatory Assets and Liabilities
Combined Notes to Consolidated Financial Statements - (Continued)
(Dollars in millions, except per share data unless otherwise noted)
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.
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, 2018 and December 31, 2017 :
December 31, 2018
Regulatory assets
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
AMI programs - Post-test year costs
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
202
328
32
—
—
—
136
—
158
158
81
472
—
—
79
309
249
—
6
—
—
—
—
—
—
—
81
472
702
561
118
326
249
193
41
545
42
59
50
564
159
41
303
9,459
1,222
—
404
—
24
—
—
—
—
—
—
22
17
—
49
—
1
—
—
—
—
—
—
—
—
113
48
32
—
—
—
—
—
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
57
50
564
159
41
162
2,801
489
18
57
—
158
159
9
79
913
270
—
—
39
30
—
—
—
—
—
—
—
—
—
—
14
67
11
—
—
97
—
4
28
290
59
110
1,600
293
24
541
81
Total noncurrent regulatory assets
$
8,237 $
1,307 $
460 $
398 $
2,312 $
643 $
231 $
292
—
—
—
—
—
—
—
—
—
—
—
—
—
—
9
7
—
10
—
50
309
—
28
13
426
40
386
Table of Contents
Combined Notes to Consolidated Financial Statements - (Continued)
(Dollars in millions, except per share data unless otherwise noted)
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
10,203
644
2,217
1,368
137
227
6,343
293
389
—
132
75
596
175
—
52
6
79
1,269
77
—
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 $
421 $
1,192
$
1,864 $
822 $
606 $
293
Table of Contents
December 31, 2017
Regulatory assets
Combined Notes to Consolidated Financial Statements - (Continued)
(Dollars in millions, except per share data unless otherwise noted)
Exelon
ComEd
PECO
BGE
PHI
Pepco
DPL
ACE
Pension and other postretirement benefits $
2,455 $
— $
— $
— $
— $
— $
— $
Pension and other postretirement benefits
- Merger related
Deferred income taxes
AMI programs - Deployment costs
AMI programs - Legacy meters
AMI programs - Post-test year costs
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
1,393
306
385
223
32
—
—
—
155
—
186
186
58
166
—
—
73
273
256
—
6
—
—
—
—
—
—
—
58
166
758
750
109
295
258
47
35
596
45
55
79
529
190
27
311
9,288
1,267
—
297
—
36
—
—
—
—
—
—
22
22
—
1
—
1
—
—
—
—
—
—
—
—
129
53
32
—
—
—
—
—
14
—
—
16
7
—
9
101
134
—
—
—
—
619
750
—
—
2
30
22
—
9
58
100
—
—
—
—
—
—
—
—
—
8
3
285
310
229
6
14
—
—
—
—
15
571
174
39
41
79
529
190
27
165
3,047
554
20
38
—
150
190
7
79
891
213
—
—
43
34
—
—
—
—
—
—
—
—
1
7
8
81
10
3
—
93
—
5
29
314
69
106
1,279
225
31
410
29
Total noncurrent regulatory assets
$
8,021 $
1,054 $
381 $
397
$
2,493 $
678 $
245 $
294
—
—
—
—
—
—
—
—
—
—
—
—
—
1
15
11
—
9
—
79
286
—
15
14
430
71
359
Table of Contents
Combined Notes to Consolidated Financial Statements - (Continued)
(Dollars in millions, except per share data unless otherwise noted)
December 31, 2017
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
$
5,241 $
2,479 $
— $
1,032 $
1,730 $
809 $
510 $
411
3,064
1,573
111
399
10,388
523
2,528
1,338
47
185
6,577
249
536
—
60
94
690
141
—
105
—
26
1,163
62
—
130
4
64
1,928
56
—
20
—
3
832
3
—
110
1
14
635
42
—
—
3
8
422
11
411
Total noncurrent regulatory liabilities
$
9,865 $
6,328 $
549 $
1,101
$
1,872 $
829 $
593 $
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 16 – Retirement Benefits for additional information. The
capitalized non–service cost components are amortized over
the lives of the underlying assets.
295
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 16 –
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 - (Continued)
(Dollars in millions, except per share data unless otherwise noted)
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.
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.
BGE - 2026
No
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.
Pepco - 2027
Yes
DPL - 2030
ComEd - 2028
PECO - 2020
AMI Programs - Legacy Meters Early retirement costs of legacy meters.
BGE - 2028
Pepco - 2027
DPL - 2030
ComEd, Pepco (District of
Columbia), DPL (Delaware) -
Yes
PECO, BGE, Pepco
(Maryland), DPL (Maryland) -
No
AMI Programs - Post-test year
incremental costs
Post-test year incremental program deployment costs of smart
meters. As of December 31, 2018 and 2017, the portion of
BGE's regulatory asset related to gas and electric costs was
$10 million and $22 million, respectively.
BGE (gas) - 2021
BGE (gas) - Yes
BGE (electric) - Not currently
being recovered.
BGE (electric) - No
Electric distribution formula
rate annual reconciliations
Electric distribution formula
rate significant one-time events
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 1 st .
2020
Under-recoveries of electric distribution service costs related to
significant one-time events (e.g., storm costs), which are
recovered over 5 years from date of the event.
2022
Yes
Yes
296
Table of Contents
Combined Notes to Consolidated Financial Statements - (Continued)
(Dollars in millions, except per share data unless otherwise noted)
Line Item
Description
End Date of Remaining
Recovery/Refund Period
Return
Energy Efficiency Costs
Fair Value of Long-Term Debt
Costs recovered through the energy efficiency formula rate
tariff and the reconciliation of the difference of the revenue
requirement in effect for the prior year and the revenue
requirement based on actual prior year costs. Deferred energy
efficiency costs are recovered over the weighted average
useful life of the related energy measure.
Represents the difference between the carrying value and fair
value of long-term debt of PHI and BGE of $569 million and
$133 million, respectively, as of December 30, 2018 and $619
million and $139 million, respectively, as of December 30,
2017, as of the PHI and Constellation merger dates.
2029
BGE - 2043
PHI - 2045
Fair Value of PHI’s
Unamortized Energy Contracts
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 22 -
Commitments and
Contingencies for additional
information.
Yes
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 1 st .
2020
Yes
297
Table of Contents
Combined Notes to Consolidated Financial Statements - (Continued)
(Dollars in millions, except per share data unless otherwise noted)
Line Item
Description
End Date of Remaining
Recovery/Refund Period
Return
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 - 2023
BGE, Pepco, DPL, ACE - Yes
PECO - Yes on capital
investment recovered through
this mechanism
Merger Integration Costs
Integration costs to achieve distribution synergies related to the
Constellation merger and PHI acquisition. Costs for Pepco
(Maryland) and Pepco (District of Columbia) were $9 million
each as of December 31, 2018 and $11 million and $9 million,
respectively, as of December 31, 2017.
Pepco, DPL - 2033
BGE - 2021
Pepco - 2021
DPL- 2023
ACE - Not currently being
recovered.
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 - 2019
BGE, Pepco, DPL- No
Securitized Stranded Costs
Represents certain stranded costs associated with ACE's
former electricity generation business.
2022
Removal Costs
For 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.
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
DC PLUG Charge
Costs associated with the DC Plug Initiative. See District of
Columbia Regulatory Matters discussion above.
Deferred Storm Costs
Nuclear Decommissioning
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 15 - Asset Retirement Obligations for
additional information
298
2019 - $30M
$127 million to be determined
based on future biennial plans
filed with the DCPSC.
Portion of asset funded by
Pepco-Yes
Pepco - 2022
DPL - 2023
ACE - 2020
Pepco, DPL - Yes
ACE - No
Not currently being refunded.
No
Table of Contents
Combined Notes to Consolidated Financial Statements - (Continued)
(Dollars in millions, except per share data unless otherwise noted)
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, 2018
$
65 $
8 $
— $
49 $
8 $
5 $
3 $
—
Exelon
ComEd (a)
PECO
BGE (b)
PHI
Pepco (c)
DPL (c)
ACE
$
December 31, 2017
__________
(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
—
53 $
10 $
69 $
— $
6 $
6 $
4 $
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 required 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. For the year ended December 31,
2018, Generation recognized revenue of $373 million , of which $150 million 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. Exelon intervened and filed motions to dismiss in
both lawsuits, which were granted by the district court. On September 13, 2018, the U.S. Circuit Court of Appeals for the Seventh Circuit affirmed the lower
court's dismissal of both lawsuits. The U.S. Circuit Court of Appeals for the Seventh Circuit panel denied the plaintiffs’ request for rehearing on October 9, 2018.
On January 7, 2019, plaintiffs filed a petition seeking Supreme Court review of the case.
New Jersey Regulatory Matters
New Jersey Clean Energy Legislation . On May 23, 2018, the Governor of New Jersey signed new legislation, effective immediately, that will establish a ZEC
program providing 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,
299
Table of Contents
Combined Notes to Consolidated Financial Statements - (Continued)
(Dollars in millions, except per share data unless otherwise noted)
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 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, the 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 the same day, Generation filed certain Supplemental Information with the NJBPU providing proprietary
information that was requested in the application but which could not be shared with PSEG. The NJBPU must complete its processes for determining eligibility
for, and participation in, the ZEC program by April 18, 2019. See Note 8 - Early Plant Retirements for additional information on New Jersey’s ZEC program
potential impacts to PSEG’s Salem nuclear plant.
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 included a Tier 3
ZEC program targeted at preserving the environmental attributes of zero-emissions nuclear-powered generating facilities that met specific criteria demonstrating
public necessity, 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.
Generation is currently recognizing revenue for the sale of New York ZECs in the month they are generated and for the years ended December 31, 2018 and
2017 , Generation has recognized revenue of $438 million and $311 million , respectively.
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. On December 9, 2016, several parties filed motions to intervene in the case and to dismiss the lawsuit. On July
25, 2017, the court granted the motions to dismiss. 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 Supreme Court review of the case.
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. Generation, CENG and the state's answers and briefs were filed on March 30, 2018. On December 17, 2018, plaintiffs filed a reply brief
introducing new arguments and new evidence. The State of New York filed a motion to strike on December 28, 2018. On January 4, 2019, Generation and
CENG filed a motion to strike the new arguments and new evidence. After briefing is completed, the court will decide whether or not to set the case for hearing.
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Combined Notes to Consolidated Financial Statements - (Continued)
(Dollars in millions, except per share data unless otherwise noted)
Other legal challenges remain possible, the outcomes of which remain uncertain. See Note 8 - Early Plant Retirements for additional information related to Ginna
and Nine Mile Point, and Note 5 - 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 Nuclear Power Plant
(Ginna) regarding the possible retirement of Ginna, the NYPSC directed Ginna and Rochester Gas & 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 8 - Early Plant Retirements for additional information regarding the
impacts of a decision to early retire a nuclear plant.
Federal Regulatory Matters
Operating License Renewals
Conowingo Hydroelectric Project . On August 29, 2012, Generation submitted a hydroelectric license application to FERC for a 46-year 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) with Maryland Department of the Environment (MDE) for Conowingo, Generation continues to work 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 resolving all fish
passage issues between the parties. The financial impact of the Settlement Agreement is estimated to be $3 million to $7 million per year, on average, over the
life of the new license, including both capital and operating costs. The actual timing and amount of these costs are not currently fixed and may vary significantly
from year to year throughout the life of the new license.
On April 27, 2018, the 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 violating MDE regulations, state, federal, and constitutional law. Generation also requested that FERC defer
action on the federal license while these significant state and federal law issues are pending. On July 9, 2018, MDE filed a motion to dismiss Generation's
complaint in state court, which was granted without prejudice on October 9, 2018. The court found MDE's Certification was not a "final decision" of Exelon's
rights and because Exelon's motion for reconsideration remains pending, as does its administrative appeal of the 401 Certification, there was no final
administrative decision for the court to review at this time. On November 5, 2018, Exelon appealed the Maryland Circuit Court's dismissal of Exelon's state
complaint. Exelon continues to challenge the 401 Certification through the administrative process and in federal court. Exelon and Generation cannot predict the
final outcome or its financial impact, if any, on Exelon or Generation.
As of December 31, 2018, $37 million of direct costs associated with Conowingo licensing efforts have been capitalized.
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 process to take
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Combined Notes to Consolidated Financial Statements - (Continued)
(Dollars in millions, except per share data unless otherwise noted)
approximately 2 years from the application submission until completion of the NRC’s review process. Peach Bottom Units 2 and 3 are currently licensed to
operate through 2033 and 2034, respectively.
PJM Transmission Rate Design . Refer to Other Federal Regulatory Matters above for additional information.
5. Mergers, Acquisitions and Dispositions (Exelon, Generation and PHI)
Acquisition of FirstEnergy Solutions Load Business (Exelon and Generation)
On July 9, 2018, Generation entered into an Asset Purchase Agreement (the Purchase Agreement) with FirstEnergy Solutions Corporation (FirstEnergy).
Pursuant to the Purchase Agreement, FirstEnergy agreed to assign all of its retail electricity and wholesale load serving contracts and certain other related
commodity contracts to Generation for an all cash purchase price of $140 million . The closing of the transaction was subject to certain conditions including the
approval of the Purchase Agreement by the United States Bankruptcy Court for the Northern District of Ohio (Bankruptcy Court). At FirstEnergy's request,
Bankruptcy Court's review of the transaction was delayed on six occasions, and Generation disputed these delays with the Bankruptcy Court. On January 23,
2019 the Bankruptcy Court approved an order that stipulated FirstEnergy's termination of the Purchase Agreement, effective January 22, 2019. The termination
order provided for Generation to receive a refund of its escrow deposit, payment of a termination fee and reimbursement of transaction expenses, all of which
were immaterial.
Acquisition of James A. FitzPatrick Nuclear Generating Station (Exelon and Generation)
On March 31, 2017, Generation acquired the 842 MW 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 acquisition agreements, Generation provided nuclear fuel and reimbursed Entergy for
incremental costs to prepare for and conduct a plant refueling outage; and Generation reimbursed Entergy for incremental costs to operate and maintain the
plant for the period after the refueling outage through the acquisition closing date. These reimbursements covered costs that Entergy otherwise would have
avoided had it shutdown the plant as originally intended in January 2017. The amounts reimbursed by Generation were offset by FitzPatrick's electricity and
capacity sales revenues for this same post-outage period. 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.
The fair values of FitzPatrick’s assets and liabilities were determined based on significant estimates and assumptions that are judgmental in nature, including
projected future cash flows (including timing), discount rates reflecting risk inherent in the future cash flows and future power and fuel market prices.
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. See
Note 15 — Asset Retirement Obligations and Note 16 — Retirement Benefits for additional information regarding the FitzPatrick decommissioning ARO and
pension and OPEB updates.
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Combined Notes to Consolidated Financial Statements - (Continued)
(Dollars in millions, except per share data unless otherwise noted)
The following table summarizes the final acquisition-date fair value of the consideration transferred and the assets and liabilities assumed for the FitzPatrick
acquisition by Generation:
Cash paid for purchase price
Cash paid for net cost reimbursement
Nuclear fuel transfer
Total consideration transferred
Identifiable assets acquired and liabilities assumed
Current assets
Property, plant and equipment
Nuclear decommissioning trust funds
Other assets (a)
Total assets
Current liabilities
Nuclear decommissioning ARO
Pension and OPEB obligations
Deferred income taxes
Spent nuclear fuel obligation
Other liabilities
Total liabilities
Total net identifiable assets, at fair value
Bargain purchase gain (after-tax)
$
$
$
$
$
$
$
$
110
125
54
289
60
298
807
114
1,279
6
444
33
149
110
15
757
522
233
_________
(a)
Includes a $110 million asset associated with a contractual right to reimbursement from the New York Power Authority (NYPA), a prior owner of FitzPatrick, associated
with the DOE one-time fee obligation. See Note 22 - Commitments and Contingencies for additional information regarding SNF obligations to the DOE.
Exelon and Generation incurred $57 million of merger and integration related costs to 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. Exelon and
Generation did not incur any merger and integration costs related to FitzPatrick for the year ended December 31, 2018 .
Acquisition of ConEdison Solutions (Exelon and Generation)
On September 1, 2016, Generation acquired the competitive retail electricity and natural gas business of Consolidated Edison Solutions, Inc. (ConEdison
Solutions), a subsidiary of Consolidated Edison, Inc. 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 Solutions are excluded from the transaction.
The purchase price of $257 million equaled the estimated fair value of the net assets acquired and the liabilities assumed and, therefore, no goodwill or bargain
purchase was recorded as of the acquisition date.
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Combined Notes to Consolidated Financial Statements - (Continued)
(Dollars in millions, except per share data unless otherwise noted)
Merger with Pepco Holdings, Inc. (Exelon)
Description of Transaction
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 Pepco Holdings, Inc. (PHI), for a total purchase price consideration of approximately $7.1 billion . As a result of the merger, Merger
Sub was merged into PHI (the PHI Merger) with PHI surviving as a wholly owned subsidiary of Exelon and Exelon Energy Delivery Company, LLC (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.
Regulatory Matters
Approval of the merger in Delaware, New Jersey, Maryland and the District of Columbia was conditioned upon Exelon and PHI agreeing to certain commitments
including where applicable: customer rate credits, funding for energy efficiency and delivery system modernization programs, a green sustainability fund,
workforce development initiatives, charitable contributions, renewable generation and other required commitments. In addition, the orders approving the merger
in Delaware, New Jersey and Maryland include a “most favored nation” provision which, generally, requires allocation of merger benefits proportionally across all
the jurisdictions.
Total nominal cost of commitments was $513 million excluding renewable generation commitments (approximately $444 million on a net present value basis
amount, excluding renewable generation commitments and charitable contributions).
During the fourth quarter of 2018, Exelon finalized the application of $5 million funding for residential and non-residential customers in the DPL Maryland service
territory. This resulted in an adjustment to merger commitment costs recorded at Exelon Corporate and DPL. Exelon Corporate recorded a decrease of $5
million and DPL recorded an increase of $5 million in Operating and maintenance expense.
The following amounts represent total commitment costs for Exelon, PHI, Pepco, DPL and ACE that have been recorded since the merger date:
Description
Rate credits
Energy efficiency
Charitable contributions
Delivery system modernization
Green sustainability fund
Workforce development
Other
Total commitments
Remaining commitments as of December 31,
2018
Successor
Expected Payment Period
Exelon
PHI
Pepco
DPL
ACE
2016 - 2021
2016 - 2021
2016 - 2026
Q2 2017
Q2 2017
2016 - 2020
$
259 $
117
50
22
14
17
29
264 $
91 $
72 $
101
—
50
—
—
—
6
—
28
—
—
—
1
—
12
—
—
—
5
—
10
—
—
—
—
$
$
508 $
320 $
120 $
89 $
111
128 $
92 $
73 $
12 $
7
Pursuant to the orders approving the merger, Exelon made $73 million , $46 million and $49 million of equity contributions to Pepco, DPL and ACE, respectively,
in the second quarter of 2016 to fund the after-tax amounts of the customer bill credit and the customer base rate credit commitments.
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
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Combined Notes to Consolidated Financial Statements - (Continued)
(Dollars in millions, except per share data unless otherwise noted)
primarily capital in nature, will be recognized as incurred and recorded on Exelon's and Generation's financial statements. As of December 31, 2018, 27 MWs
were developed and Exelon and Generation have incurred costs of $83 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 is pending review and
approval with the DPSC. The third and final 40 MW wind REC tranche will be conducted in 2022.
Pursuant to the various jurisdictions' merger approval conditions, over specified periods Pepco, DPL and ACE are not permitted to reduce employment levels
due to involuntary attrition associated with the merger integration process and have made other commitments regarding hiring and relocation of positions.
In July 2015, the OPC, Public Citizen, Inc., the Sierra Club and the Chesapeake Climate Action Network (CCAN) filed motions to stay the MDPSC order
approving the merger. The Circuit Court judge issued an order denying the motions for stay on August 12, 2015. On January 8, 2016, the Circuit Court judge
affirmed the MDPSC’s order approving the merger and denied the petitions for judicial review filed by the OPC, the Sierra Club, CCAN and Public Citizen, Inc.
On January 19, 2016, the OPC filed a notice of appeal to the Maryland Court of Special Appeals, and on January 21, the Sierra Club and CCAN filed notices of
appeal. On January 27, 2017, the Maryland Court of Special Appeals affirmed the Circuit Court's judgment that the MDPSC did not err in approving the merger.
The OPC and Sierra Club filed petitions seeking further review in the Maryland Court of Appeals, which is the highest court in Maryland. On August 29, 2018, the
Maryland Court of Appeals affirmed the MDPSC's May 2015 Order approving the merger of Exelon and PHI.
Between March 25, 2016 and April 22, 2016, various parties filed motions with the DCPSC to reconsider its March 23, 2016 order approving the merger. On
June 17, 2016, the DCPSC denied all motions. In August 2016, the District Legal Entity of Columbia Office of People’s Counsel, the District of Columbia
Government, and Public Citizen jointly with DC Sun each filed petitions for judicial review of the DCPSC’s March 23, 2016 order with the District of Columbia
Court of Appeals. On July 20, 2017, the Court issued an opinion rejecting all of appellants’ arguments and affirming the Commission’s decision approving the
merger.
Accounting for the Merger Transaction
The total purchase price consideration for the PHI merger was approximately $7.1 billion . The excess of the purchase price over the estimated fair value of the
assets acquired and the liabilities assumed totaled $4 billion , which was recognized as goodwill by PHI and Exelon at the merger date, reflecting the value
associated with enhancing Exelon's regulated utility portfolio of businesses, including the ability to leverage experience and best practices across the utilities and
the opportunities for synergies. None of this goodwill is expected to be tax deductible. For purposes of future required impairment assessments, the goodwill has
been assigned to PHI's reportable units Pepco, DPL and ACE. See Note 10 - Intangible Assets for additional information.
Immediately following closing of the merger, $235 million of net assets associated with PHI's unregulated business interests were distributed by PHI to Exelon.
Exelon contributed $163 million of such net assets to Generation.
Rates charged to customers are established by a regulator to provide for recovery of costs and a fair return on invested capital, or rate base, generally measured
at historical cost. Historical cost information therefore is the most relevant presentation for the financial statements of PHI’s rate regulated utility subsidiary
registrants, Pepco, DPL and ACE. As such, Exelon and PHI did not push-down the application of acquisition accounting to PHI's utility registrants, and therefore
the financial statements of Pepco, DPL and ACE do not reflect the revaluation of any assets and liabilities.
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Combined Notes to Consolidated Financial Statements - (Continued)
(Dollars in millions, except per share data unless otherwise noted)
The current impact of PHI, including its unregulated businesses, in Exelon's Consolidated Statements of Operations and Comprehensive Income includes
Operating revenues and Net Income (Loss) as follows:
Operating Revenues
Net Income (Loss)
For the Years Ended December 31,
2018
2017
2016
4,670
453
4,829
364
3,785
(66)
For the periods ended December 31, 2018 , 2017 and 2016 , the Registrants have recognized costs to achieve the PHI merger as follows:
Acquisition, Integration and Financing Costs (a)
2018
2017
2016
For the Year Ended December 31,
Exelon
Generation
ComEd (b)
PECO
BGE (b)
Pepco (b)
DPL (b)
ACE (b)
$
7 $
5
—
1
1
—
—
—
16 $
22
1
4
4
(6)
(7)
(6)
143
37
(6)
5
(1)
28
20
19
Successor
Predecessor
For the Year Ended December 31,
March 24, 2016 to December 31,
2016
January 1, 2016 to
March 23, 2016
Acquisition, Integration and Financing Costs (a)
PHI (b)
______________
(a) The costs incurred are classified primarily within Operating and maintenance expense in the Registrants’ respective Consolidated Statements of Operations and
Comprehensive Income, with the exception of the financing costs, which are included within Interest expense. Costs do not include merger commitments discussed
above.
69 $
(18) $
— $
29
$
2018
2017
(b) For the year ended December 31, 2017 , includes deferrals of previously incurred integration costs as regulatory assets of $24 million , $8 million , $8 million , and $8
million at PHI, Pepco, DPL and ACE, respectively. For the year ended December 31, 2016 , includes deferrals of previously incurred integration costs as regulatory assets
of $8 million , $6 million , $11 million and $4 million at ComEd, BGE, Pepco and DPL, respectively. For the Successor period March 24, 2016 to December 31, 2016 ,
includes deferrals of previously incurred integration costs as regulatory assets of $16 million at PHI. See Note 4 - Regulatory Matters for additional information.
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Pro-forma Impact of the Merger
Combined Notes to Consolidated Financial Statements - (Continued)
(Dollars in millions, except per share data unless otherwise noted)
The following unaudited pro-forma financial information reflects the consolidated results of operations of Exelon as if the PHI merger had taken place on
January 1, 2015 . The unaudited pro forma information was calculated after applying Exelon’s accounting policies and adjusting PHI’s results to reflect purchase
accounting adjustments.
The unaudited pro-forma financial information has been presented for illustrative purposes only and is not necessarily indicative of results of operations that
would have been achieved had the merger events taken place on the dates indicated, or future consolidated results of operations of the combined company.
Total operating revenues
Net income attributable to common shareholders
Basic earnings per share
Year Ended December 31,
2016 (a)
2015 (b)
32,342 $
1,562
33,823
2,618
1.69 $
2.85
$
$
Diluted earnings per share
______________
(a) The amounts above exclude non-recurring costs directly related to the merger of $680 million and intercompany revenue of $171 million for the year ended December 31,
2.84
1.69
2016 .
(b) The amounts above exclude non-recurring costs directly related to the merger of $92 million and intercompany revenue of $559 million for the year ended December 31,
2015 .
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 the Oyster Creek Generating Station (Oyster Creek) located in Forked River, New Jersey. On
September 17, 2018, Oyster Creek permanently ceased generation operations.
Under the terms of the transaction, Generation will transfer 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. In addition to the assumption of liability for the full decommissioning and ongoing management of spent fuel, other consideration to be
received in the transaction is contingent on several factors, including a requirement that Generation deliver a minimum NDT fund balance at closing, subject to
adjustment for specific terms that include income taxes that would be imposed on any net unrealized built-in gains and certain decommissioning activities to be
performed during the pre-close period after the unit shuts down in the fall of 2018 and prior to the anticipated close of the transaction. 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 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. At December 31, 2018 Generation has $897 million and $777 million of Assets held for sale and
Liabilities held for sale, respectively, for Oyster Creek. Upon remeasurement of the Oyster Creek ARO in 2018, Exelon and Generation recognized an $84
million pre-tax charge to Operating and maintenance expense. See Note 15 - Asset Retirement Obligations for additional information.
Completion of the transaction contemplated by the sale agreement is subject to the satisfaction of several closing conditions, including approval of the license
transfer from the NRC and other regulatory approvals, and the receipt of a private letter ruling from the IRS. Generation currently anticipates satisfaction of the
closing conditions to occur in the second half of 2019.
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Combined Notes to Consolidated Financial Statements - (Continued)
(Dollars in millions, except per share data unless otherwise noted)
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 13 - Debt and Credit Agreements for details regarding the nonrecourse debt associated with EGTP and Note 7 - Impairment of Long-Lived
Assets and Intangibles 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.
Other Asset Dispositions (Exelon, Generation, DPL and Pepco)
In December 2017, Generation entered into an agreement to sell its interest in an electrical contracting business that primarily installs, maintains and repairs
underground and high-voltage cable transmission and distribution systems. As a result, as of December 31, 2017, certain assets and liabilities were classified as
held for sale and included in the Other current assets and Other current liabilities balances in Exelon's and Generation's Consolidated Balance Sheet. On
February 28, 2018, Generation completed the sale of its interest 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. In June 2018, additional proceeds were received,
and a pre-tax gain was recorded within Gain on sales of assets and businesses in Exelon's and Generation's Consolidated Statements of Operations and
Comprehensive Income.
During the fourth quarter of 2016, as part of its continual assessment of growth and development opportunities, Generation reevaluated and in certain instances
terminated or renegotiated certain projects and contracts. As a result, a pre-tax loss of $69 million was recorded within Loss on sales of assets and businesses
and pre-tax impairment charges of $23 million was recorded within Operating and maintenance expense in Exelon’s and Generation’s Consolidated Statements
of Operations and Comprehensive Income.
On June 16, 2016, Generation initiated the sales process of its Upstream business by executing a forbearance agreement with the lenders of the nonrecourse
debt. See Note 13 - Debt and Credit Agreements for additional information. In December 2016, Generation sold substantially all of the Upstream assets for $37
million which resulted in a pre-tax loss on sale of $10 million which is included in Gain (loss) on sales of assets and businesses in Exelon’s and Generation’s
Consolidated Statements of Operations and Comprehensive Income.
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Combined Notes to Consolidated Financial Statements - (Continued)
(Dollars in millions, except per share data unless otherwise noted)
6. Property, Plant and Equipment (All Registrants)
Exelon
The following table presents a summary of property, plant and equipment by asset category as of December 31, 2018 and 2017 :
Asset Category
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
Average
Service Life
(years)
5-90
1-56
5-90
5-75
1-8
N/A
1-50
2018
2017
$
$
53,090 $
29,170
5,530
1,627
5,957
3,377
858
99,609
22,902
76,707 $
49,506
29,019
5,050
1,447
6,420
2,825
999
95,266
21,064
74,202
__________
(a)
(b)
Includes nuclear fuel that is in the fabrication and installation phase of $1,004 million and $1,196 million at December 31, 2018 and 2017 , respectively.
Includes Generation’s buildings under capital lease with a net carrying value of $5 million and $7 million at December 31, 2018 and 2017 , respectively. The original cost
basis of the buildings was $47 million as of both December 31, 2018 and 2017 , and total accumulated amortization was $42 million and $40 million , as of December 31,
2018 and 2017 , respectively. Also includes ComEd’s buildings under capital lease with a net carrying value at both December 31, 2018 and 2017 of $7 million . The
original cost basis of the buildings was $8 million and total accumulated amortization was $1 million as of both December 31, 2018 and 2017 . Includes land held for future
use and non-utility property at ComEd, PECO, BGE, Pepco, DPL and ACE of $39 million , $19 million , $25 million , $61 million , $17 million and $28 million , respectively,
at December 31, 2018 .
Includes accumulated amortization of nuclear fuel in the reactor core at Generation of $2,969 million and $3,159 million as of December 31, 2018 and 2017 , respectively.
(c)
The following table presents the annual depreciation provisions as a percentage of average service life for each asset category.
Average Service Life Percentage by Asset Category
Electric—transmission and distribution
Electric—generation (a)
Gas
2018
2017
2016
2.73%
5.37%
2.07%
2.75%
4.36%
2.10%
2.73%
5.94%
2.17%
Common—electric and gas
__________
(a) See Note 8 — Early Plant Retirements for additional information on the accelerated net depreciation and amortization of Clinton, Quad Cities, Oyster Creek and TMI.
7.05%
6.98%
7.41%
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Generation
Combined Notes to Consolidated Financial Statements - (Continued)
(Dollars in millions, except per share data unless otherwise noted)
The following table presents a summary of property, plant and equipment by asset category as of December 31, 2018 and 2017 :
Asset Category
Electric—generation
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
Average
Service Life
(years)
1-56
1-8
N/A
1-8
2018
2017
$
29,170 $
5,957
997
63
36,187
12,206
$
23,981 $
29,019
6,420
838
57
36,334
11,428
24,906
__________
(a)
(b)
Includes nuclear fuel that is in the fabrication and installation phase of $1,004 million and $1,196 million at December 31, 2018 and 2017 , respectively.
Includes buildings under capital lease with a net carrying value of $5 million and $7 million at December 31, 2018 and 2017 , respectively. The original cost basis of the
buildings was $47 million as of both December 31, 2018 and 2017 , and total accumulated amortization was $42 million and $40 million , as of December 31, 2018 and
2017 , respectively.
Includes accumulated amortization of nuclear fuel in the reactor core of $2,969 million and $3,159 million as of December 31, 2018 and 2017 , respectively.
(c)
The annual depreciation provisions as a percentage of average service life for electric generation assets were 5.37% , 4.36% and 5.94% for the years ended
December 31, 2018 , 2017 and 2016 , respectively. See Note 8 — Early Plant Retirements for additional information on the accelerated depreciation and
amortization of Clinton, Quad Cities, Oyster Creek and TMI.
License Renewals
Depreciation provisions are based on the estimated useful lives of the stations, which reflect the actual renewal of the operating licenses for all of Generation's
operating nuclear generating stations except for TMI and Clinton. As a result, the receipt of license renewals has no material impact in the Consolidated
Statements of Operations and Comprehensive Income. 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. Clinton
depreciation provisions are based on an estimated useful life through 2027 which is the last year of the Illinois Zero Emissions Standard. See Note 4 —
Regulatory Matters for additional information regarding license renewals and the Illinois ZECs and Note 8 — Early Plant Retirements for additional information
on the impacts of expected and potential early plant retirement.
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ComEd
Combined Notes to Consolidated Financial Statements - (Continued)
(Dollars in millions, except per share data unless otherwise noted)
The following table presents a summary of property, plant and equipment by asset category as of December 31, 2018 and 2017 :
Asset Category
Electric—transmission and distribution
Construction work in progress
Other property, plant and equipment (a), (b)
Total property, plant and equipment
Less: accumulated depreciation
Property, plant and equipment, net
Average
Service Life
(years)
5-80
N/A
35-50
2018
2017
$
25,991 $
705
46
26,742
4,684
22,058 $
$
24,423
517
52
24,992
4,269
20,723
__________
(a)
Includes buildings under capital lease with a net carrying value at both December 31, 2018 and 2017 of $7 million . The original cost basis of the buildings was $8 million
and total accumulated amortization was $1 million as of both December 31, 2018 and 2017 .
(b) Represents land held for future use and non-utility property.
The annual depreciation provisions as a percentage of average service life for electric transmission and distribution assets were 2.95% , 2.99% and 3.03% for
the years ended December 31, 2018 , 2017 and 2016 , respectively.
PECO
The following table presents a summary of property, plant and equipment by asset category as of December 31, 2018 and 2017 :
Asset Category
Electric—transmission and distribution
Gas—transportation and distribution
Common—electric and gas
Construction work in progress
Other property, plant and equipment (a)
Total property, plant and equipment
Less: accumulated depreciation
Property, plant and equipment, net
__________
(a) Represents land held for future use and non-utility property.
Average
Service Life
(years)
5-65
5-70
5-50
N/A
50
2018
2017
$
$
8,359 $
2,694
756
343
19
12,171
3,561
8,610 $
7,975
2,504
710
254
21
11,464
3,411
8,053
The following table presents the annual depreciation provisions as a percentage of average service life for each asset category.
Average Service Life Percentage by Asset Category
Electric—transmission and distribution
Gas
Common—electric and gas
2018
2017
2016
2.35%
1.90%
5.44%
2.37%
1.89%
5.47%
2.32%
1.82%
5.11%
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BGE
Combined Notes to Consolidated Financial Statements - (Continued)
(Dollars in millions, except per share data unless otherwise noted)
The following table presents a summary of property, plant and equipment by asset category as of December 31, 2018 and 2017 :
Asset Category
Electric—transmission and distribution
Gas—distribution
Common—electric and gas
Construction work in progress
Other property, plant and equipment (a)
Total property, plant and equipment
Less: accumulated depreciation
Property, plant and equipment, net
Average
Service Life
(years)
5-90
5-90
5-40
N/A
20
2018
2017
$
$
7,951 $
2,630
860
410
25
11,876
3,633
8,243 $
7,464
2,379
771
367
26
11,007
3,405
7,602
__________
(a) Represents plant held for future use and non-utility property.
The following table presents the annual depreciation provisions as a percentage of average service life for each asset category.
Average Service Life Percentage by Asset Category
Electric—transmission and distribution
Gas
Common—electric and gas
PHI
2018
2017
2016
2.61%
2.36%
8.50%
2.58%
2.33%
8.64%
2.56%
2.45%
9.45%
The following table presents a summary of property, plant and equipment by asset category as of December 31, 2018 and 2017 :
Asset Category
Electric—transmission and distribution
Gas—distribution
Common—electric and gas
Construction work in progress
Other property, plant and equipment (a)
Total property, plant and equipment
Less: accumulated depreciation
Property, plant and equipment, net
__________
(a) Represents plant held for future use and non-utility property.
312
Average
Service Life
(years)
5-75
5-75
5-75
N/A
3-43
2018
2017
$
12,664 $
11,517
486
126
912
99
14,287
841
13,446
$
449
82
835
102
12,985
487
12,498
$
Table of Contents
Combined Notes to Consolidated Financial Statements - (Continued)
(Dollars in millions, except per share data unless otherwise noted)
The following table presents the annual depreciation provisions as a percentage of average service life for each asset category.
Average Service Life Percentage by Asset Category
Electric—transmission and distribution
Gas
Common—electric and gas
Pepco
2018
2017
2016
2.61%
1.59%
6.30%
2.63%
2.07%
6.50%
2.52%
2.57%
8.12%
The following table presents a summary of property, plant and equipment by asset category as of December 31, 2018 and 2017 :
Asset Category
Electric—transmission and distribution
Construction work in progress
Other property, plant and equipment (a)
Total property, plant and equipment
Less: accumulated depreciation
Property, plant and equipment, net
__________
(a) Represents plant held for future use and non-utility property.
Average
Service Life
(years)
5-75
N/A
25-33
2018
2017
$
9,217 $
536
61
9,814
3,354
$
6,460
$
8,646
473
59
9,178
3,177
6,001
The annual depreciation provisions as a percentage of average service life for electric transmission and distribution assets were 2.40% , 2.35% and 2.17% for
the years ended December 31, 2018 , 2017 and 2016 , respectively.
DPL
The following table presents a summary of property, plant and equipment by asset category as of December 31, 2018 and 2017 :
Asset Category
Electric—transmission and distribution
Gas—distribution
Common—electric and gas
Construction work in progress
Other property, plant and equipment (a)
Total property, plant and equipment
Less: accumulated depreciation
Property, plant and equipment, net
__________
(a) Represents plant held for future use and non-utility property.
313
Average
Service Life
(years)
5-70
5-75
5-75
N/A
10-43
2018
2017
$
4,195 $
651
136
151
17
5,150
1,329
3,821
$
$
3,875
614
117
205
15
4,826
1,247
3,579
Table of Contents
Combined Notes to Consolidated Financial Statements - (Continued)
(Dollars in millions, except per share data unless otherwise noted)
The following table presents the annual depreciation provisions as a percentage of average service life for each asset category.
Average Service Life Percentage by Asset Category
Electric—transmission and distribution
Gas
Common—electric and gas
ACE
2018
2017
2016
2.77%
1.59%
3.70%
2.75%
2.07%
4.14%
2.49%
2.57%
4.99%
The following table presents a summary of property, plant and equipment by asset category as of December 31, 2018 and 2017 :
Asset Category
Electric—transmission and distribution
Construction work in progress
Other property, plant and equipment (a)
Total property, plant and equipment
Less: accumulated depreciation
Property, plant and equipment, net
__________
(a) Represents plant held for future use and non-utility property.
Average
Service Life
(years)
5-60
N/A
13-15
2018
2017
$
3,866 $
209
28
4,103
1,137
$
2,966
$
3,607
138
27
3,772
1,066
2,706
The annual depreciation provisions as a percentage of average service life for electric transmission and distribution assets were 2.45% , 2.46% and 2.45% for
the years ended December 31, 2018 , 2017 and 2016 , respectively.
Capitalized Software Costs (All Registrants)
The following tables presents net unamortized capitalized software costs and amortization of capitalized software costs by year.
Net unamortized software costs
Exelon
Generation
ComEd
PECO
BGE
PHI
Pepco
DPL
ACE
December 31, 2018
December 31, 2017
$
810 $
164 $
206 $
98 $
166 $
165 $
26 $
21 $
834
173
227
111
179
133
2
1
14
1
Amortization of capitalized software costs
Exelon
Generation
ComEd
PECO
BGE
Pepco
DPL
ACE
2018
2017
2016
PHI
$
282 $
78 $
79 $
37 $
48 $
2 $
2 $
270
255
73
72
73
62
39
33
46
44
—
—
—
—
1
—
—
Successor
Predecessor
For the year ended December
31, 2018
For the year ended December
31, 2017
March 24, 2016 to December
31, 2016
January 1, 2016 to March 23, 2016
8
29 $
Amortization of capitalized software costs
$
33 $
34 $
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Combined Notes to Consolidated Financial Statements - (Continued)
(Dollars in millions, except per share data unless otherwise noted)
Capitalized Interest and AFUDC (All Registrants)
The following table summarizes total incurred interest, capitalized interest and credits to AFUDC by year:
2018
Total incurred interest (a)
Capitalized interest
Credits to AFUDC debt and equity
2017
Total incurred interest (a)
Capitalized interest
Credits to AFUDC debt and equity
2016
Total incurred interest (a)
Capitalized interest
Credits to AFUDC debt and equity
Exelon
Generation
ComEd
PECO
BGE
$ 1,695 $
464 $
377 $
141 $
130 $
Pepco
DPL
ACE
162 $ 62 $ 68
31
109
31
—
—
30
—
12
—
24
—
34
—
4
—
4
$ 1,658 $
502 $
369 $
130 $
111 $
133 $ 54 $ 64
63
108
63
—
—
20
—
12
—
22
—
34
—
10
—
9
$ 1,678 $
472 $
469 $
127 $
114 $
137 $ 52 $ 65
108
98
107
—
Successor
—
22
—
11
—
30
—
29
—
7
—
9
Predecessor
PHI
For the year ended December
31, 2018
For the year ended December
31, 2017
March 24, 2016 to December
31, 2016
January 1, 2016 to March 23,
2016
Total incurred interest (a)
$
Credits to AFUDC debt and equity
__________
(a)
Includes interest expense to affiliates.
305 $
44
263 $
54
207 $
35
68
10
See Note 1 — Significant Accounting Policies for additional information regarding property, plant and equipment policies. See Note 13 — Debt and Credit
Agreements for additional information regarding Exelon’s, ComEd’s and PECO’s property, plant and equipment subject to mortgage liens.
7. Impairment of Long-Lived Assets and Intangibles (Exelon, Generation and PHI)
Long-Lived Assets (Exelon, Generation and PHI)
Registrants evaluate long-lived assets for recoverability whenever events or changes in circumstances indicate that the carrying amount may not be recoverable.
In the second quarter of 2018, updates to Exelon's long-term view of energy and capacity prices suggested that the carrying value of a group of merchant wind
assets, located in West Texas, may be impaired. Upon review, the estimated undiscounted future cash flows and fair value of the group were less than its
carrying value. The fair value analysis was based on the income approach using significant unobservable inputs (Level 3) including revenue and generation
forecasts, projected capital and maintenance expenditures and discount rates. As a result, long-lived merchant wind assets held and used with a net carrying
amount of $41 million were fully impaired and a pre-tax impairment charge of $41 million was recorded during 2018 within Operating and maintenance expense
in Exelon's and Generation's Consolidated Statements of Operations and Comprehensive Income.
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. As a result, 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 future impairments of the New
England asset group, which could be material. See Note 8 — Early Plant Retirements for additional information.
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 and paid the District of Columbia $25 million , 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 over time through future negotiations. In the fourth quarter of
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Combined Notes to Consolidated Financial Statements - (Continued)
(Dollars in millions, except per share data unless otherwise noted)
2017, based upon the lack of currently available sponsorship opportunities, 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.
On May 2, 2017, EGTP entered into a consent agreement with its lenders to initiate an orderly sales process to sell 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 of $460 million within Operating and maintenance expense in their Consolidated Statements of Operations and Comprehensive
Income during 2017. 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 5 — Mergers, Acquisitions and Dispositions for additional information.
In the second quarter of 2016, updates to Exelon's long-term view of energy and capacity prices suggested that the carrying value of a group of merchant wind
assets, located in West Texas, may be impaired. Upon review, the estimated undiscounted future cash flows and fair value of the group were less than their
carrying value. The fair value analysis was based on the income approach using significant unobservable inputs (Level 3) including revenue and generation
forecasts, projected capital and maintenance expenditures and discount rates. As a result of the fair value analysis, long-lived merchant wind assets held and
used with a carrying amount of approximately $60 million were written down to their fair value of $24 million and a pre-tax impairment charge of $36 million was
recorded during the second quarter of 2016 in Operating and maintenance expense in Exelon’s and Generation’s Consolidated Statements of Operations and
Comprehensive Income.
In the first quarter of 2016, significant changes in Generation’s intended use of the Upstream oil and gas assets, developments with nonrecourse debt held by its
Upstream subsidiary CEU Holdings, LLC (as described in Note 13 — Debt and Credit Agreements ) and continued declines in both production volumes and
commodity prices suggested that the carrying value may be impaired. Generation concluded that the estimated undiscounted future cash flows and fair value of
its Upstream properties were less than their carrying values. As a result, a pre-tax impairment charge of $119 million was recorded in March 2016 within
Operating and maintenance expense in Exelon’s and Generation’s Consolidated Statements of Operations and Comprehensive Income. On June 16, 2016,
Generation initiated the sales process of its Upstream natural gas and oil exploration and production business by executing a forbearance agreement with the
lenders of the nonrecourse debt, see Note 13 — Debt and Credit Agreements for additional information. An additional pre-tax impairment charge of $15 million
was recorded in September 2016 within Operating and maintenance expense in Exelon’s and Generation’s Consolidated Statements of Operations and
Comprehensive Income due to further declines in fair value. In December 2016, Generation sold substantially all of the Upstream Assets. See Note 5 —
Mergers, Acquisitions and Dispositions for additional information.
The fair value analysis used in the above impairments was primarily based on the income approach using significant unobservable inputs (Level 3) including
revenue, generation and production forecasts, projected capital and maintenance expenditures and discount rates. Changes in the assumptions described
above could potentially result in future impairments of Exelon’s long-lived assets, which could be material.
Like-Kind Exchange Transaction (Exelon)
In June 2000, UII, LLC (formerly Unicom Investments, Inc.) (UII), a wholly owned subsidiary of Exelon Corporation, entered into transactions pursuant to which
UII invested in coal-fired generating station leases (Headleases) with the Municipal Electric Authority of Georgia (MEAG). The generating stations were leased
back to MEAG as part of the transactions (Leases).
Pursuant to the applicable authoritative guidance, Exelon is required to review the estimated residual values of its direct financing lease investments at least
annually and record an impairment charge if the review indicates an other-than-temporary decline in the fair value of the residual values below their carrying
values. Exelon estimates the fair value of the residual values of its direct financing lease investments based on the income approach, which uses a discounted
cash flow analysis, taking into consideration significant unobservable inputs (Level 3) including the expected revenues to be generated and costs to be incurred
to operate the plants over their remaining useful lives subsequent to the lease end dates. Significant assumptions used in estimating the fair value include
fundamental energy and capacity prices, fixed and variable costs, capital expenditure requirements, discount rates, tax rates and the estimated remaining useful
lives of the plants. The estimated fair values also reflect the cash
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Combined Notes to Consolidated Financial Statements - (Continued)
(Dollars in millions, except per share data unless otherwise noted)
flows associated with the service contract option discussed above given that a market participant would take into consideration all of the terms and conditions
contained in the lease agreements.
All the Headleases were terminated by the second quarter of 2016, and no events occurred prior to the termination that required Exelon to review the estimated
residual values of the direct financing lease investments in 2016. On March 31, 2016, UII and MEAG finalized an agreement to terminate the MEAG
Headleases, the MEAG Leases, and other related agreements prior to their expiration dates. As a result of the lease termination, UII received an early
termination payment of $360 million from MEAG and wrote-off the $356 million net investment in the MEAG Headleases and the Leases. The transaction
resulted in a pre-tax gain of $4 million which is reflected in Operating and maintenance expense in Exelon's Consolidated Statements of Operations and
Comprehensive Income. See Note 14 — Income Taxes for additional information.
8. 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 the benefits they
provide through their carbon-free emissions, reliability, or fuel security, and the impact of potential rules from the EPA requiring reduction of carbon and other
emissions and the efforts of states to implement those final rules. The precise timing of an early retirement date for any plant, and the resulting financial
statement impacts, may be affected by many factors, including the status of potential regulatory or legislative solutions, results of any transmission system
reliability study assessments, the nature of any co-owner requirements and stipulations, and NDT fund requirements for nuclear plants, among other factors.
However, the earliest retirement date for any plant would usually be the first year in which the unit does not have capacity or other obligations, and where
applicable, just prior to its next scheduled nuclear refueling outage.
Nuclear Generation
In 2015 and 2016, Generation identified the Clinton and Quad Cities nuclear plants in Illinois, Ginna and Nine Mile Point nuclear plants in New York and Three
Mile Island nuclear plant in Pennsylvania as having the greatest risk of early retirement based on economic valuation and other factors.
On June 2, 2016, Generation announced it would shutdown the Clinton and Quad Cities nuclear plants on June 1, 2017 and June 1, 2018, respectively, given a
lack of progress on Illinois energy legislation and MISO market reforms, and capacity auctions results that failed to cover cash operating costs and a risk-
adjusted rate of return to shareholders.
On December 7, 2016, Illinois FEJA was signed into law by the Governor of Illinois and included a ZES that now provides compensation to Clinton and Quad
Cities for the carbon-free attributes of their production through 2027. With the passage of the Illinois ZES in December 2016, Generation reversed its June 2016
decision to permanently cease generation operations at the Clinton and Quad Cities nuclear generating plants. Clinton and Quad Cities are currently licensed to
operate through 2026 and 2032, respectively. See Note 4 - Regulatory Matters for additional information on the Illinois FEJA and the ZES.
In New York, the Ginna and Nine Mile Point nuclear plants faced similar economic challenges and on August 1, 2016, the NYPSC issued an order adopting the
CES, which now provides payments to Ginna and Nine Mile Point, as well as FitzPatrick, for the environmental attributes of their production through 2029. Ginna
and Nine Mile Point Unit 1 are currently licensed to operate through 2029, and Nine Mile Point Unit 2 through 2046. See Note 4 - Regulatory Matters for
additional information on the New York CES.
Assuming the continued effectiveness of both the Illinois ZES and the New York CES, Generation and CENG, through its ownership of Ginna and Nine Mile
Point, no longer consider Clinton, Quad Cities, Ginna or Nine Mile Point to be at heightened risk for early retirement. However, to the extent either the Illinois
ZES or the New York CES programs 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 Pennsylvania, the TMI nuclear plant failed to clear in the May 2017 PJM capacity auction for the 2020-2021 planning year, the third consecutive year that TMI
failed to clear in 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
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Combined Notes to Consolidated Financial Statements - (Continued)
(Dollars in millions, except per share data unless otherwise noted)
absence of federal or state policies that place a value on nuclear energy for its ability to produce electricity without air pollution, Exelon announced that
Generation will permanently cease generation operations at TMI on or about September 30, 2019. TMI is currently committed to operate through May 2019 and
is licensed to operate through 2034. Generation has filed the required market and regulatory notifications to shutdown the plant. PJM has subsequently notified
Generation that it has not identified any reliability issues and has approved the deactivation of TMI as proposed.
In 2010, Generation announced that Oyster Creek would retire by the end of 2019 as part of an agreement with the State of New Jersey to avoid significant
costs associated with the construction of cooling towers to meet the State's then new environmental regulations. Since then, like other nuclear sites, Oyster
Creek continued to face rising operating costs amid a historically low wholesale power price environment. On February 2, 2018, Exelon announced that
Generation will permanently cease generation operations at the Oyster Creek nuclear plant at the end of its current operating cycle and permanently ceased
generation operations in September 2018.
As a result of these early nuclear plant retirement decisions, Exelon and Generation recognized one-time charges in Operating and maintenance expense
related to materials and supplies inventory reserve adjustments, employee-related costs and CWIP impairments, among other items. In addition to these one-
time charges, annual 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), accelerated amortization of nuclear fuel, and additional ARO accretion expense associated with the changes in
decommissioning timing and cost assumptions were also recorded. See Note 15 — Asset Retirement Obligations for additional information on changes to the
nuclear decommissioning ARO balance. 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 (d)
Accelerated nuclear fuel amortization
Operating and Maintenance
One-time charges (e,f)
Change in ARO accretion, net of any contractual offset (g)
Contractual offset for ARC depreciation (g)
Total
2018 (a)
2017 (b)
2016 (c)
$
539 $
57
250 $
12
32
—
—
77
—
—
$
628 $
339 $
712
60
26
2
(86)
714
_________
(a) Reflects incremental accelerated depreciation for TMI and Oyster Creek. The Oyster Creek year-to-date amounts are from February 2, 2018 through September 17, 2018.
(b) Reflects incremental charges for TMI including incremental accelerated depreciation and amortization from May 30, 2017 through December 31, 2017.
(c) Reflects incremental charges for Clinton and Quad Cities including incremental accelerated depreciation and amortization from June 2, 2016 through December 6, 2016.
In December 2016, as a result of reversing its retirement decision for Clinton and Quad Cities, Exelon and Generation updated the expected economic useful life for both
facilities, to 2027 for Clinton, commensurate with the end of the Illinois ZES, and to 2032 for Quad Cities, the end of its current operating license. Depreciation was
therefore adjusted beginning December 7, 2016, to reflect these extended useful life estimates.
(d) Reflects incremental accelerated depreciation of plant assets, including any ARC.
(e) Primarily includes materials and supplies inventory reserve adjustments, employee related costs and CWIP impairments. Excludes the charge to Operating and
maintenance expense from the ARO remeasurement due to the announced sale of Oyster Creek. See Note 5 — Mergers, Acquisitions and Dispositions for additional
information.
In June 2016, as a result of the retirement decision for Clinton and Quad Cities, Exelon and Generation recognized one-time charges of $146 million . In December 2016,
as a result of reversing its retirement decision for Clinton and Quad Cities, Exelon and Generation reversed approximately $120 million of these one-time charges initially
recorded in June 2016.
(f)
(g) For Quad Cities based on the regulatory agreement with the ICC, decommissioning-related activities are offset within Exelon's and Generation's Consolidated Statements
of Operations and Comprehensive Income. The offset results in an equal adjustment to the noncurrent payables to ComEd at Generation and an adjustment to the
regulatory liabilities at ComEd. Likewise, ComEd has recorded an equal noncurrent affiliate receivable from Generation and corresponding regulatory liability.
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Combined Notes to Consolidated Financial Statements - (Continued)
(Dollars in millions, except per share data unless otherwise noted)
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.
On May 23, 2018, New Jersey enacted legislation that established a ZEC program, similar to that in Illinois and New York, 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. The NJBPU must complete its processes for determining eligibility for, and participation in,
the ZEC program by April 18, 2019. On December 19, 2018, PSEG submitted its application for Salem. Assuming the successful implementation of the New
Jersey ZEC program and the selection of Salem as one of the qualifying facilities, the New Jersey ZEC program has the potential to mitigate the heightened risk
of earlier retirement for Salem. See Note 4 - Regulatory Matters for additional information.
The following table provides the balance sheet amounts as of December 31, 2018 for Generation’s ownership share of the significant assets and liabilities
associated with Salem that would potentially be impacted by a decision to permanently cease generation operations.
Asset Balances
Materials and supplies inventory
Nuclear fuel inventory, net
Completed plant, net
Construction work in progress
Liability Balances
Asset retirement obligation
NRC License Renewal Term
December 31, 2018
$
45
118
538
44
(395)
2036 (unit 1)
2040 (unit 2)
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 its Mystic Generating Station assets absent regulatory reforms on June
1, 2022, at the end of the current capacity commitment for Mystic Units 7 and 8. Mystic Unit 9 is currently committed through May 2021.
The ISO-NE announced that it would take a three-step approach to fuel security.
•
First, on May 1, 2018, ISO-NE made a filing with FERC requesting waiver of certain tariff provisions to allow it to retain Mystic Units 8 and 9 for fuel
security for the 2022 - 2024 capacity commitment periods. FERC denied the waiver request on procedural grounds on July 2, 2018 and ordered ISO-
NE to (i) make a filing within 60 days providing for the filing of a short-term cost-of-service agreement to address fuel security concerns and (ii) make a
filing by July 1, 2019 proposing permanent tariff revisions that would improve its market design to better address regional fuel security concerns.
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Combined Notes to Consolidated Financial Statements - (Continued)
(Dollars in millions, except per share data unless otherwise noted)
•
•
Second, in accordance with FERC's July 2, 2018 order, on August 31, 2018, ISO-NE made a filing with FERC proposing short-term tariff changes to
permit it to retain a resource for fuel security reliability reasons, which FERC accepted on December 3, 2018.
Third, ISO-NE stated its intention to work with stakeholders to develop long-term market rule changes to address system resiliency considering
significant reliability risks identified in ISO-NE’s January 2018 fuel security report. Changes to market rules are necessary because critical units to the
region, such as Mystic Units 8 and 9, cannot recover future operating costs, including the cost of procuring fuel. In its July 2, 2018 order, FERC ordered
ISO-NE to make a filing by July 1, 2019 proposing permanent tariff revisions that would improve its market design to better address regional fuel
security concerns. In January 2019, ISO-NE has indicated that it intends to seek an extension of the deadline for this filing to November 15, 2019.
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. Among the costs included in the filing are costs associated with the Everett Marine Terminal. On December
20, 2018, FERC issued an order accepting the cost of service agreement reflecting a number of adjustments to the annual fixed revenue requirement and
allowing for recovery of a substantial portion of the costs associated with the Everett Marine Terminal. FERC also directed a paper hearing on ROE using a new
methodology. Initial and reply briefs on ROE will be due on April 18, 2019 and July 18, 2019. These will be reflected in a compliance filing due February 18,
2019. On January 4, 2019, Generation notified ISO-NE that it will participate in the Forward Capacity Market auction for the 2022 - 2023 capacity commitment
period. In addition, on January 22, 2019, Exelon and several other parties filed requests for rehearing of certain findings of the December 20, 2018 order. The
request for rehearing does not alter Generation's commitment to participate in the Forward Capacity Auction for the 2022-2023 capacity commitment period.
The following table provides the balance sheet amounts as of December 31, 2018 for 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 a decision to permanently cease generation operations.
Asset Balances
Materials and supplies inventory
Fuel inventory
Completed plant, net
Construction work in progress
Liability Balances
Asset retirement obligation
December 31, 2018
$
30
20
901
9
(1)
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.
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Combined Notes to Consolidated Financial Statements - (Continued)
(Dollars in millions, except per share data unless otherwise noted)
9. Jointly Owned Electric Utility Plant (Exelon, Generation, PECO, BGE, PHI, Pepco, DPL and ACE)
Exelon's, Generation's, PECO's, BGE's, Pepco's, DPL's and ACE's undivided ownership interests in jointly owned electric plants and transmission facilities at
December 31, 2018 and 2017 were as follows:
Operator
Ownership interest
Exelon’s share at December 31, 2018:
Plant (e)
Accumulated depreciation (e)
Construction work in progress
Exelon’s share at December 31, 2017:
Plant (e)
Accumulated depreciation (e)
$
$
Nuclear Generation
Fossil-Fuel Generation
Transmission
Other
Quad Cities
Peach
Bottom
Generation
Generation
Salem (a)
PSEG
Nuclear
Nine Mile Point Unit 2
Generation
Wyman
FP&L
PA (b)
First
Energy
NJ/ DE (c)
Other (d)
PSEG/ DPL
various
75.00%
50.00%
42.59%
82.00%
5.89%
various
various
various
1,131
$
1,451
$
587
13
523
15
$
1,074
550
$
1,417
461
$
$
648
227
44
631
205
$
$
910
126
56
839
97
$
$
4
3
—
3
3
28 $
16
1
103 $
53
—
27 $
15
—
102 $
52
—
15
13
—
15
13
Construction work in progress
__________
(a) Generation also owns a proportionate share in the fossil-fuel combustion turbine at Salem, which is fully depreciated. The gross book value was $3 million at
33
55
35
18
—
—
December 31, 2018 and 2017 .
(b) PECO, BGE, Pepco, DPL and ACE own a 22% , 7% , 27% , 9% and 8% share, respectively, in 127 miles of 500 kV lines located in Pennsylvania as well as a 20.72% ,
10.56% , 9.72% , 3.72% and 3.83% share, respectively, of a 500 kV substation immediately outside of the Conemaugh fossil-generating station which supplies power to
the 500 kV lines including, but not limited to, the lines noted above.
(c) PECO, DPL and ACE own a 42.55% , 1% and 13.9% share, respectively in 151.3 miles of 500 kV 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 500 kV line located over the Delaware River. ACE also has a
21.78% share in a 500 kV New Freedom Switching substation.
(d) Generation, DPL and ACE own a 44.24% , 11.91% and 4.83% share, respectively in assets located at Merrill Creek Reservoir located in New Jersey. Pepco, DPL and
ACE own a 11.9% , 7.4% and 6.6% share, respectively, in Valley Forge Corporate Center.
(e) Excludes asset retirement costs and general plant.
Exelon’s, Generation’s, PECO's, BGE's, Pepco'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, BGE's, Pepco'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, BGE's, Pepco's, DPL's and ACE's Consolidated
Statements of Operations and Comprehensive Income.
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Combined Notes to Consolidated Financial Statements - (Continued)
(Dollars in millions, except per share data unless otherwise noted)
10. Intangible Assets (Exelon, Generation, ComEd, PECO, PHI, Pepco, DPL and ACE)
Goodwill
Exelon’s, ComEd’s and PHI's gross amount of goodwill, accumulated impairment losses and carrying amount of goodwill for the years ended December 31,
2018 and 2017 were as follows:
Exelon
Gross amount
Accumulated impairment loss
Carrying amount
ComEd (a)
Gross amount
Accumulated impairment loss
Carrying amount
PHI (b)
Gross amount
Carrying amount
Balance at
January 1, 2017
Impairment losses
Balance at December
31, 2017
Impairment losses
Balance at December
31, 2018
$
8,660 $
1,983
6,677
4,608
1,983
2,625
4,005
4,005
— $
—
—
—
—
—
—
—
8,660 $
1,983
6,677
4,608
1,983
2,625
4,005
4,005
— $
—
—
—
—
—
—
—
8,660
1,983
6,677
4,608
1,983
2,625
4,005
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 24 — 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. PHI identified an error related to the allocation of goodwill to its reporting units in 2016
while performing the 2018 annual impairment assessment. As revised in 2018, Exelon's and PHI's $4 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, an increase (decrease) of $0.4 billion , $0.3 billion , and $(0.7)
billion for Pepco, DPL and ACE, respectively, from the originally reported amounts. This error did not result in a change to the total amount of goodwill recorded
at PHI nor would it have resulted in an impairment of PHI's goodwill in 2016 or 2017. Therefore, management has concluded that the error is not material to the
previously issued financial statements.
Entities assessing goodwill for impairment have the option of first performing a qualitative assessment to determine whether a quantitative assessment is
necessary. In performing a qualitative assessment, entities should assess, among other things, macroeconomic conditions, industry and market considerations,
overall financial performance, cost factors and entity-specific events. If an entity determines, on the basis of qualitative factors, that the fair value of the reporting
unit is more likely than not greater than the carrying amount, no further testing is required.
If an entity bypasses the qualitative assessment or performs the qualitative assessment but determines that it is more likely than not that its fair value is less than
its carrying amount, a quantitative two-step, fair value-based test is performed. Exelon's, ComEd's and PHI's accounting policy is to perform a quantitative test of
goodwill at least once every three years. The first step in the quantitative test 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. If the implied
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Combined Notes to Consolidated Financial Statements - (Continued)
(Dollars in millions, except per share data unless otherwise noted)
fair value of goodwill is less than the carrying amount, an impairment loss is recorded as a reduction to goodwill and a charge to operating expense.
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.
2018 and 2017 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, 2018 and 2017 for ComEd and as of
November 1, 2017 for PHI. As part of their qualitative assessments, ComEd and PHI evaluated, 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 company EBITDA multiples, while also considering, the passing margin from their last quantitative assessments as of November 1,
2016.
As a result of the reallocation of goodwill to PHI’s reporting units as discussed above, as of November 1, 2018, PHI performed a quantitative test for its 2018
annual goodwill impairment assessment. 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 annual goodwill test 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.
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Other Intangible Assets and Liabilities
Combined Notes to Consolidated Financial Statements - (Continued)
(Dollars in millions, except per share data unless otherwise noted)
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, 2018 and 2017 :
December 31, 2018
Accumulated
Amortization
Gross
Net
Gross
December 31, 2017
Accumulated
Amortization
Net
Generation
Unamortized Energy Contracts (b)
Customer Relationships
Trade Name
ComEd
1,957
325
243
(1,588)
(162)
(171)
369
163
72
1,938
305
243
(1,574)
(133)
(148)
Chicago Settlement Agreements (c)
162
(148)
14
162
(141)
PHI
364
172
95
21
Unamortized Energy Contracts (b)
(1,515)
954
(561)
(1,515)
766
(749)
Exelon Corporate
Software License (a)
Exelon
95
(34)
61
95
(25)
$
1,267 $
(1,149) $
118 $
1,228 $
(1,255) $
70
(27)
__________
(a) On May 31, 2015, Exelon entered into a long-term software license agreement. Exelon is required to make payments starting August 2015 through May 2024. The
(b)
(c)
intangible asset recognized as a result of these payments is being amortized on a straight-line basis over the contract term.
Includes unamortized energy contract assets and liabilities in Exelon's, Generations and PHI's Consolidated Balance Sheets.
In March 1999 and February 2003, ComEd entered into separate agreements with the City of Chicago and Midwest Generation, LLC. Under the terms of the settlement,
ComEd agreed to make payments to the City of Chicago. The intangible asset recognized as a result of the settlement agreement is being amortized ratably over the
remaining term of the City of Chicago franchise agreement.
The following table summarizes the estimated future amortization expense related to intangible assets and liabilities as of December 31, 2018 :
For the Years Ending December 31,
Exelon
Generation
ComEd
PHI
2019
2020
2021
2022
2023
$
(32) $
70 $
7 $
(20)
(4)
(23)
(21)
78
78
56
50
7
—
—
—
(119)
(115)
(92)
(89)
(81)
The following table summarizes the amortization expense related to intangible assets and liabilities for each of the years ended December 31, 2018 , 2017 and
2016 :
For the Years Ended December 31,
Exelon (a)(b)
Generation (a)
ComEd
PHI (b)
2018 $
2017
2016
(109) $
(237)
(336)
63 $
83
79
7 $
7
7
(188)
(336)
(430)
__________
(a) At Exelon and Generation, amortization of unamortized energy contracts totaling $14 million , $35 million and $35 million for the years ended December 31, 2018 , 2017
and 2016 , respectively, was recorded in Operating revenues or Purchased power and fuel expense in their Consolidated Statements of Operations and Comprehensive
Income.
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Combined Notes to Consolidated Financial Statements - (Continued)
(Dollars in millions, except per share data unless otherwise noted)
(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.
Acquired Intangible Assets and Liabilities
Business combinations require the acquirer to separately recognize identifiable intangible assets in the application of purchase accounting.
Unamortized Energy Contracts. Unamortized energy contract assets and liabilities represent the remaining unamortized fair value of non-derivative energy
contracts that Exelon and Generation have acquired. The valuation of unamortized energy contracts was estimated by applying either the market approach or
the income approach depending on the nature of the underlying contract. The market approach was utilized when prices and other relevant information
generated by market transactions involving comparable transactions were available. Otherwise, the income approach, which is based upon discounted projected
future cash flows associated with the underlying contracts, was utilized. The fair value is based upon certain unobservable inputs, which are considered Level 3
inputs, pursuant to applicable authoritative guidance. Key estimates and inputs include forecasted power and fuel prices and the discount rate. The Exelon Wind
unamortized energy contracts are amortized on a straight-line basis over the period in which the associated contract revenues are recognized as a decrease in
Operating revenues within Exelon’s and Generation’s Consolidated Statements of Operations and Comprehensive Income. In the case of Antelope Valley,
Constellation, CENG, Integrys and ConEdison, the fair value amounts are amortized over the life of the contract in relation to the present value of the underlying
cash flows as of the acquisition dates through either Operating revenues or Purchased power and fuel expense within Exelon’s and Generation’s Consolidated
Statements of Operations and Comprehensive Income. At PHI, offsetting regulatory assets or liabilities were also recorded. 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.
Customer Relationships. The customer relationship intangibles were determined based on a “multi-period excess method” of the income approach. Under this
method, the intangible asset’s fair value is determined to be the estimated future cash flows that will be earned on the current customer base, taking into account
expected contract renewals based on customer attrition rates and costs to retain those customers. The fair value is based upon certain unobservable inputs,
which are considered Level 3 inputs, pursuant to applicable authoritative guidance. Key assumptions include the customer attrition rate and the discount
rate. The authoritative guidance requires that customer-based intangibles be amortized over the period expected to be benefited using the pattern of economic
benefit. The amortization of the customer relationships recorded in Depreciation and amortization expense within Exelon's and Generation's Consolidated
Statements of Operations and Comprehensive Income.
Trade Name. The Constellation trade name intangible was determined based on the relief from royalty method of income approach whereby fair value is
determined to be the present value of the license fees avoided by owning the assets. The fair value is based upon certain unobservable inputs, which are
considered Level 3 inputs, pursuant to applicable authoritative guidance. Key assumptions include the hypothetical royalty rate and the discount rate. The
Constellation trade name intangible is amortized on a straight-line basis over a period of 10 years . The amortization of the trade name is recorded in
Depreciation and amortization expense within Exelon's and Generation's Consolidated Statements of Operations and Comprehensive Income.
Renewable Energy Credits and Alternative Energy Credits (Exelon, Generation, PECO, PHI, DPL and ACE)
Exelon’s, Generation’s, PECO's, PHI's, DPL's and ACE's other intangible assets, included in Other current assets and Other deferred debits and other assets in
the Consolidated Balance Sheets, include RECs (Exelon, Generation, PHI, DPL and ACE) and AECs (Exelon and PECO). 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.
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Combined Notes to Consolidated Financial Statements - (Continued)
(Dollars in millions, except per share data unless otherwise noted)
The following table summarizes the current and noncurrent Renewable and Alternative Energy Credits as of December 31, 2018 and 2017 :
Current AEC's
Current REC's
Noncurrent REC's
Current AEC's
Current REC's
Noncurrent REC's
$
$
As of December 31, 2018
Exelon
Generation
PECO
PHI
DPL
ACE
2 $
279
52
— $
270
52
2 $
—
—
— $
— $
9
—
8
—
As of December 31, 2017
Exelon
Generation
PECO
PHI
DPL
ACE
1 $
321
27
— $
312
27
1 $
—
—
— $
— $
9
—
8
—
—
1
—
—
1
—
11. Fair Value of Financial Assets and Liabilities (All Registrants)
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, 2018 and 2017 :
Exelon
Short-term liabilities
$
714 $
— $
714
$
— $
Long-term debt (including amounts due within one year) (a)
Long-term debt to financing trusts (b)
SNF obligation
35,424
390
1,171
—
—
—
33,711
—
949
2,158
400
—
714
35,869
400
949
Carrying
Amount
Level 1
Level 2
Level 3
Total
December 31, 2018
Fair Value
Carrying
Amount
Level 1
Level 2
Level 3
Total
December 31, 2017
Fair Value
Short-term liabilities
$
929 $
— $
929 $
— $
Long-term debt (including amounts due within one year) (a)
Long-term debt to financing trusts (b)
SNF obligation
34,264
389
1,147
326
—
—
—
34,735
—
936
1,970
431
—
929
36,705
431
936
Table of Contents
Generation
Combined Notes to Consolidated Financial Statements - (Continued)
(Dollars in millions, except per share data unless otherwise noted)
Long-term debt (including amounts due within one year) (a)
$
8,793 $
— $
7,467
$
1,443 $
SNF obligation
1,171
—
949
—
8,910
949
Carrying
Amount
Level 1
Level 2
Level 3
Total
December 31, 2018
Fair Value
Short-term liabilities
Long-term debt (including amounts due within one year) (a)
SNF obligation
ComEd
December 31, 2017
Fair Value
Carrying
Amount
$
2 $
8,990
1,147
Level 1
Level 2
Level 3
Total
— $
—
—
2 $
— $
7,839
936
1,673
—
2
9,512
936
Long-term debt (including amounts due within one year) (a)
$
8,101 $
— $
8,390
$
Long-term debt to financing trusts (b)
205
—
—
— $
209
8,390
209
Carrying
Amount
Level 1
Level 2
Level 3
Total
December 31, 2018
Fair Value
Long-term debt (including amounts due within one year) (a)
Long-term debt to financing trusts (b)
PECO
December 31, 2017
Fair Value
Carrying
Amount
$
7,601 $
205
Level 1
Level 2
Level 3
Total
— $
—
8,418 $
—
— $
227
8,418
227
Long-term debt (including amounts due within one year) (a)
$
3,084 $
— $
3,157
$
Long-term debt to financing trusts
184
—
—
50 $
191
3,207
191
Carrying
Amount
Level 1
Level 2
Level 3
Total
December 31, 2018
Fair Value
Long-term debt (including amounts due within one year) (a)
Long-term debt to financing trusts
December 31, 2017
Fair Value
Level 1
Level 2
Level 3
Total
— $
—
3,194 $
—
— $
204
3,194
204
Carrying
Amount
$
2,903 $
184
327
Table of Contents
BGE
Combined Notes to Consolidated Financial Statements - (Continued)
(Dollars in millions, except per share data unless otherwise noted)
Short-term liabilities
Long-term debt (including amounts due within one year) (a)
Short-term liabilities
Long-term debt (including amounts due within one year) (a)
PHI
December 31, 2018
Fair Value
$
$
Carrying
Amount
35 $
2,876
Carrying
Amount
Level 1
Level 2
Level 3
Total
— $
—
35
$
2,950
— $
—
35
2,950
December 31, 2017
Fair Value
Level 1
Level 2
Level 3
Total
77 $
2,577
— $
—
77 $
2,825
— $
—
77
2,825
Short-term liabilities
Long-term debt (including amounts due within one year) (a)
Carrying Amount
Level 1
Level 2
Level 3
Total
$
179 $
6,259
— $
—
179 $
5,436
— $
665
179
6,101
December 31, 2018
Fair Value
Short-term liabilities
Long-term debt (including amounts due within one year) (a)
Carrying Amount
Level 1
Level 2
Level 3
Total
$
350 $
5,874
— $
—
350 $
5,722
— $
297
350
6,019
December 31, 2017
Fair Value
Pepco
Short-term liabilities
Long-term debt (including amounts due within one year) (a)
Carrying Amount
Level 1
Level 2
Level 3
Total
$
40 $
2,719
— $
—
40 $
2,901
— $
196
40
3,097
December 31, 2018
Fair Value
Short-term liabilities
Long-term debt (including amounts due within one year) (a)
Carrying Amount
Level 1
Level 2
Level 3
Total
$
26 $
2,540
— $
—
26 $
3,114
— $
9
26
3,123
December 31, 2017
Fair Value
328
Table of Contents
DPL
Combined Notes to Consolidated Financial Statements - (Continued)
(Dollars in millions, except per share data unless otherwise noted)
Long-term debt (including amounts due within one year) (a)
$
1,494 $
— $
1,303 $
193 $
1,496
Carrying Amount
Level 1
Level 2
Level 3
Total
December 31, 2018
Fair Value
Short-term liabilities
Long-term debt (including amounts due within one year) (a)
Carrying Amount
Level 1
Level 2
Level 3
Total
$
216 $
1,300
— $
—
216 $
1,393
— $
—
216
1,393
December 31, 2017
Fair Value
ACE
Short-term liabilities
Long-term debt (including amounts due within one year) (a)
Carrying Amount
Level 1
Level 2
Level 3
Total
$
139 $
1,188
— $
—
139 $
987
— $
275
139
1,262
December 31, 2018
Fair Value
December 31, 2017
Fair Value
Carrying Amount
Level 1
Level 2
Level 3
Total
Short-term liabilities
Long-term debt (including amounts due within one year) (a)
__________
(a) Includes unamortized debt issuance costs which are not fair valued of $216 million , $51 million , $63 million , $23 million , $18 million , $14 million , $34 million , $12 million
and $7 million for Exelon, Generation, ComEd, PECO, BGE, PHI, Pepco, DPL and ACE respectively, as of December 31, 2018 . Includes unamortized debt issuance costs
which are not fair valued of $201 million , $60 million , $52 million , $17 million , $17 million , $6 million , $32 million , $11 million and $5 million for Exelon, Generation, ComEd,
PECO, BGE, PHI, Pepco, DPL and ACE respectively, as of December 31, 2017 .
(b) Includes unamortized debt issuance costs which are not fair valued of $0 million and $1 million for Exelon and ComEd, respectively, as of December 31, 2018 . Includes
unamortized debt issuance costs which are not fair valued of $1 million and $1 million for Exelon and ComEd, respectively, as of December 31, 2017 .
1,121
949
288
1,237
—
108
$
108 $
108 $
— $
— $
Short-Term Liabilities. The short-term liabilities included in the tables above are comprised of dividends payable (included in Other current liabilities) (Level 1)
and short-term borrowings (Level 2). The Registrants’ carrying amounts of the short-term liabilities are representative of fair value because of the short-term
nature of these instruments.
Long-Term Debt. The fair value amounts of Exelon’s taxable debt securities (Level 2) and private placement taxable debt securities (Level 3) are determined
by a valuation model that is based on a conventional discounted cash flow methodology and utilizes assumptions of current market pricing curves. In order to
incorporate the credit risk of the Registrants into the discount rates, Exelon obtains pricing (i.e., U.S. Treasury rate plus credit spread) based on trades of
existing Exelon debt securities as well as debt securities of other issuers in the utility sector with similar credit ratings in both the primary and secondary market,
across the Registrants’ debt maturity spectrum. The credit spreads of various tenors obtained from this information are added to the appropriate benchmark U.S.
Treasury rates in order to determine the current market yields for the various tenors. 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
329
Table of Contents
Combined Notes to Consolidated Financial Statements - (Continued)
(Dollars in millions, except per share data unless otherwise noted)
bond or note. Due to low trading volume of private placement debt, qualitative factors such as market conditions, low volume of investors and investor demand,
this debt is classified as Level 3.
The fair value of Generation’s and Pepco's non-government-backed fixed rate nonrecourse debt (Level 3) 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 (e.g., political and regulatory environment). The fair value of Generation’s government-backed fixed
rate project financing debt (Level 3) is largely based on a discounted cash flow methodology that is similar to the taxable debt securities methodology described
above. 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
Treasury rate as well as a current market curve derived from government-backed securities. Variable rate financing debt resets on a monthly or quarterly basis
and the carrying value approximates fair value (Level 2). When trading data is available on variable rate financing debt, the fair value is based on market and
quoted prices for its own and other nonrecourse debt with similar risk profiles (Level 2). Generation, Pepco, DPL and ACE also have tax-exempt debt (Level 2).
Due to low trading volume in this market, qualitative factors, such as market conditions, investor demand, and circumstances related to the issuer (e.g., conduit
issuer political and regulatory environment), may be incorporated into the credit spreads that are used to obtain the fair value as described above. Variable rate
tax-exempt debt (Level 2) resets on a regular basis and the carrying value approximates fair value.
SNF Obligation . The carrying amount of Generation’s SNF obligation (Level 2) 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 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. The carrying amount also includes $119 million and $114 million as of December 31, 2018 and 2017 for the one-time fee obligation
associated with closing of the FitzPatrick acquisition on March 31, 2017. The fair value was determined using a similar methodology, however the New York
Power Authority's (NYPA) discount rate is used in place of Generation's given the contractual right to reimbursement from NYPA for the obligation; see Note 5 -
Mergers, Acquisitions and Dispositions for additional information on Generation's acquisition of FitzPatrick.
Long-Term Debt to Financing Trusts . Exelon’s long-term debt to financing trusts is valued based on publicly traded securities issued by the financing trusts.
Due to low trading volume of these securities, qualitative factors, such as market conditions, investor demand, and circumstances related to each issue, this debt
is classified as Level 3.
Recurring Fair Value Measurements
Exelon records the fair value of assets and liabilities in accordance with the hierarchy established by the authoritative guidance for fair value measurements. The
hierarchy prioritizes the inputs to valuation techniques used to measure fair value into three levels as follows:
•
•
•
Level 1 — quoted prices (unadjusted) in active markets for identical assets or liabilities that the Registrants have the ability to liquidate as of the
reporting date.
Level 2 — inputs other than quoted prices included within Level 1 that are directly observable for the asset or liability or indirectly observable
through corroboration with observable market data.
Level 3 — unobservable inputs, such as internally developed pricing models or third-party valuations for the asset or liability due to little or no
market activity for the asset or liability.
330
Table of Contents
Generation and Exelon
Combined Notes to Consolidated Financial Statements - (Continued)
(Dollars in millions, except per share data unless otherwise noted)
In accordance with the applicable guidance on fair value measurement, certain investments that are measured at fair value using the NAV per share as a
practical expedient are no longer classified within the fair value hierarchy and are included under "Not subject to leveling" in the table below.
The following tables present assets and liabilities measured and recorded at fair value in Exelon's and Generation’s Consolidated Balance Sheets on a recurring
basis and their level within the fair value hierarchy as of December 31, 2018 and 2017 :
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
Generation
Exelon
Assets
Cash equivalents (a)
NDT fund investments
$
581 $
— $
— $
— $
581 $
1,243
$
— $
— $
— $
1,243
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
Middle market lending
Private equity
Real estate
—
—
—
—
—
—
NDT fund investments subtotal
(d)
5,251
3,598
—
—
230
—
—
—
—
230
313
—
—
543
—
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
—
—
—
—
—
—
3,433
12,825
5,251
3,598
331
—
—
230
—
—
—
—
230
313
—
—
543
—
1,381
—
—
—
—
846
846
367
329
510
338
5,890
1,823
2,180
50
149
876
5,078
680
329
510
3,433
12,825
Table of Contents
As of December 31, 2018
Pledged assets for Zion Station
decommissioning
Cash equivalents
Equities
Middle market lending
Pledged assets for Zion Station
decommissioning subtotal
Rabbi trust investments
Cash equivalents
Mutual funds
Fixed income
Life insurance contracts
Rabbi trust investments subtotal
(f)
Commodity derivative assets
Economic hedges
Proprietary trading
Effect of netting and allocation
of
collateral (e)
Commodity derivative assets
subtotal
Interest rate and foreign
currency derivative assets
Derivatives designated as
hedging instruments
Economic hedges
Effect of netting and allocation
of collateral
Interest rate and foreign
currency derivative assets
subtotal
Other investments
Combined Notes to Consolidated Financial Statements - (Continued)
(Dollars in millions, except per share data unless otherwise noted)
Level 1
Level 2
Level 3
Not subject to
leveling
Total
Level 1
Level 2
Level 3
Not subject to
leveling
Total
Generation
Exelon
9
—
—
9
5
24
—
—
29
—
—
—
—
—
—
—
22
22
—
—
—
—
—
—
—
—
—
541
—
2,760
1,470
69
77
(582)
(2,357)
(41)
472
(732)
815
—
—
—
—
—
—
13
(3)
10
—
—
—
—
—
42
—
—
—
—
—
—
—
—
—
—
—
—
—
—
—
—
—
—
9
—
—
9
5
24
—
22
51
4,771
146
(3,671)
1,246
—
13
(3)
10
42
9
—
—
9
48
72
—
—
120
541
—
—
—
—
—
—
—
15
70
85
—
—
—
—
—
—
—
38
38
2,760
1,470
69
77
(582)
(41)
(2,357)
472
(732)
815
—
—
—
—
—
—
13
(3)
10
—
—
—
—
—
42
—
—
—
—
—
—
—
—
—
—
—
—
—
—
—
—
—
—
9
—
—
9
48
72
15
108
243
4,771
146
(3,671)
1,246
—
13
(3)
10
42
Total assets
5,829
4,102
1,400
3,433
14,764
6,582
4,165
1,438
3,433
15,618
332
Table of Contents
Combined Notes to Consolidated Financial Statements - (Continued)
(Dollars in millions, except per share data unless otherwise noted)
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
Generation
Exelon
Liabilities
Commodity derivative liabilities
Economic hedges
(642)
(2,963)
(1,027)
—
639
(3)
—
—
—
—
—
(3)
(73)
2,581
(455)
—
(6)
3
(3)
(35)
(493)
(21)
808
(240)
—
—
—
—
—
(240)
—
—
—
—
—
—
—
—
—
—
(4,632)
(642)
(2,963)
(1,276)
(94)
4,028
(698)
—
(6)
3
(3)
(35)
(736)
—
639
(73)
2,581
(21)
808
(3)
(455)
(489)
—
—
—
—
—
(3)
(4)
(6)
3
(7)
(137)
(599)
—
—
—
—
—
(489)
—
—
—
—
—
—
—
—
—
—
(4,881)
(94)
4,028
(947)
(4)
(6)
3
(7)
(137)
(1,091)
$
5,826
$
3,609
$
1,160
$
3,433
$
14,028
$
6,579
$
3,566
$
949
$
3,433
$
14,527
As of December 31, 2017
Level 1
Level 2
Level 3
Not subject to
leveling
Total
Level 1
Level 2
Level 3
Not subject to
leveling
Total
Generation
Exelon
$
168 $
— $
— $
— $
168 $
656 $
— $
— $
— $
656
135
4,163
85
915
—
1,614
1,917
—
—
—
52
82
263
47
—
—
251
—
—
—
—
—
220
135
2,176
7,254
4,163
85
915
1,865
1,969
82
263
557
—
1,614
1,917
—
—
—
52
82
263
47
—
—
—
—
510
510
333
—
—
251
—
—
—
—
—
2,176
—
—
—
—
510
510
220
7,254
1,865
1,969
82
263
557
4,736
Fixed income subtotal
1,917
2,058
251
4,736
1,917
2,058
251
Proprietary trading
Effect of netting and allocation of
collateral (e)
Commodity derivative liabilities
subtotal
Interest rate and foreign currency
derivative liabilities
Derivatives designated as
hedging instruments
Economic hedges
Effect of netting and allocation of
collateral
Interest rate and foreign currency
derivative liabilities subtotal
Deferred compensation obligation
Total liabilities
Total net assets
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)
Table of Contents
Combined Notes to Consolidated Financial Statements - (Continued)
(Dollars in millions, except per share data unless otherwise noted)
As of December 31, 2017
Level 1
Level 2
Level 3
Not subject to
leveling
Total
Level 1
Level 2
Level 3
Not subject to
leveling
Total
Generation
Exelon
—
—
—
—
—
—
397
—
—
131
222
471
528
222
471
—
—
—
—
—
—
6,215
3,058
648
3,510
13,431
6,215
3,058
Middle market lending
Private equity
Real estate
NDT fund investments subtotal
(d)
Pledged assets for Zion Station
decommissioning
Cash equivalents
Equities
Middle market lending
Pledged assets for Zion Station
decommissioning subtotal
Rabbi trust investments
Cash equivalents
Mutual funds
Fixed income
Life insurance contracts
Rabbi trust investments subtotal
(f)
Commodity derivative assets
Economic hedges
Proprietary trading
Effect of netting and allocation
of
collateral (e)
Commodity derivative assets
subtotal
Interest rate and foreign
currency derivative assets
Derivatives designated as
hedging instruments
Economic hedges
Effect of netting and allocation
of collateral
Interest rate and foreign
currency derivative assets
subtotal
Other investments
Total assets
2
—
—
2
5
23
—
—
28
—
1
—
1
—
—
—
22
22
—
—
12
12
—
—
—
—
—
557
2
2,378
1,290
31
35
(585)
(1,769)
(26)
640
(635)
690
—
—
(2)
(2)
—
3
10
(5)
8
—
—
—
—
—
37
—
—
24
24
—
—
—
—
—
—
—
—
—
—
—
—
—
—
2
1
36
39
5
23
—
22
50
4,225
68
(2,989)
1,304
3
10
(7)
6
37
397
—
—
648
—
—
12
12
—
—
—
22
22
—
1
—
1
—
—
12
71
83
2
—
—
2
77
58
—
—
135
557
2
2,378
1,290
31
35
(585)
(26)
(1,769)
640
(635)
690
—
—
(2)
(2)
—
6
10
(5)
11
—
—
—
—
—
37
131
222
471
528
222
471
3,510
13,431
—
—
24
24
—
—
—
—
—
—
—
—
—
—
—
—
—
—
2
1
36
39
77
58
12
93
240
4,225
68
(2,989)
1,304
6
10
(7)
9
37
6,385
3,729
1,387
3,534
15,035
6,980
3,793
1,409
3,534
15,716
334
Table of Contents
Combined Notes to Consolidated Financial Statements - (Continued)
(Dollars in millions, except per share data unless otherwise noted)
As of December 31, 2017
Level 1
Level 2
Level 3
Not subject to
leveling
Total
Level 1
Level 2
Level 3
Not subject
to leveling
Total
Generation
Exelon
Liabilities
Commodity derivative liabilities
Economic hedges
Proprietary trading
Effect of netting and allocation of
collateral (e)
Commodity derivative liabilities
subtotal
Interest rate and foreign currency
derivative liabilities
Derivatives designated as
hedging instruments
Economic hedges
Effect of netting and allocation of
collateral
Interest rate and foreign currency
derivative liabilities subtotal
Deferred compensation obligation
Total liabilities
(712)
(2)
650
(64)
—
(1)
2
1
—
(63)
(2,226)
(42)
2,089
(179)
(2)
(8)
5
(5)
(38)
(222)
(845)
(9)
716
(138)
—
—
—
—
—
(138)
—
—
—
—
—
—
—
—
—
—
(3,783)
(53)
3,455
(713)
(2)
651
(2,226)
(1,101)
(42)
2,089
(9)
716
(381)
(64)
(179)
(394)
(2)
(9)
7
(4)
(38)
(423)
—
(1)
2
1
—
(63)
(2)
(8)
5
(5)
(145)
(329)
—
—
—
—
—
(394)
—
—
—
—
—
—
—
—
—
—
(4,040)
(53)
3,456
(637)
(2)
(9)
7
(4)
(145)
(786)
$
6,322
$
3,534
$
1,249
$
3,507
$
Total net assets
__________
(a) Generation excludes cash of $283 million and $259 million at December 31, 2018 and 2017 and restricted cash of $39 million and $127 million at December 31, 2018 and
2017 . Exelon excludes cash of $458 million and $389 million at December 31, 2018 and 2017 and restricted cash of $80 million and $145 million at December 31, 2018
and 2017 and includes long-term restricted cash of $185 million and $85 million at December 31, 2018 and 2017 , which is reported in Other deferred debits in the
Consolidated Balance Sheets.
Includes $50 million and $77 million of cash received from outstanding repurchase agreements at December 31, 2018 and 2017 , respectively, and is offset by an
obligation to repay upon settlement of the agreement as discussed in (d) below.
Includes derivative instruments of $44 million and less than $1 million , which have a total notional amount of $1,432 million and $811 million at December 31, 2018 and
2017 , 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)
14,612
$
6,917
$
3,464
$
1,015
$
3,534
$
14,930
(d) Excludes net liabilities of $130 million and $82 million at December 31, 2018 and 2017 , 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) Excludes net assets of less than $1 million at December 31, 2018 and 2017 . These items consist of receivables related to pending securities sales, interest and dividend
(f)
receivables, and payables related to pending securities purchases.
The amount of unrealized gains/(losses) at Generation totaled less than $1 million and $1 million for the years ended December 31, 2018 and 2017 , respectively. The
amount of unrealized gains/(losses) at Exelon totaled $1 million for the years ended December 31, 2018 and 2017 , respectively.
(g) Collateral posted/(received) from 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 . Collateral posted/(received) from counterparties totaled $65 million , $320 million and $81 million allocated to Level 1, Level 2 and
Level 3 mark-to-market derivatives, respectively, as of December 31, 2017 .
(h) Of the collateral posted/(received), $(94) million and $(117) million represents variation margin on the exchanges as of December 31, 2018 and 2017 , respectively.
335
Table of Contents
Combined Notes to Consolidated Financial Statements - (Continued)
(Dollars in millions, except per share data unless otherwise noted)
Exelon and Generation hold investments without readily determinable fair values with carrying amounts of $72 million as of December 31, 2018 . Changes were
immaterial in fair value, cumulative adjustments and impairments for the year ended December 31, 2018 .
ComEd, PECO and BGE
The following tables present assets and liabilities measured and recorded at fair value in ComEd's, PECO's and BGE's Consolidated Balance Sheets on a
recurring basis and their level within the fair value hierarchy as of December 31, 2018 and 2017 :
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 (b)
Total assets
Liabilities
Deferred compensation
obligation
Mark-to-market derivative
liabilities (c)
Total liabilities
—
—
—
209
—
—
—
Total net assets (liabilities) $
209
$
—
—
—
—
(6)
—
(6)
(6)
—
—
—
—
—
—
—
7
—
7
209
118
—
(6)
(249)
(249)
(249)
(255)
—
—
—
—
10
10
10
(10)
—
(10)
—
—
—
—
—
—
—
7
10
17
128
(10)
—
(10)
$
(249)
$
(46)
$
118
$
— $
— $
118
$
6
—
6
10
—
—
—
10
$
—
—
—
—
(5)
—
(5)
(5)
—
—
—
—
—
—
—
$
— $
4
6
—
6
10
(5)
—
(5)
5
336
Table of Contents
Combined Notes to Consolidated Financial Statements - (Continued)
(Dollars in millions, except per share data unless otherwise noted)
As of December 31, 2017
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)
$
98
$
— $
— $
98 $
228
$
— $
— $
228 $
— $
— $
— $
Rabbi trust investments
Mutual funds
Life insurance contracts
Rabbi trust investments
subtotal (b)
Total assets
Liabilities
Deferred compensation
obligation
Mark-to-market derivative
liabilities (c)
Total liabilities
—
—
—
98
—
—
—
—
—
—
—
(8)
—
(8)
—
—
—
—
—
—
—
98
7
—
7
235
—
(8)
(256)
(256)
(256)
(264)
—
—
—
—
10
10
10
(11)
—
(11)
—
—
—
—
—
—
—
7
10
17
245
(11)
—
(11)
6
—
6
6
—
—
—
—
—
—
—
(5)
—
(5)
—
—
—
—
—
—
—
—
6
—
6
6
(5)
—
(5)
$
98
(8)
Total net assets (liabilities) $
__________
(a) ComEd excludes cash of $93 million and $45 million at December 31, 2018 and 2017 and restricted cash of $28 million at December 31, 2018 and includes long-term
restricted cash of $166 million and $62 million at December 31, 2018 and December 31, 2017 , which is reported in Other deferred debits in the Consolidated Balance
Sheets. PECO excludes cash of $24 million and $47 million at December 31, 2018 and 2017 . BGE excludes cash of $7 million and $17 million at December 31, 2018
and 2017 and restricted cash of $2 million and $1 million at December 31, 2018 and December 31, 2017 .
— $
— $
(166)
(256)
235
234
(5)
(1)
$
$
$
6
$
$
$
$
$
1
(b) The amount of unrealized gains/(losses) at ComEd, PECO and BGE totaled less than $1 million for the years ended December 31, 2018 and December 31, 2017 .
(c) The Level 3 balance consists of the current and noncurrent liability of $26 million and $223 million , respectively, at December 31, 2018 , and $21 million and $235 million ,
respectively, at December 31, 2017 , related to floating-to-fixed energy swap contracts with unaffiliated suppliers.
337
Table of Contents
PHI, Pepco, DPL and ACE
Combined Notes to Consolidated Financial Statements - (Continued)
(Dollars in millions, except per share data unless otherwise noted)
The following tables present assets and liabilities measured and recorded at fair value in PHI's, Pepco's, DPL's and ACE's Consolidated Balance Sheets on a
recurring basis and their level within the fair value hierarchy as of December 31, 2018 and 2017 :
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
Mark-to-market derivative liabilities
Effect of netting and allocation of collateral
Mark-to-market derivative liabilities subtotal
As of December 31, 2018
As of December 31, 2017
Level 1
Level 2
Level 3
Total
Level 1
Level 2
Level 3
Total
$
147 $
— $
— $
147 $
83 $
— $
— $
42
13
—
—
55
202
—
—
—
—
—
—
15
22
37
37
(21)
—
—
—
(21)
16
$
—
—
—
38
38
38
—
—
—
—
42
13
15
60
130
277
(21)
—
—
—
72
—
—
—
72
155
—
(1)
1
—
—
38
$
(21)
256
$
—
155
$
—
—
12
23
35
35
(25)
—
—
—
(25)
10
$
—
—
—
22
22
22
—
—
—
—
—
22
$
83
72
—
12
45
129
212
(25)
(1)
1
—
(25)
187
Total liabilities
Total net assets
—
202
$
$
As of December 31, 2018
Assets
Pepco
DPL
ACE
Level 1
Level 2
Level 3
Total
Level 1
Level 2
Level 3
Total
Level 1
Level 2
Level 3
Total
Cash equivalents (a)
$
38 $
— $
— $
38 $
16 $
— $
— $
16 $
23 $
— $
— $
Rabbi trust investments
Cash equivalents
Fixed income
Life insurance
contracts
Rabbi trust investments
subtotal (b)
Total assets
Liabilities
Deferred compensation
obligation
Total liabilities
Total net assets
(liabilities)
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
—
—
—
—
—
—
—
—
—
—
—
—
—
—
—
—
$
79
$
24
$
37
$
140
$
16
$
(1)
$
— $
15
$
23
$
— $
— $
23
—
—
—
—
23
—
—
23
338
Table of Contents
As of December 31, 2017
Assets
Combined Notes to Consolidated Financial Statements - (Continued)
(Dollars in millions, except per share data unless otherwise noted)
Pepco
DPL
ACE
Level 1
Level 2
Level 3
Total
Level 1
Level 2
Level 3
Total
Level 1
Level 2
Level 3
Total
Cash equivalents (a)
$
36 $
— $
— $
36 $
— $
— $
— $ — $
29 $
— $
— $
29
Rabbi trust investments
Cash equivalents
Fixed income
Life insurance contracts
Rabbi trust investments subtotal
(b)
Total assets
Liabilities
Deferred compensation
obligation
Mark-to-market derivative
liabilities
Effect of netting and allocation
of collateral
Mark-to-market derivative
liabilities subtotal
Total liabilities
44
—
—
44
80
—
—
—
—
—
—
12
23
35
35
(4)
—
—
—
(4)
—
—
22
22
22
—
—
—
—
—
44
12
45
101
137
(4)
—
—
—
(4)
—
—
—
—
—
—
(1)
1
—
—
—
—
—
—
—
(1)
—
—
—
(1)
—
—
—
—
—
—
—
—
—
—
—
—
—
—
—
(1)
(1)
1
—
(1)
—
—
—
—
29
—
—
—
—
—
—
—
—
—
—
—
—
—
—
—
—
—
—
—
—
—
—
—
—
—
—
—
—
—
29
—
—
—
—
—
$
$
80
Total net assets (liabilities)
__________
(a) PHI excludes cash of $39 million and $12 million at December 31, 2018 and 2017 and includes long term restricted cash of $19 million and $23 million at December 31,
2018 and 2017 which is reported in Other deferred debits in the Consolidated Balance Sheets. Pepco excludes cash of $15 million and $4 million at December 31, 2018
and 2017 . DPL excludes cash of $8 million and $2 million at December 31, 2018 and 2017 . ACE excludes cash of $7 million and $2 million at December 31, 2018 and
2017 and includes long-term restricted cash of $19 million and $23 million at December 31, 2018 and 2017 at December 31, 2018 and 2017 which is reported in Other
deferred debits in the Consolidated Balance Sheets.
— $
(1)
$
— $
29
— $
— $
(1)
$
$ 133
29
31
22
$
$
$
(b) The amount of unrealized gains/(losses) at PHI totaled $1 million for the years ended December 31, 2018 and 2017 , respectively. The amount of unrealized
gains/(losses) at Pepco totaled less than $1 million for the years ended December 31, 2018 and 2017 , respectively.
339
Table of Contents
Combined Notes to Consolidated Financial Statements - (Continued)
(Dollars in millions, except per share data unless otherwise noted)
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, 2018 and 2017 :
Generation
ComEd
PHI
Exelon
For the year ended December 31,
2018
NDT Fund
Investments
Pledged Assets
for Zion Station
Decommissioning
Balance as of January 1, 2018 $
648
$
12
Derivatives
Mark-to-Market
$
552
Other
Investments
Total
Generation
$
37
$
1,249
Derivatives
Mark-to-Market
$
(256)
Life Insurance
Contracts (c)
Eliminated in
Consolidation
Total
$
22 $
— $
1,015
Total realized / unrealized
gains (losses)
Included in net income
Included in noncurrent
payables to affiliates
Included in payable for
Zion Station
decommissioning
Included in regulatory
assets/liabilities
Change in collateral
Purchases, sales, issuances
and settlements
Purchases
Sales
Issuances
Settlements
Transfers into Level 3
Transfers out of Level 3
Other miscellaneous
Balance as of December 31,
2018
—
(1)
—
—
—
36
—
—
(140)
—
—
—
$
543
$
— $
The amount of total (losses)
gains included in income
attributed to the change in
unrealized (losses) gains
related to assets and liabilities
held as of December 31, 2018 $
(5)
$
— $
165
—
—
7
—
—
(105)
(a)
—
—
—
(5)
1
190 (e)
(20)
—
—
—
—
—
(4)
—
5
(22)
(d)
(36)
(d)
—
575
3
—
—
—
—
4
—
—
—
—
(2)
(102)
(1)
7
—
(5)
231
(24)
—
(135)
(22)
(38)
—
—
—
—
7 (b)
—
—
—
—
—
—
—
—
4
—
—
—
—
—
—
—
12
—
—
—
—
1
—
(1)
—
—
—
—
—
—
—
—
42
$
1,160
$
(249)
$
38
$
— $
(98)
—
7
6
(5)
231
(24)
—
(123)
(22)
(38)
—
949
3
$
163 $
—
$
— $
— $
163
$
$
340
Table of Contents
Combined Notes to Consolidated Financial Statements - (Continued)
(Dollars in millions, except per share data unless otherwise noted)
Generation
ComEd
PHI
Exelon
For the year ended December 31,
2017
NDT Fund
Investments
Pledged Assets
for Zion Station
Decommissioning
Balance as of January 1, 2017 $
677
$
19
Derivatives
Mark-to-Market
$
493
Other
Investments
Total
Generation
$
42
$
1,231
Derivatives
Mark-to-Market
$
(258)
Life Insurance
Contracts (c)
Eliminated in
Consolidation
Total
$
20
$
— $
993
Total realized / unrealized
gains (losses)
Included in net income
Included in noncurrent
payables to affiliates
Included in payable for
Zion Station
decommissioning
Included in regulatory
assets/liabilities
Change in collateral
Purchases, sales, issuances
and settlements
Purchases
Sales
Issuances
Settlements
Transfers into Level 3
Transfers out of Level 3
Other miscellaneous
Balance as of December 31,
2017
$
$
3
6
—
—
—
64
—
—
(102)
—
—
— $
648
$
—
—
(8)
—
—
1
—
—
—
—
—
— $
(90)
(a)
—
—
—
20
178
(16)
—
(8)
(6)
(d)
(d)
(50)
31
12
$
552
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, 2017 $
__________
(a)
1
$
— $
254
3
—
—
—
—
5
—
—
—
—
(84)
6
(8)
—
20
248
(16)
—
(110)
(6)
(11)
(2)
$
(61)
29 $
—
—
—
2 (b)
—
—
—
—
—
—
—
—
37
$
1,249
$
(256)
3
$
258 $
—
$
$
$
$
$
$
3
—
—
—
—
—
(1)
—
—
—
— $
22
$
—
(6)
—
6
—
—
—
—
—
—
—
— $
(81)
—
(8)
8
20
248
(16)
(1)
(110)
(6)
(61)
29
— $
1,015
3
$
— $
261
(b)
Includes a reduction for the reclassification of $265 million and $352 million of realized gains due to the settlement of derivative contracts for the years ended
December 31, 2018 and 2017 , respectively.
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 . Includes $18 million of decreases in fair value and an increase
for realized losses due to settlements of $20 million recorded in purchased power expense associated with floating-to-fixed energy swap contracts with unaffiliated
suppliers for the year ended December 31, 2017 .
(c) The amounts represented are life insurance contracts at Pepco.
(d) 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.
Includes $(19) million of fair value from contracts acquired as a result of the Everett Marine Terminal acquisition
(e)
341
Table of Contents
Combined Notes to Consolidated Financial Statements - (Continued)
(Dollars in millions, except per share data unless otherwise noted)
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, 2018 and 2017 :
Generation
Purchased
Power and
Fuel
Operating
Revenues
PHI
Exelon
Other, net
Operating and
Maintenance
Operating
Revenues
Purchased
Power and
Fuel
Operating and
Maintenance
Other, net
Total (losses) gains included in net
income for the year ended December 31,
2018
$
Change in the unrealized gains relating
to assets and liabilities held for the year
ended December 31, 2018
(7) $
(93) $
3 $
4 $
(7) $
(93) $
4 $
3
144
21
(2)
—
144
21
—
(2)
Total gains (losses) included in net
income for the year ended December
31, 2017
$
Change in the unrealized gains
(losses) relating to assets and
liabilities held for the year ended
December 31, 2017
Generation
Purchased
Power and
Fuel
Operating
Revenues
PHI
Exelon
Other, net
Operating and
Maintenance
Operating
Revenues
Purchased
Power and
Fuel
Operating and
Maintenance
Other, net
28 $
(126) $
6 $
3 $
28 $
(126) $
3 $
290
(36)
4
3
290
(36)
3
6
4
Valuation Techniques Used to Determine Fair Value
The following describes the valuation techniques used to measure the fair value of the assets and liabilities shown in the tables above.
Cash Equivalents (Exelon, Generation, ComEd, PECO, BGE, PHI, Pepco, DPL and ACE). The Registrants’ cash equivalents include investments with
original maturities of three months or less when purchased. The cash equivalents shown in the fair value tables are comprised of investments in mutual and
money market funds. The fair values of the shares of these funds are based on observable market prices and, therefore, have been categorized in Level 1 in the
fair value hierarchy.
NDT Fund Investments and Pledged Assets for Zion Station Decommissioning (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. 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.
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 Generation is able to independently corroborate. The fair values of equity securities held directly by the trust funds which are based on
quoted prices in active markets are categorized in 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. Equity securities held individually are primarily traded on
the New York Stock Exchange and NASDAQ-Global Select Market, which contain only actively traded securities due to the volume trading requirements
imposed by these exchanges.
For fixed income securities, multiple prices from pricing services are obtained 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
342
Table of Contents
Combined Notes to Consolidated Financial Statements - (Continued)
(Dollars in millions, except per share data unless otherwise noted)
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. Generation has obtained an
understanding of how these prices are derived, including the nature and observability of the inputs used in deriving such prices. Additionally, Generation
selectively corroborates the fair values of securities by comparison to other market-based price sources. U.S. Treasury securities are categorized as Level 1
because they trade in a highly liquid and transparent market. The fair values of fixed income securities, excluding U.S. Treasury 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 fair values of private placement fixed income securities, which are included in Corporate debt, are determined using a third-party
valuation that contains significant unobservable inputs and are categorized in Level 3.
Equity and fixed income commingled funds and mutual funds are maintained by investment companies and hold certain investments in accordance with a stated
set of fund objectives such as holding short-term fixed income securities or tracking the performance of certain equity indices by purchasing equity securities to
replicate the capitalization and characteristics of the indices. 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 commingled funds and mutual funds, which are not
publicly quoted, the funds are valued using NAV as a practical expedient for fair value, which is primarily derived from the quoted prices in active markets on the
underlying securities, and are not classified within the fair value hierarchy. These investments typically can be redeemed monthly with 30 or less days of notice
and without further restrictions.
Derivative instruments consisting primarily of futures and interest rate 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.
Middle market lending are investments in loans or managed funds which lend to private companies. Generation elected the fair value option for its investments
in certain limited partnerships that invest in middle market lending managed funds. The fair value of these loans is determined using a combination of valuation
models including cost models, market models, and income models. Investments in loans are categorized as Level 3 because the fair value of these securities is
based largely on inputs that are unobservable and utilize complex valuation models. Managed funds are valued using NAV or its equivalent as a practical
expedient, and therefore, are not classified within the fair value hierarchy. Investments in middle market lending typically cannot be redeemed until maturity of
the term loan.
Private equity and real estate investments include those in limited partnerships that invest in operating companies and real estate holding companies that are not
publicly traded on a stock exchange, such as, leveraged buyouts, growth capital, venture capital, distressed investments, investments in natural resources, and
direct investments in pools of real estate properties. The fair value of private equity and real estate investments is determined using NAV or its equivalent as a
practical expedient, and therefore, are not classified within the fair value hierarchy. These investments typically cannot be redeemed and are generally liquidated
over a period of 8 to 10 years from the initial investment date, which is based on Exelon’s understanding of the investment funds. Private equity and real estate
valuations are reported by the fund manager and are based on the valuation of the underlying investments, which include inputs such as cost, operating results,
discounted future cash flows, market based comparable data, and independent appraisals from sources with professional qualifications. These valuation inputs
are unobservable.
As of December 31, 2018 , Generation has outstanding commitments to invest in fixed income, middle market lending, private equity and real estate investments
of approximately $127 million , $224 million , $326 million and $273 million , respectively. These commitments will be funded by Generation’s existing NDT
funds.
Concentrations of Credit Risk. Generation evaluated its NDT portfolios for the existence of significant concentrations of credit risk as of December 31, 2018 .
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, 2018 , there were no significant concentrations (generally defined as greater than 10 percent) of risk in Generation's NDT
assets.
See Note 15 — Asset Retirement Obligations for additional information on the NDT fund investments.
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(Dollars in millions, except per share data unless otherwise noted)
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. The mutual funds are maintained by investment companies and hold certain investments in accordance with a stated set of fund
objectives, which are consistent with Exelon’s overall investment strategy. Money market funds and mutual funds are publicly quoted and have been categorized
as Level 1 given the clear observability of the prices. The fair values of fixed income securities are based on evaluated prices that reflect observable market
information, such as actual trade information or similar securities, adjusted for observable differences and are categorized in Level 2. The life insurance policies
are valued using the cash surrender value of the policies, net of loans against those policies, which is provided by a third-party. Certain life insurance policies,
which consist primarily of mutual funds that are priced based on observable market data, have been categorized as Level 2 because the life insurance policies
can be liquidated at the reporting date for the value of the underlying assets. Life insurance policies that are valued using unobservable inputs have been
categorized as Level 3.
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.
Exelon may utilize fixed-to-floating interest rate swaps as a means to achieve its targeted level of variable-rate debt as a percent of total debt. In addition, the
Registrants may utilize interest rate derivatives to lock in interest rate levels in anticipation of future financings. Exelon determines the current fair value by
calculating the net present value of expected payments and receipts under the swap agreement, based on and discounted by the market's expectation of future
interest rates. Additional inputs to the net present value calculation may include the contract terms, counterparty credit risk and other market parameters. As
these inputs are based on observable data and valuations of similar instruments, the interest rate swaps are categorized in Level 2 in the fair value hierarchy.
See Note 12 — Derivative Financial Instruments for additional information on mark-to-market derivatives.
Deferred Compensation Obligations (Exelon, Generation, ComEd, PECO, BGE, PHI, Pepco, DPL and ACE). 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.
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(Dollars in millions, except per share data unless otherwise noted)
Additional Information Regarding Level 3 Fair Value Measurements (Exelon, Generation, ComEd, PHI, Pepco, DPL and ACE)
NDT Fund Investments and Pledged Assets for Zion Station Decommissioning (Exelon and Generation). For middle market lending and certain
corporate debt securities investments, the fair value is determined using a combination of valuation models including cost models, market models and income
models. The valuation estimates are based on discounting the forecasted cash flows, market-based comparable data, credit and liquidity factors, as well as
other factors that may impact value. Significant judgment is required in the application of discounts or premiums applied for factors such as size, marketability,
credit risk and relative performance.
Because Generation relies on third-party fund managers to develop the quantitative unobservable inputs without adjustment for the valuations of its Level 3
investments, quantitative information about significant unobservable inputs used in valuing these investments is not reasonably available to Generation. This
includes information regarding the sensitivity of the fair values to changes in the unobservable inputs. Therefore, Generation has not disclosed such inputs.
Rabbi Trust Investments - Life insurance contracts (Exelon, PHI, Pepco, DPL and ACE). For life insurance policies categorized as Level 3, 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.
Mark-to-Market Derivatives (Exelon, Generation and ComEd). 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.
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
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(Dollars in millions, except per share data unless otherwise noted)
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 $3.18 and $0.64 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 12 — 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.
The following tables present the significant inputs to the forward curve used to value these positions:
Type of trade
Fair Value at December
31, 2018
Valuation
Technique
Unobservable
Input
Range
Mark-to-market derivatives—Economic hedges (Exelon
and Generation) (a)(b)
$
Discounted
Cash Flow
443
Forward power price
Forward gas price
Option Model
Volatility percentage
$12
$0.78
10%
Mark-to-market derivatives—Proprietary trading (Exelon
and Generation) (a)(b)
$
Discounted
Cash Flow
56
Forward power price
$14
Mark-to-market derivatives (Exelon and ComEd)
$
Discounted
Cash Flow
(249)
Forward heat rate (c)
Marketability reserve
Renewable factor
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 $76 million as of December 31, 2018 .
(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.
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Combined Notes to Consolidated Financial Statements - (Continued)
(Dollars in millions, except per share data unless otherwise noted)
Type of trade
Fair Value at
December 31, 2017
Valuation
Technique
Unobservable
Input
Range
Mark-to-market derivatives—Economic hedges (Exelon
and Generation) (a)(b)
$
Discounted
Cash Flow
445
Forward power price
Forward gas price
Option Model
Volatility percentage
$3
$1.27
11%
Mark-to-market derivatives—
Proprietary trading (Exelon and Generation) (a)(b)
Mark-to-market derivatives (Exelon and ComEd)
$
$
Discounted
Cash Flow
26
Discounted
Cash Flow
(256)
Forward power price
$14
Forward heat rate (c)
Marketability reserve
Renewable factor
9x
4%
88%
-
-
-
-
-
-
-
$124
$12.80
139%
$94
10x
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 $81 million as of December 31, 2017 .
(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.
12. Derivative Financial Instruments (All Registrants)
The Registrants use derivative instruments to manage commodity price risk, interest rate risk and foreign exchange risk related to ongoing business operations.
Commodity Price Risk (All Registrants)
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. 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.
Derivative authoritative guidance requires that derivative instruments be recognized as either assets or liabilities at fair value, with changes in fair value of the
derivative recognized in earnings immediately. Other accounting treatments are available through special election and designation, provided they meet specific,
restrictive criteria both at the time of designation and on an ongoing basis. These alternative permissible accounting treatments include normal purchase normal
sale (NPNS), cash flow hedges and fair value hedges. For Generation, all derivative
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(Dollars in millions, except per share data unless otherwise noted)
economic hedges related to commodities are recorded at fair value through earnings for the consolidated company, referred to as economic hedges in the
following tables. 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.
Fair value authoritative guidance and disclosures 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 Sheet. 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. Generation’s use of cash collateral is generally unrestricted, unless
Generation is downgraded below investment grade (i.e., to BB+ or Ba1). In the table below, 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 column. As of
December 31, 2018 , $2 million of cash collateral posted with external counterparties and an additional $12 million of cash collateral posted with ComEd, and as
of December 31, 2017 , $4 million of cash collateral held, was not offset against derivative positions because such collateral was not associated with any energy-
related derivatives, were associated with accrual positions, or had no positions to offset as of the balance sheet date. Excluded from the tables below are
economic hedges that qualify for the NPNS scope exception and other non-derivative contracts that are accounted for under the accrual method of accounting.
ComEd’s use of cash collateral is generally unrestricted unless ComEd is downgraded below investment grade (i.e., to BB+ or Ba1).
Cash collateral held by PECO and BGE must be deposited in an unaffiliated major U.S. commercial bank or foreign bank with a U.S. branch office that meet
certain qualifications.
In the table below, DPL's economic hedges 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 column.
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Combined Notes to Consolidated Financial Statements - (Continued)
(Dollars in millions, except per share data unless otherwise noted)
The following table provides a summary of the derivative fair value balances related to commodity contracts recorded by the Registrants as of December 31,
2018 :
Description
Generation
ComEd
Exelon
Economic
Hedges
Proprietary
Trading
Collateral
and
Netting (a)(d)
Subtotal (b)
Economic
Hedges (c)
Total
Derivatives
Mark-to-market derivative assets (current assets)
$
3,505 $
105 $
(2,809) $
801 $
— $
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
1,266
4,771
(3,429)
(1,203)
(4,632)
41
146
(74)
(20)
(94)
(862)
(3,671)
3,056
972
4,028
445
1,246
(447)
(251)
(698)
—
—
(26)
(223)
(249)
Total mark-to-market derivative net assets (liabilities)
$
139
$
52
$
357 $
548 $
(249)
$
801
445
1,246
(473)
(474)
(947)
299
__________
(a) Exelon and Generation net all available amounts allowed under the derivative authoritative guidance on 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 are not reflected in the table above.
(b) Current and noncurrent assets are shown net of collateral of $121 million and $51 million , respectively, and current and noncurrent liabilities are shown net of collateral of
$125 million and $60 million , respectively. The total cash collateral posted, net of cash collateral received and offset against mark-to-market assets and liabilities was
$357 million at December 31, 2018 .
Includes current and noncurrent liabilities relating to floating-to-fixed energy swap contracts with unaffiliated suppliers.
(c)
(d) Of the collateral posted/(received), $(94) million represents variation margin on the exchanges.
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Combined Notes to Consolidated Financial Statements - (Continued)
(Dollars in millions, except per share data unless otherwise noted)
The following table provides a summary of the derivative fair value balances related to commodity contracts recorded by the Registrants as of December 31,
2017 :
Description
Generation
ComEd
Exelon
Economic
Hedges
Proprietary
Trading
Collateral
and
Netting (a)(d)
Subtotal (b)
Economic
Hedges (c)
Total
Derivatives
Mark-to-market derivative assets (current assets)
$
3,061 $
56 $
(2,144) $
973 $
— $
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
1,164
4,225
(2,646)
(1,137)
(3,783)
12
68
(43)
(10)
(53)
(845)
(2,989)
2,480
975
3,455
331
1,304
(209)
(172)
(381)
—
—
(21)
(235)
(256)
Total mark-to-market derivative net assets (liabilities)
$
442
$
15
$
466 $
923 $
(256)
$
973
331
1,304
(230)
(407)
(637)
667
__________
(a) Exelon and Generation net all available amounts allowed under the derivative authoritative guidance on 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, and letters
of credit and other forms of non-cash collateral. These are not reflected in the table above.
(b) Current and noncurrent assets are shown net of collateral of $169 million and $53 million , respectively, and current and noncurrent liabilities are shown net of collateral of
$167 million and $77 million , respectively. The total cash collateral posted, net of cash collateral received and offset against mark-to-market assets and liabilities was
$466 million at December 31, 2017 .
Includes current and noncurrent liabilities relating to floating-to-fixed energy swap contracts with unaffiliated suppliers.
(c)
(d) Of the collateral posted/(received), $(117) million represents variation margin on the exchanges.
Economic Hedges (Commodity Price Risk)
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. For the years ended December 31, 2018 , 2017 and 2016 , 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" in the Consolidated Statements of Cash Flows.
Income Statement Location
Operating revenues
Purchased power and fuel
Total Exelon and Generation
For the Years Ended December 31,
2018
2017
Gain (Loss)
2016
$
$
(270) $
(47)
(317) $
(126) $
(43)
(169) $
(490)
459
(31)
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
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(Dollars in millions, except per share data unless otherwise noted)
price risk on a ratable basis over three-year periods. As of December 31, 2018 , the percentage of expected generation hedged for the Mid-Atlantic, Midwest,
New York and ERCOT reportable segments is 89% - 92% , 56% - 59% and 32% - 35% for 2019 , 2020 and 2021 , respectively.
On December 17, 2010, ComEd executed several 20 -year floating-to-fixed energy swap contracts with unaffiliated suppliers for the procurement of long-term
renewable energy and associated RECs. Delivery under the contracts began in June 2012. These contracts are designed to lock in a portion of the long-term
commodity price risk resulting from the renewable energy resource procurement requirements in the Illinois Settlement Legislation. ComEd has not elected
hedge accounting for these derivative financial instruments. ComEd records the fair value of the swap contracts on its balance sheet. Because ComEd receives
full cost recovery for energy procurement and related costs from retail customers, the change in fair value each period is recorded by ComEd as a regulatory
asset or liability. See Note 4 — Regulatory Matters for additional information.
PECO’s natural gas procurement policy is designed to achieve a reasonable balance of long-term and short-term gas purchases under different pricing
approaches to achieve system supply reliability at the least cost. PECO’s reliability strategy is two-fold. First, PECO must assure that there is sufficient
transportation capacity to satisfy delivery requirements. Second, PECO must ensure that a firm source of supply exists to utilize the capacity resources. All of
PECO’s natural gas supply and asset management agreements that are derivatives either qualify for the NPNS scope exception and have been designated as
such, or have no mark-to-market balances because the derivatives are index priced. Additionally, in accordance with the 2018 PAPUC PGC settlement and to
reduce the exposure of PECO and its customers to natural gas price volatility, PECO has continued its program to purchase natural gas for both winter and
summer supplies using a layered approach of locking-in prices ahead of each season with long-term gas purchase agreements (those with primary terms of at
least twelve months). Under the terms of the 2018 and previous PGC settlements, PECO is required to lock in (i.e., economically hedge) the price of a minimum
volume of its long-term gas commodity purchases. PECO’s gas-hedging program is designed to cover about 20% of planned natural gas purchases in support of
projected firm sales. The hedging program for natural gas procurement has no direct impact on PECO’s results of operations and financial position as natural
gas costs are fully recovered from customers under the PGC.
BGE has contracts to procure SOS electric supply that are executed through a competitive procurement process approved by the MDPSC. The SOS rates
charged recover BGE’s wholesale power supply costs and include an administrative fee. BGE’s commodity price risk related to electric supply procurement is
limited. BGE locks in fixed prices for all of its SOS requirements through full requirements contracts. Certain of BGE’s full requirements contracts, which are
considered derivatives, qualify for the NPNS scope exception under current derivative authoritative guidance. Other BGE full requirements contracts are not
derivatives.
BGE provides natural gas to its customers under a MBR mechanism approved by the MDPSC. Under this mechanism, BGE’s actual cost of gas is compared to
a market index (a measure of the market price of gas in a given period). The difference between BGE’s actual cost and the market index is shared equally
between shareholders and customers. BGE must also secure fixed price contracts for at least 10% , but not more than 20% , of forecasted system supply
requirements for flowing (i.e., non-storage) gas for the November through March period. These fixed-price contracts are not subject to sharing under the MBR
mechanism. BGE also ensures it has sufficient pipeline transportation capacity to meet customer requirements. BGE’s natural gas supply and asset
management agreements qualify for the NPNS scope exception and result in physical delivery.
Pepco has contracts to procure SOS electric supply that are executed through a competitive procurement process approved by the MDPSC and DCPSC. The
SOS rates charged recover Pepco's wholesale power supply costs and include an administrative fee. The administrative fee includes an incremental cost
component and a shareholder return component for residential and commercial rate classes. Pepco’s commodity price risk related to electric supply
procurement is limited. Pepco locks in fixed prices for its SOS requirements through full requirements contracts. Certain of Pepco’s full requirements contracts,
which are considered derivatives, qualify for the NPNS scope exception under current derivative authoritative guidance. Other Pepco full requirements contracts
are not derivatives.
DPL has contracts to procure SOS electric supply that are executed through a competitive procurement process approved by the MDPSC and the DPSC. The
SOS rates charged recover DPL's wholesale power supply costs. In Delaware, DPL is also entitled to recover a Reasonable Allowance for Retail Margin
(RARM). The RARM includes a fixed annual margin of approximately $2.75 million , plus an incremental cost component and a cash working capital allowance.
In Maryland, DPL charges an administrative fee intended to allow it to recover its administrative
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Combined Notes to Consolidated Financial Statements - (Continued)
(Dollars in millions, except per share data unless otherwise noted)
costs. DPL locks in fixed prices for its SOS requirements through full requirements contracts. DPL’s commodity price risk related to electric supply procurement
is limited. Certain of DPL’s full requirements contracts, which are considered derivatives, qualify for the NPNS scope exception under current derivative
authoritative guidance. Other DPL full requirements contracts are not derivatives.
DPL provides natural gas to its customers under an Annual GCR mechanism approved by the DPSC. Under this mechanism, DPL’s Annual GCR Filing
establishes a future GCR for firm bundled sales customers by using a forecast of demand and commodity costs. The actual costs are trued up against forecast
on a monthly basis and any shortfall or excess is carried forward as a recovery balance in the next GCR filing. The demand portion of the GCR is based upon
DPL’s firm transportation and storage contracts. DPL has firm deliverability of swing and seasonal storage; a liquefied natural gas facility and firm transportation
capacity to meet customer demand and provide a reserve margin. The commodity portion of the GCR includes a commission approved hedging program which
is intended to reduce gas commodity price volatility while limiting the firm natural gas customers’ exposure to adverse changes in the market price of natural gas.
The hedge program requires that DPL hedge, on a non-discretionary basis, an amount equal to 50% of estimated purchase requirements for each month,
including estimated monthly purchases for storage injections. The 50% hedge monthly target is achieved by hedging 1/12th of the 50% target each month
beginning 12-months prior to the month in which the physical gas is to be purchased. Currently, DPL uses only exchange traded futures for its gas hedging
program, which are considered derivatives, however, it retains the capability to employ other physical and financial hedges if needed. DPL has not elected
hedge accounting for these derivative financial instruments. Because of the DPSC-approved fuel adjustment clause for DPL's derivatives, the change in fair
value of the derivatives each period, in addition to all premiums paid and other transaction costs incurred as part of the Gas Hedging Program, are fully
recoverable and are recorded by DPL as regulatory assets or liabilities. DPL’s physical gas purchases are currently all daily, monthly or intra-month transactions.
From time to time, DPL will enter into seasonal purchase or sale arrangements, however, there are none currently in the portfolio. Certain of DPL's full
requirements contracts, which are considered derivatives, qualify for the NPNS scope exception under current derivative authoritative guidance. Other DPL full
requirements contracts are not derivatives.
ACE has contracts to procure BGS electric supply that are executed through a competitive procurement process approved by the NJBPU. The BGS rates
charged recover ACE's wholesale power supply costs. ACE does not make any profit or incur any loss on the supply component of the BGS it supplies to
customers. ACE’s commodity price risk related to electric supply procurement is limited. ACE locks in fixed prices for its BGS requirements through full
requirements contracts. Certain of ACE’s full requirements contracts, which are considered derivatives, qualify for the NPNS scope exception under current
derivative authoritative guidance. Other ACE full requirements contracts are not derivatives.
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. Proprietary trading activities are subject to
limits established by Exelon’s RMC. The proprietary trading portfolio is subject to a risk management policy that includes stringent risk management limits to
manage exposure to market risk. Additionally, the Exelon risk management group and Exelon's RMC monitor the financial risks of the 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
revenue from energy marketing activities. 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. For the years ended December 31, 2018 , 2017 and 2016 , Exelon and Generation
recognized the following net pre-tax commodity mark-to-market gains (losses) which are also included in the "Net fair value changes related to derivatives" in the
Consolidated Statements of Cash Flows. The Utility Registrants do not execute derivatives for proprietary trading purposes.
Income Statement Location
Operating revenues
For the Years Ended December 31,
2018
2017
Gain
2016
$
17 $
6 $
2
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Combined Notes to Consolidated Financial Statements - (Continued)
(Dollars in millions, except per share data unless otherwise noted)
Interest Rate and Foreign Exchange Risk (All Registrants)
The Registrants use a combination of fixed-rate and variable-rate debt to manage interest rate exposure. The Registrants also utilize interest rate swaps, which
are treated as economic hedges, to manage their interest rate exposure. To manage foreign exchange rate exposure associated with international commodity
purchases in currencies other than U.S. dollars, Generation utilizes foreign currency derivatives, which are treated as economic hedges. Below is a summary of
the interest rate and foreign exchange hedge balances as of December 31, 2018 :
Description
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)
Economic
Hedges
Generation
Collateral
and
Netting (a)
Exelon Corporate
Exelon
Subtotal
Economic
Hedges
Total
$
$
5
8
13
(4)
(2)
(6)
7
$
$
$
(2)
(1)
(3)
2
1
3
3
7
10
(2)
(1)
(3)
$
— $
—
—
—
(4)
(4)
— $
7
$
(4)
$
3
7
10
(2)
(5)
(7)
3
__________
(a) Exelon and Generation net all available amounts allowed under the derivative authoritative guidance on 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 counterparty exposures subject to a master netting or similar agreement, such as accrued interest, transactions that do not qualify as derivatives, letters of credit
and other forms of non-cash collateral, which are not reflected in the table above.
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Combined Notes to Consolidated Financial Statements - (Continued)
(Dollars in millions, except per share data unless otherwise noted)
The following table provides a summary of the interest rate and foreign exchange hedge balances recorded by the Registrants as of December 31, 2017 :
Description
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)
$
$
Derivatives
Designated
as Hedging
Instruments
— $
3
3
(2)
—
(2)
1
Generation
Exelon Corporate
Exelon
Economic
Hedges
Collateral
and
Netting (a)
Subtotal
Derivatives
Designated
as Hedging
Instruments
Total
10 $
—
10
(7)
(2)
(9)
(7)
$
—
(7)
7
—
7
3
3
6
(2)
(2)
(4)
$
— $
3
3
—
—
—
$
1
$
— $
2
$
3 $
3
6
9
(2)
(2)
(4)
5
__________
(a) Exelon and Generation net all available amounts allowed under the derivative authoritative guidance on 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 counterparty exposures subject to a master netting or similar agreement, such as accrued interest, transactions that do not qualify as derivatives, letters of credit
and other forms of non-cash collateral, which are not reflected in the table above.
Economic Hedges (Interest Rate and Foreign Exchange Risk)
Exelon and Generation execute these instruments to mitigate exposure to fluctuations in interest rates or foreign exchange but for which the fair value or cash
flow hedge elections were not made. 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 amount deferred in AOCI associated with the previously designated cash flow hedges will be reclassified into
earnings as the underlying forecasted transaction occurs. The result of this de-designation is that all economic hedges for interest rate swaps will be recorded at
fair value through earnings going forward, referred to as economic hedges in the following tables.
The following table provides notional amounts outstanding held by Exelon and Generation at December 31, 2018 related to interest rate swaps and foreign
currency exchange rate swaps.
Foreign currency exchange rate swaps
Interest rate swaps
Total
Generation
Exelon Corporate
Exelon
$
$
268 $
620
888 $
— $
800
800 $
268
1,420
1,688
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Combined Notes to Consolidated Financial Statements - (Continued)
(Dollars in millions, except per share data unless otherwise noted)
The following table provides notional amounts outstanding held by Exelon and Generation at December 31, 2017 related to interest rate swaps and foreign
currency exchange rate swaps.
Foreign currency exchange rate swaps
Interest rate swaps (a)
Total
Generation
Exelon Corporate
Exelon
$
$
94 $
1
95 $
— $
—
— $
94
1
95
__________
(a) On July 1, 2018, Exelon and Generation de-designated its fair value and cash flow hedges. The table excludes amounts of $800 million of fixed-to-floating hedges that
were previously designated as fair value hedges by Exelon and $636 million of floating-to-fixed hedges that were previously designated as cash flow hedges by Exelon
and Generation as of December 31, 2017.
For the years ended December 31, 2018 , 2017 and 2016 , Exelon and Generation recognized the following net pre-tax mark-to-market gains (losses) in the
Consolidated Statements of Operations and Comprehensive Income and are included in “Net fair value changes related to derivatives” in Exelon’s and
Generation’s Consolidated Statements of Cash Flows.
Generation
Generation
Generation
Total Generation
Exelon
Exelon
Exelon
Total Exelon
Income Statement Location
Operating Revenues
Purchased Power and Fuel
Interest Expense
Income Statement Location
Operating Revenues
Purchased Power and Fuel
Interest Expense
Fair Value Hedges (Interest Rate Risk)
2018
2018
For the Years Ended December 31,
2017
Gain (Loss)
2016
7 $
(9)
(7)
(9) $
(6) $
—
(3)
(9) $
For the Years Ended December 31,
2017
Gain (Loss)
2016
7 $
(9)
(4)
(6) $
(6) $
—
(3)
(9) $
(10)
—
—
(10)
(10)
—
—
(10)
$
$
$
$
For derivative instruments that qualify and are designated as fair value hedges, the gain or loss on the derivative as well as the offsetting loss or gain on the
hedged item attributable to the hedged risk are recognized in earnings immediately. Exelon had no fixed-to-floating swaps designated as fair value hedges as of
December 31, 2018 and had $800 million notional amounts designated as fair value hedges as of December 31, 2017 . Exelon and Generation include the gain
or loss on the hedged items and the offsetting loss or gain on the related interest rate swaps as follows:
2018
2017
2016
2018
2017
2016
Year Ended December 31,
Exelon
Income Statement Location
Interest expense
$
(11) $
(13) $
(9) $
20 $
28 $
23
Loss on Swaps
Gain on Borrowings
During the years ended December 31, 2018 , 2017 and 2016 , the impact on the results of operations due to ineffectiveness from fair value hedges were gains
of $9 million , $15 million and $14 million , respectively.
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Cash Flow Hedges (Interest Rate Risk)
Combined Notes to Consolidated Financial Statements - (Continued)
(Dollars in millions, except per share data unless otherwise noted)
For derivative instruments that qualify and are designated as cash flow hedges, the gain or loss on the effective portion of the derivative will be deferred in AOCI
and reclassified into earnings when the underlying transaction occurs. Exelon and Generation have no floating-to-fixed swaps designated as cash flow hedges
as of December 31, 2018 , and had $636 million notional amounts designated as cash flow hedges as of December 31, 2017 .
The tables below provide the activity of OCI related to cash flow hedges for the years ended December 31, 2018 and 2017 , containing information about the
changes in the fair value of cash flow hedges and the reclassification from AOCI into results of operations. The amounts reclassified from AOCI, when combined
with the impacts of the hedged transactions, result in the ultimate recognition of net revenues or expenses at the contractual price.
For the Year Ended December 31, 2018
Income Statement Location
AOCI derivative loss at December 31, 2017
Effective portion of changes in fair value
Reclassifications from AOCI to net income
AOCI derivative loss at December 31, 2018
Interest expense
For the Year Ended December 31, 2017
Income Statement Location
AOCI derivative loss at December 31, 2016
Effective portion of changes in fair value
Reclassifications from AOCI to net income
AOCI derivative loss at December 31, 2017
Interest expense
__________
(a) Amount is net of related income tax expense of $1 million for the year ended December 31, 2017 .
Total Cash Flow Hedge AOCI Activity, Net of Income Tax
Generation
Total Cash
Flow Hedges
Exelon
Total Cash
Flow Hedges
$
$
(16)
11
1
(4)
$
$
(14)
11
1
(2)
Total Cash Flow Hedge AOCI Activity, Net of Income Tax
Generation
Total Cash
Flow Hedges
Exelon
Total Cash
Flow Hedges
$
$
(19)
(1)
4 (a)
(16)
$
$
(17)
(1)
4 (a)
(14)
During the years ended December 31, 2018 , 2017 and 2016 , the impact on the results of operations as a result of ineffectiveness from cash flow hedges was
immaterial. The estimated amount of existing gains and losses that are reported in AOCI at the reporting date that are expected to be reclassified into earnings
within the next twelve months is immaterial.
Proprietary Trading (Interest Rate and Foreign Exchange Risk)
Generation also executes derivative contracts for proprietary trading purposes to hedge risk associated with the interest rate and foreign exchange components
of underlying commodity positions. 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 “Net fair value changes related to derivatives” in Exelon’s and
Generation’s Consolidated Statements of Cash Flows. For the years ended December 31, 2018 , 2017 and 2016 , Exelon and Generation recognized the
following net pre-tax commodity mark-to-market gains (losses).
Income Statement Location
Operating revenues
For the Years Ended December 31,
2018
2017
Loss
2016
$
— $
(1) $
(1)
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Combined Notes to Consolidated Financial Statements - (Continued)
(Dollars in millions, except per share data unless otherwise noted)
Credit Risk, Collateral and Contingent-Related Features (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. For commodity derivatives, Generation
enters into enabling agreements that allow for payment netting with its counterparties, which reduces Generation’s exposure to counterparty risk by providing for
the offset of amounts payable to the counterparty against amounts receivable from the counterparty. Typically, each enabling agreement is for a specific
commodity and so, with respect to each individual counterparty, netting is limited to transactions involving that specific commodity product, except where master
netting agreements exist with a counterparty that allow for cross product netting. In addition to payment netting language in the enabling agreement,
Generation’s credit department establishes credit limits, margining thresholds and collateral requirements for each counterparty, which are defined in the
derivative contracts. Counterparty credit limits are based on an internal credit review process that considers a variety of factors, including the results of a scoring
model, leverage, liquidity, profitability, credit ratings by credit rating agencies, and risk management capabilities. To the extent that a counterparty’s margining
thresholds are exceeded, the counterparty is required to post collateral with Generation as specified in each enabling agreement. Generation’s credit department
monitors current and forward credit exposure to counterparties and their affiliates, both on an individual and an aggregate basis.
The following tables provide information on Generation’s credit exposure for all derivative instruments, NPNS, and applicable payables and receivables, net of
collateral and instruments that are subject to master netting agreements, as of December 31, 2018 . 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. Additionally, the figures in the tables below exclude exposures with affiliates, including net receivables with ComEd, PECO, BGE, Pepco,
DPL and ACE of $43 million , $30 million , $24 million , $28 million , $7 million and $5 million as of December 31, 2018 , respectively.
Total
Exposure
Before Credit
Collateral
Credit
Collateral (a)
Net
Exposure
Number of
Counterparties
Greater than 10%
of Net Exposure
Net Exposure of
Counterparties
Greater than 10%
of Net Exposure
Rating as of December 31, 2018
Investment grade
Non-investment grade
No external ratings
Internally rated — investment grade
Internally rated — non-investment grade
Total
$
$
$
795
133
181
92
— $
45
1
6
795
88
180
86
1,201
$
52 $
1,149
1 $
—
—
—
1 $
$
$
153
—
—
—
153
12
737
324
76
1,149
December 31, 2018
Net Credit Exposure by Type of Counterparty
Financial institutions
Investor-owned utilities, marketers, power producers
Energy cooperatives and municipalities
Other
Total
__________
(a) As of December 31, 2018 , credit collateral held from counterparties where Generation had credit exposure included $17 million of cash and $35 million of letters of credit.
The credit collateral does not include non-liquid collateral.
ComEd’s power procurement contracts provide suppliers with a certain amount of unsecured credit. The credit position is based on daily, updated forward
market prices compared to the benchmark prices. The benchmark prices are the forward prices of energy projected through the contract term and are set at the
point of supplier bid submittals. If the forward market price of energy exceeds the benchmark price on a given day, the suppliers are required to
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Table of Contents
Combined Notes to Consolidated Financial Statements - (Continued)
(Dollars in millions, except per share data unless otherwise noted)
post collateral for the secured credit portion after adjusting for any unpaid deliveries and unsecured credit allowed under the contract. The unsecured credit used
by the suppliers represents ComEd’s net credit exposure. The unsecured credit used by the suppliers represents ComEd’s net credit exposure. As of
December 31, 2018 , ComEd’s net credit exposure to suppliers was immaterial.
ComEd is permitted to recover its costs of procuring energy through the Illinois Settlement Legislation. ComEd’s counterparty credit risk is mitigated by its ability
to recover realized energy costs through customer rates. See Note 4 — Regulatory Matters for additional information.
PECO’s unsecured credit used by electric suppliers represents PECO’s net credit exposure. As of December 31, 2018 , PECO had no material net credit
exposure to electric suppliers.
PECO’s natural gas procurement plan is reviewed and approved annually on a prospective basis by the PAPUC. PECO’s counterparty credit risk under its
natural gas supply and asset management agreements is mitigated by its ability to recover its natural gas costs through the PGC, which allows PECO to adjust
rates quarterly to reflect realized natural gas prices. As of December 31, 2018 , PECO had no material credit exposure under its natural gas supply and asset
management agreements with investment grade suppliers.
BGE is permitted to recover its costs of procuring energy through the MDPSC-approved procurement tariffs. BGE’s counterparty credit risk is mitigated by its
ability to recover realized energy costs through customer rates. See Note 4 — Regulatory Matters for additional information.
BGE’s full requirement wholesale electric power agreements that govern the terms of its electric supply procurement contracts, which define a supplier’s
performance assurance requirements, allow a supplier, or its guarantor, to meet its credit requirements with a certain amount of unsecured credit. As of
December 31, 2018 , BGE had no material net credit exposure to suppliers.
BGE’s regulated gas business is exposed to market-price risk. At December 31, 2018 , BGE had credit exposure of $3 million related to off-system sales which
is mitigated by parental guarantees, letters of credit, or right to offset clauses within other contracts with those third-party suppliers.
Pepco’s, DPL's and ACE's power procurement contracts provide suppliers with a certain amount of unsecured credit. The amount of unsecured credit is
determined based on the supplier’s lowest credit rating from the major credit rating agencies and the supplier’s tangible net worth. The credit position is based
on the initial market price, which is the forward price of energy on the day a transaction is executed, compared to the current forward price curve for energy. To
the extent that the forward price curve for energy exceeds the initial market price, the supplier is required to post collateral to the extent the credit exposure is
greater than the supplier’s unsecured credit limit. The unsecured credit used by the suppliers represents Pepco’s, DPL's and ACE's net credit exposure. As of
December 31, 2018 , Pepco’s, DPL's and ACE's net credit exposures to suppliers were immaterial.
Pepco is permitted to recover its costs of procuring energy through the MDPSC-approved and DCPSC-approved procurement tariffs. DPL is permitted to recover
its costs of procuring energy through the MDPSC-approved and DPSC-approved procurement tariffs. ACE is permitted to recover its costs of procuring energy
through the NJBPU-approved procurement tariffs. Pepco’s, DPL's and ACE's counterparty credit risks are mitigated by their ability to recover realized energy
costs through customer rates. See Note 4 — Regulatory Matters for additional information.
DPL’s natural gas procurement plan is reviewed and approved annually on a prospective basis by the DPSC. DPL’s counterparty credit risk under its natural gas
supply and asset management agreements is mitigated by its ability to recover its natural gas costs through the GCR, which allows DPL to adjust rates annually
to reflect realized natural gas prices. To the extent that the fair value of the transactions in a net loss position exceeds the unsecured credit threshold, then
collateral is required to be posted in an amount equal to the amount by which the unsecured credit threshold is exceeded. Exchange-traded contracts are
required to be fully collateralized without regard to the credit rating of the holder. As of December 31, 2018 , DPL's credit exposure under its natural gas supply
and asset management agreements was immaterial.
Collateral (All Registrants)
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.
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Combined Notes to Consolidated Financial Statements - (Continued)
(Dollars in millions, except per share data unless otherwise noted)
Generation also enters into commodity transactions on exchanges where the exchanges act as the counterparty to each trade. Transactions on the exchanges
must adhere to comprehensive collateral and margining requirements. This collateral may be posted in the form of cash or credit support with thresholds
contingent upon Generation’s credit rating from each of the major credit rating agencies. The collateral and credit support requirements vary by contract and by
counterparty. These credit-risk related contingent features stipulate that if Generation were to be downgraded or lose its investment grade credit rating (based on
its senior unsecured debt rating), it would be required to provide additional collateral. This incremental collateral requirement allows for the offsetting of derivative
instruments that are assets with the same counterparty, where the contractual right of offset exists under applicable master netting agreements. In the absence
of expressly agreed-to provisions that specify the collateral that must be provided, collateral requested will be a function of the facts and circumstances of the
situation at the time of the demand. In this case, Generation believes an amount of several months of future payments (i.e., capacity payments) rather than a
calculation of fair value is the best estimate for the contingent collateral obligation, which has been factored into the disclosure below.
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 Feature
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)
For the Years Ended December 31,
2018
2017
$
$
(1,723) $
1,105
(618) $
(926)
577
(349)
__________
(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.
Generation had cash collateral posted of $418 million and letters of credit posted of $367 million , and cash collateral held of $47 million and letters of credit held
of $44 million as of December 31, 2018 for external counterparties with derivative positions. Generation had cash collateral posted of $497 million and letters of
credit posted of $293 million and cash collateral held of $35 million and letters of credit held of $33 million at December 31, 2017 for external counterparties with
derivative positions. In the event of a credit downgrade below investment grade (i.e., to BB+ by S&P or Ba1 by Moody's), Generation would have been required
to post additional collateral of $2.1 billion and $1.8 billion as of December 31, 2018 and 2017 , respectively. These amounts represent the potential additional
collateral required after giving consideration to offsetting derivative and non-derivative positions under master netting agreements.
Generation’s and Exelon’s interest rate swaps contain provisions that, in the event of a merger, if Generation’s debt ratings were to materially weaken, it would
be in violation of these provisions, resulting in the ability of the counterparty to terminate the agreement prior to maturity. Collateralization would not be required
under any circumstance. Termination of the agreement could result in a settlement payment by Exelon or the counterparty on any interest rate swap in a net
liability position. The settlement amount would be equal to the fair value of the swap on the termination date. As of December 31, 2018 , Generation’s and
Exelon's swaps were in an asset position with a fair value of $7 million and $3 million , respectively.
See Note 24 — Segment Information for additional information regarding the letters of credit supporting the cash collateral.
Generation entered into supply forward contracts with certain utilities, including PECO and BGE, with one-sided collateral postings only 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,
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Table of Contents
Combined Notes to Consolidated Financial Statements - (Continued)
(Dollars in millions, except per share data unless otherwise noted)
counterparty suppliers, including Generation, are required to post collateral once certain unsecured credit limits are exceeded. Under the terms of ComEd’s
standard block energy contracts, collateral postings are one-sided from suppliers, including Generation, should exposures between market prices and
benchmark prices exceed established unsecured credit limits outlined in the contracts. As of December 31, 2018 , ComEd held approximately $38 million in
collateral from suppliers in association with energy procurement contracts. Under the terms of ComEd's ZEC contracts, collateral postings are required to cover
a percentage of the ZEC contract value. ComEd’s REC contracts require collateral postings that are either a fixed price per REC or a percentage of the REC
contract value. As of December 31, 2018 , ComEd held approximately $31 million in collateral from suppliers for REC and ZEC contract obligations. Under the
terms of ComEd’s long-term renewable energy contracts, collateral postings are required from suppliers for both RECs and energy. The REC portion is a fixed
value and the energy portion is one-sided from suppliers should the forward market prices exceed contract prices. As of December 31, 2018 , ComEd held
approximately $19 million in collateral from suppliers for the long-term renewable energy contracts. If ComEd lost its investment grade credit rating as of
December 31, 2018 , it would have been required to post approximately $7 million of collateral to its counterparties. See Note 4 — Regulatory Matters for
additional information.
PECO’s natural gas procurement contracts contain provisions that could require PECO to post collateral. This collateral may be posted in the form of cash or
credit support with thresholds contingent upon PECO’s credit rating from the major credit rating agencies. The collateral and credit support requirements vary by
contract and by counterparty. As of December 31, 2018 , PECO was not required to post collateral for any of these agreements. If PECO lost its investment
grade credit rating as of December 31, 2018 , PECO could have been required to post approximately $39 million of collateral to its counterparties.
PECO’s supplier master agreements that govern the terms of its DSP Program contracts do not contain provisions that would require PECO to post collateral.
BGE’s natural gas procurement contracts contain provisions that could require BGE to post collateral. This collateral may be posted in the form of cash or credit
support with thresholds contingent upon BGE’s credit rating from the major credit rating agencies. The collateral and credit support requirements vary by
contract and by counterparty. As of December 31, 2018 , BGE was not required to post collateral for any of these agreements. If BGE lost its investment grade
credit rating as of December 31, 2018 , BGE could have been required to post approximately $69 million of collateral to its counterparties.
DPL's natural gas procurement contracts contain provisions that could require DPL to post collateral. To the extent that the fair value of the natural gas
derivative transaction in a net loss position exceeds the unsecured credit threshold, then collateral is required to be posted in an amount equal to the amount by
which the unsecured credit threshold is exceeded. The DPL obligations are standalone, without the guaranty of PHI. If DPL lost its investment grade credit rating
as of December 31, 2018 , DPL could have been required to post an additional amount of approximately $11 million of collateral to its natural gas counterparties.
BGE's, Pepco's, DPL's and ACE’s full requirements wholesale power agreements that govern the terms of its electric supply procurement contracts do not
contain provisions that would require BGE, Pepco, DPL or ACE to post collateral.
13. Debt and Credit Agreements (All Registrants)
Short-Term Borrowings
Exelon Corporate, ComEd, BGE, Pepco, DPL and ACE 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. 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.
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Commercial Paper
Combined Notes to Consolidated Financial Statements - (Continued)
(Dollars in millions, except per share data unless otherwise noted)
The following table reflects the Registrants' commercial paper programs supported by the revolving credit agreements and bilateral credit agreements at
December 31, 2018 and 2017 :
Commercial Paper Issuer
Exelon Corporate
Generation
ComEd
PECO
BGE
Pepco
DPL
ACE
Total
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,
2018 (a)(b)(c)
2017 (a)(b)(c)
2018
2017
2018
2017
$
600 $
600 $
— $
5,300
1,000
600
600
300
300
300
5,300
1,000
600
600
500
500
350
—
—
—
35
40
—
14
$
9,000
$
9,450
$
89
$
—
—
—
—
77
26
216
108
427
1.93%
1.96%
2.14%
2.24%
2.18%
2.24%
2.07%
2.21%
1.16%
1.23%
1.24%
1.13%
1.28%
1.06%
1.48%
1.43%
__________
(a) Excludes $545 million and $480 million in bilateral credit facilities at December 31, 2018 and 2017 , respectively, and $159 million and $179 million in credit facilities for
project finance at December 31, 2018 and 2017 , respectively. These credit facilities do not back Generation's commercial paper program.
(b) 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. These facilities expire on
October 11, 2019. These facilities are solely utilized to issue letters of credit. At December 31, 2017, excludes $128 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 , $34 million , $34 million , $5
million , $2 million , $2 million , and $2 million , respectively.
(c) Pepco, DPL and ACE's revolving credit facility is subject to available borrowing capacity. 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.
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. While the amount of outstanding commercial paper does not reduce available capacity under a
Registrant’s credit facility, a Registrant does not issue commercial paper in an aggregate amount exceeding the then available capacity under its credit facility.
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Table of Contents
Combined Notes to Consolidated Financial Statements - (Continued)
(Dollars in millions, except per share data unless otherwise noted)
At December 31, 2018 , the Registrants had the following aggregate bank commitments, credit facility borrowings and available capacity under their respective
credit facilities:
Available Capacity at December 31, 2018
Facility Type
Aggregate Bank
Commitment (a)
Facility Draws
Outstanding
Letters of Credit
Actual
Syndicated Revolver
$
600 $
— $
Syndicated Revolver
Bilaterals
Project Finance
Syndicated Revolver
Syndicated Revolver
Syndicated Revolver
Syndicated Revolver
Syndicated Revolver
Syndicated Revolver
5,300
545
159
1,000
600
600
300
300
300
—
—
—
—
—
—
—
—
—
9 $
591 $
1,203
4,097
353
119
2
—
1
8
1
—
192
40
998
600
599
292
299
300
To Support
Additional
Commercial
Paper (b)
591
4,097
—
—
998
600
564
252
299
286
$
9,704 $
— $
1,696 $
8,008 $
7,687
Borrower
Exelon Corporate
Generation
Generation
Generation
ComEd
PECO
BGE
Pepco
DPL
ACE
Total
__________
(a) 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. These facilities expire on October 11, 2019. These
facilities are solely utilized to issue letters of credit. As of December 31, 2018 , letters of credit issued under these facilities totaled $5 million and $2 million for Generation
and BGE, respectively.
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Table of Contents
Combined Notes to Consolidated Financial Statements - (Continued)
(Dollars in millions, except per share data unless otherwise noted)
The following tables present the short-term borrowings activity for Exelon, Generation, ComEd, PECO, BGE, PHI, Pepco, DPL and ACE during 2018 , 2017 and
2016 .
Exelon
Average borrowings
Maximum borrowings outstanding
Average interest rates, computed on a daily basis
Average interest rates, at December 31
Generation
Average borrowings
Maximum borrowings outstanding
Average interest rates, computed on a daily basis
Average interest rates, at December 31
ComEd
Average borrowings
Maximum borrowings outstanding
Average interest rates, computed on a daily basis
Average interest rates, at December 31
PECO
Average borrowings
Maximum borrowings outstanding
Average interest rates, computed on a daily basis
Average interest rates, at December 31
BGE
Average borrowings
Maximum borrowings outstanding
Average interest rates, computed on a daily basis
Average interest rates, computed at December 31
2018
2017
2016
$
531
$
823
$
1,237
2.21%
2.15%
2,147
1.32%
1.24%
2018
2017
2016
$
37
$
405
$
583
1.96%
1.96%
1,455
1.23%
1.23%
1,125
3,076
0.88%
1.12%
536
1,735
0.94%
1.14%
$
$
$
2018
2017
2016
$
154
520
2.14%
2.14%
$
200
470
1.24%
1.24%
2018
2017
2016
68
$
350
2.24%
2.24%
$
2
60
1.13%
1.13%
2018
2017
2016
65
$
54
$
239
2.18%
2.18%
165
1.28%
1.28%
256
755
0.77%
N/A
—
—
N/A
N/A
143
369
0.77%
0.95%
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Table of Contents
PHI Corporate
Combined Notes to Consolidated Financial Statements - (Continued)
(Dollars in millions, except per share data unless otherwise noted)
Average borrowings
Maximum borrowings outstanding
Average interest rates, computed on a daily basis
Average interest rates, computed at December 31
Pepco
Average borrowings
Maximum borrowings outstanding
Average interest rates, computed on a daily basis
Average interest rates, computed at December 31
DPL
Average borrowings
Maximum borrowings outstanding
Average interest rates, computed on a daily basis
Average interest rates, computed at December 31
ACE
Average borrowings
Maximum borrowings outstanding
Average interest rates, computed on a daily basis
Average interest rates, computed at December 31
Short-Term Loan Agreements
2018
2017
2016
N/A
N/A
N/A
N/A
N/A $
N/A
N/A
N/A
$
$
$
2018
2017
2016
$
22
90
2.24%
2.24%
51
$
197
1.06%
1.06%
2018
2017
2016
87
$
40
$
245
2.07%
2.07%
216
1.48%
1.48%
2018
2017
2016
95
$
30
$
210
2.21%
2.21%
133
1.43%
1.43%
153
559
1.03%
N/A
4
73
0.71%
0.90%
33
116
0.68%
N/A
—
5
0.65%
N/A
On January 13, 2016, PHI entered into a $500 million term loan agreement, which was amended on March 28, 2016. The net proceeds of the loan were used to
repay PHI's outstanding commercial paper, and for general corporate purposes. Pursuant to the loan agreement, as amended, loans made thereunder bear
interest at a variable rate equal to LIBOR plus 1% , and all indebtedness thereunder is unsecured. On March 23, 2017, the aggregate principal amount of all
loans, together with any accrued but unpaid interest due under the loan agreement was fully repaid and the loan terminated. On March 23, 2017, Exelon
Corporate entered into a similar type term loan for $500 million which expired on March 22, 2018. The loan agreement was renewed on March 22, 2018 and will
expire on March 21, 2019. Pursuant to the loan agreement, loans made thereunder bear interest at a variable rate equal to LIBOR plus 1% and all indebtedness
thereunder is unsecured. The loan agreement is reflected in Exelon's Consolidated Balance Sheet within Short-Term borrowings.
On May 23, 2018, ACE entered into two term loan agreements in the aggregate amount of $ 125 million , which expire on May 22, 2019. Pursuant to the term
loan agreements, loans made thereunder bear interest at a variable rate equal to LIBOR plus 0.55% and all indebtedness thereunder is unsecured.
Credit Agreements
On January 5, 2016, Generation entered into a credit agreement establishing a $150 million bilateral credit facility. On January 4, 2019, the credit agreement
was amended to extend its maturity from January 2019 to April 2021.
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Table of Contents
Combined Notes to Consolidated Financial Statements - (Continued)
(Dollars in millions, except per share data unless otherwise noted)
This facility will solely be utilized by Generation to issue lines of credit. This facility does not back Generation's commercial paper program.
On April 1, 2016, the credit agreement for CENG's $100 million bilateral credit facility was amended to increase the overall facility size to $200 million ,
scheduled to mature in October of 2019. This facility is utilized by CENG to fund working capital and capital projects. The facility does not back Generation's
commercial paper program.
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.
On January 9, 2017, the credit agreement for Generation's $75 million bilateral credit facility was amended and restated to increase the facility size to $100
million . On January 4, 2019, the credit agreement was amended to extend its maturity from January 2019 to March 2021. This facility will solely be used by
Generation to issue letters of credit.
On March 15, 2018, the credit agreement for a Generation bilateral credit facility of $30 million was amended to increase the overall facility size to $95 million ,
scheduled to mature in March of 2020. This facility will solely be used by Generation to issue letters of credit.
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
The maximum adders for prime rate borrowings and LIBOR-based rate borrowings are 90 basis points and 165 basis points, respectively. The credit agreements
also require the borrower to pay a facility fee based upon the aggregate commitments. The fee varies depending upon the respective credit ratings of the
borrower.
Each revolving credit agreement for Exelon, Generation, ComEd, PECO, BGE, Pepco, DPL and ACE requires the affected borrower to maintain a minimum
cash from operations to interest expense ratio for the twelve-month period ended on the last day of any quarter. The following table summarizes the minimum
thresholds reflected in the credit agreements for the year ended December 31, 2018 :
Credit agreement threshold
2.50 to 1
3.00 to 1
2.00 to 1
Exelon
Generation
ComEd
PECO
2.00 to 1
BGE
2.00 to 1
Pepco
2.00 to 1
DPL
2.00 to 1
ACE
2.00 to 1
At December 31, 2018 , the interest coverage ratios at the Registrants were as follows:
Interest coverage ratio
Exelon
7.34
Generation
10.99
ComEd
7.34
PECO
8.14
BGE
9.77
Pepco
5.98
DPL
7.03
ACE
5.06
An event of default under Exelon, Generation, ComEd, PECO or BGE's indebtedness will not constitute an event of default under any of the others’ credit
facilities, except that a bankruptcy or other event of default in the payment of principal, premium or indebtedness in principal amount in excess of $100 million in
the aggregate by Generation
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Table of Contents
Combined Notes to Consolidated Financial Statements - (Continued)
(Dollars in millions, except per share data unless otherwise noted)
will constitute an event of default under the Exelon Corporate credit facility. An event of default under Pepco, DPL or ACE's indebtedness will not constitute an
event of default with respect to the other PHI Utilities under the PHI Utilities' combined credit facility.
The absence of a material adverse change in Exelon's or PHI’s business, property, results of operations or financial condition is not a condition to the availability
of credit under any of the borrowers' credit agreement. None of the credit agreements include any rating triggers.
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, bonds submitted for purchase are remarketed by a remarketing agent on
a best efforts basis. PHI expects that any bonds submitted for purchase will be remarketed successfully due to the creditworthiness of the issuer and, as
applicable, the credit support, and because the remarketing resets the interest rate to the then-current market rate. The 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, 2018 and December 31, 2017 , $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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Table of Contents
Long-Term Debt
Combined Notes to Consolidated Financial Statements - (Continued)
(Dollars in millions, except per share data unless otherwise noted)
The following tables present the outstanding long-term debt at the Registrants as of December 31, 2018 and 2017 :
Exelon
Long-term debt
First mortgage bonds (a)
Senior unsecured notes
Unsecured notes
Pollution control notes
Nuclear fuel procurement contracts
Notes payable and other (b)(c)
Junior subordinated notes
Long-term software licensing agreement
Unsecured Tax-Exempt Bonds
Medium-Terms Notes (unsecured)
Transition bonds
Loan Agreement
Nonrecourse debt:
Fixed rates
Variable rates (f)
Total long-term debt
Unamortized debt discount and premium, net
Unamortized debt issuance costs
Fair value adjustment
Long-term debt due within one year (e)
Long-term debt
Long-term debt to financing trusts (d)
Subordinated debentures to ComEd Financing III
Rates
1.70% -
2.45% -
2.40% -
2.50% -
2.85% -
1.74% -
7.61% -
2.29% -
Subordinated debentures to PECO Trust III
7.38% -
Subordinated debentures to PECO Trust IV
Total long-term debt to financing trusts
Unamortized debt issuance costs
Long-term debt to financing trusts
7.90%
7.60%
6.35%
2.70%
3.15%
8.88%
3.50%
3.95%
5.40% —
7.72%
5.55%
2.00%
6.00%
5.81%
6.35%
7.50%
5.75%
Maturity
Date
December 31,
2018
2017
2019 - 2048
2019 - 2046
2021 - 2048
2025 - 2036
2020
2019 - 2053
2022
2024
2024 - 2031
2019 - 2027
2023
2023
2031 - 2037
2019 - 2024
16,496
11,285
2,900
435
39
188
15,197
11,285
2,600
435
82
405
1,150
1,150
73
112
22
59
50
1,253
849
34,911
(66)
(216)
795
(1,349)
79
112
26
90
—
1,331
865
33,657
(57)
(201)
865
(2,088)
32,176
206
81
103
390
(1)
389
$
34,075 $
2033 $
206 $
2028
2033
81
103
390
—
$
390 $
__________
(a) Substantially all of ComEd’s assets other than expressly excepted property and substantially all of PECO’s, Pepco's, DPL's and ACE's assets are subject to the liens of
(b)
their respective mortgage indentures.
Includes capital lease obligations of $36 million and $53 million at December 31, 2018 and 2017 , respectively. Lease payments of $21 million , $5 million , $1 million , $1
million , less than $1 million, and $8 million will be made in 2019 , 2020 , 2021 , 2022 , 2023 , and thereafter, respectively.
Includes financing related to Albany Green Energy, LLC (AGE). During the third quarter of 2017, Generation retired $228 million of its outstanding debt balance.
(c)
(d) Amounts owed to these financing trusts are recorded as Long-term debt to financing trusts within Exelon’s Consolidated Balance Sheets.
(e)
(f) Excludes interest on CEU Upstream nonrecourse debt, see discussion below.
In January 2019, $300 million of ComEd long-term debt due within one year was paid in full.
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Table of Contents
Generation
Combined Notes to Consolidated Financial Statements - (Continued)
(Dollars in millions, except per share data unless otherwise noted)
Long-term debt
Senior unsecured notes
Pollution control notes
Nuclear fuel procurement contracts
Notes payable and other (a)(b)
Nonrecourse debt:
Fixed rates
Variable rates (c)
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,
2018
2017
2.95% -
2.50% -
2.85% -
2.29% -
7.60%
2.70%
3.15%
7.83%
6.00%
5.81%
2019 - 2042 $
6,019 $
6,019
2025 - 2036
2020
2019 - 2024
2031 - 2037
2019 - 2024
435
39
164
1,253
849
8,759
(6)
(51)
91
(906)
435
82
223
1,331
865
8,955
(8)
(60)
103
(346)
$
7,887 $
8,644
__________
(a)
Includes Generation’s capital lease obligations of $14 million and $18 million at December 31, 2018 and 2017 , respectively. Generation will make lease payments of $7
million , $5 million , $1 million , and $1 million in 2019 , 2020 , 2021 , and 2022 , respectively. Lease payments of less than $1 million annually will be made from 2023
through expiration of the final capital lease in 2024.
Includes financing related to Albany Green Energy, LLC (AGE). During the third quarter of 2017, Generation retired $228 million of its outstanding debt balance.
(b)
(c) Excludes interest on CEU Upstream nonrecourse debt, see discussion below.
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Table of Contents
ComEd
Combined Notes to Consolidated Financial Statements - (Continued)
(Dollars in millions, except per share data unless otherwise noted)
Long-term debt
First mortgage bonds (a)
Notes payable and other (b)
Total long-term debt
Unamortized debt discount and premium, net
Unamortized debt issuance costs
Long-term debt due within one year (d)
Long-term debt
Long-term debt to financing trust (c)
Subordinated debentures to ComEd Financing III
Total long-term debt to financing trusts
Unamortized debt issuance costs
Long-term debt to financing trusts
Rates
2.15% -
6.45%
7.49%
Maturity
Date
December 31,
2018
2017
2019 - 2048 $
8,179 $
2053
8
8,187
(23)
(63)
(300)
$
7,801 $
7,529
147
7,676
(23)
(52)
(840)
6,761
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)
Includes ComEd’s capital lease obligations of $8 million at both December 31, 2018 and 2017 , respectively. Lease payments of less than $1 million annually will be made
from 2019 through expiration at 2053.
(c) Amount owed to this financing trust is recorded as Long-term debt to financing trust within ComEd’s Consolidated Balance Sheets.
(d)
In January 2019, the $300 million balance was paid in full.
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 due within one year
Long-term debt
Long-term debt to financing trusts (b)
Subordinated debentures to PECO Trust III
Subordinated debentures to PECO Trust IV
Long-term debt to financing trusts
Rates
Maturity
Date
December 31,
2018
2017
1.70% -
5.95%
2021 - 2048 $
3,075 $
2,925
2.00% 2023
7.38% -
7.50%
5.75%
50
3,125
(18)
(23)
—
$
3,084 $
2028 $
2033
$
81 $
103
184 $
0
2,925
(5)
(17)
(500)
2,403
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.
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Table of Contents
BGE
Long-term debt
Unsecured notes
Total long-term debt
Unamortized debt discount and premium, net
Unamortized debt issuance costs
Long-term debt
PHI
Long-term debt
First mortgage bonds (a)
Senior unsecured notes
Unsecured Tax-Exempt Bonds
Medium-terms notes (unsecured)
Transition bonds (b)
Notes payable and other (c)
Total long-term debt
Unamortized debt discount and premium, net
Unamortized debt issuance costs
Fair value adjustment
Long-term debt due within one year
Long-term debt
Combined Notes to Consolidated Financial Statements - (Continued)
(Dollars in millions, except per share data unless otherwise noted)
Rates
Maturity
Date
December 31,
2018
2017
2.40% -
6.35%
2021 - 2048
2,900
2,900
(6)
(18)
2,600
2,600
(6)
(17)
$
2,876 $
2,577
Rates
Maturity
Date
December 31,
2018
2017
1.81% -
1.74% -
7.61% -
7.28% -
7.90%
7.45%
5.40%
7.72%
5.55%
8.88%
2021 - 2048 $
5,242 $
4,743
2032
2024 - 2031
2019 - 2027
2023
2019 - 2022
185
112
22
59
16
185
112
26
90
33
5,636
5,189
4
(14)
633
(125)
5
(6)
686
(396)
$
6,134
$
5,478
__________
(a) Substantially all of Pepco's, DPL's, and ACE's assets are subject to the lien of its respective mortgage indenture.
(b) Transition bonds are recorded as part of Long-term debt within ACE's Consolidated Balance Sheets.
(c)
Includes Pepco's capital lease obligations of $14 million and $27 million at December 31, 2018 and 2017 , respectively.
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Table of Contents
Pepco
Combined Notes to Consolidated Financial Statements - (Continued)
(Dollars in millions, except per share data unless otherwise noted)
Long-term debt
First mortgage bonds (a)
Notes payable and other (b)
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,
2018
2017
3.05% -
7.28% -
7.90%
8.88%
2022 - 2048 $
2,735 $
2,535
2019 - 2022
16
2,751
2
(34)
(15)
35
2,570
2
(32)
(19)
$
2,704
$
2,521
__________
(a) Substantially all of Pepco's assets are subject to the lien of its respective mortgage indenture.
(b)
Includes capital lease obligations of $14 million and $27 million at December 31, 2018 and 2017 , respectively. Lease payments of $14 million will be made in 2019 .
DPL
Long-term debt
First mortgage bonds (a)
Unsecured Tax-Exempt Bonds
Medium-terms notes (unsecured)
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,
2018
2017
1.81% -
1.74% -
7.61% -
4.27%
5.40%
7.72%
2023 - 2048 $
1,370 $
1,171
2024 - 2031
2019 - 2027
112
22
1,504
2
(12)
(91)
112
26
1,309
2
(11)
(83)
$
1,403
$
1,217
__________
(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)
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% -
6.80%
5.55%
Maturity
Date
December 31,
2018
2017
2021 - 2036 $
1,137 $
1,037
2023
59
1,196
(1)
(7)
(18)
$
1,170
$
90
1,127
(1)
(5)
(281)
840
__________
(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, 2018 are $18 million in 2019, $20 million in 2020 and $21 million in 2021.
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Combined Notes to Consolidated Financial Statements - (Continued)
(Dollars in millions, except per share data unless otherwise noted)
Long-term debt maturities at Exelon, Generation, ComEd, PECO, BGE, PHI, Pepco, DPL and ACE in the periods 2019 through 2023 and thereafter are as
follows:
Year
2019
2020
2021
2022
2023
3,528
1,511
3,084
850
Thereafter
Total
$
24,979 (a)
35,301
$
Exelon
Generation
ComEd
PECO
BGE
PHI
Pepco
DPL
ACE
$
1,349
$
906 $
2,108
1
1,024
—
4,720
8,759 $
$
300
500
350
—
—
—
—
300
350
50
7,243 (b)
8,393
$
2,609 (c)
3,309
$
— $
125 $
15 $
91 $
—
300
250
300
20
261
310
500
—
1
310
—
2,050
4,420
2,425
—
—
—
500
913
18
20
260
—
—
898
$
2,900
$
5,636
$
2,751
$
1,504
$
1,196
__________
(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.
Junior Subordinated Notes
In June 2014, Exelon issued $1.15 billion of junior subordinated notes in the form of 23 million equity units at a stated amount of $50.00 per unit. Each equity unit
represented an undivided beneficial ownership interest in Exelon’s $1.15 billion of 2.50% junior subordinated notes due in 2024 (“2024 notes”) and a forward
equity purchase contract. As contemplated in the June 2014 equity unit structure, in April 2017, Exelon completed the remarketing of the 2024 notes into $1.15
billion of 3.497% junior subordinated notes due in 2022 (“Remarketing”). Exelon conducted the Remarketing on behalf of the holders of equity units and did not
directly receive any proceeds therefrom. Instead, the former holders of the 2024 notes used debt remarketing proceeds towards settling the forward equity
purchase contract with Exelon on June 1, 2017. Exelon issued approximately 33 million shares of common stock from treasury stock and received $1.15 billion
upon settlement of the forward equity purchase contract. When reissuing treasury stock Exelon uses the average price paid to repurchase shares to calculate a
gain or loss on issuance and records gains or losses directly to retained earnings. A loss on reissuance of treasury shares of $1.05 billion was recorded to
retained earnings as of December 31, 2017. See Note 20 — Earnings Per Share for additional information on the issuance of common stock.
Nonrecourse Debt
Exelon and Generation have issued nonrecourse debt financing, in which approximately $2.9 billion of generating assets have been pledged as collateral at
December 31, 2018 . 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.
Denver Airport. In June 2011, Generation entered into a 20-year, $7 million solar loan agreement to finance a solar construction project in Denver, Colorado.
The agreement is scheduled to mature on June 30, 2031. The agreement bears interest at a fixed rate of 5.50% annually with interest payable annually. As of
December 31, 2018 , $ 6 million was outstanding.
CEU Upstream. In July 2011, CEU Holdings, LLC, a wholly owned subsidiary of Generation, entered into a 5-year reserve based lending agreement (RBL)
associated with certain Upstream oil and gas properties. The lenders do not have recourse against Exelon or Generation in the event of default pursuant to the
RBL. Borrowings under this arrangement are secured by the assets and equity of CEU Holdings.
In December 2016, substantially all of the Upstream natural gas and oil exploration and production assets were sold for $37 million . The proceeds were used to
reduce the debt balance by $31 million . The remaining proceeds
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Combined Notes to Consolidated Financial Statements - (Continued)
(Dollars in millions, except per share data unless otherwise noted)
of $6 million were being held in escrow. In addition, during 2016, $15 million of the debt was repaid using CEU Holding’s cash, resulting in an outstanding debt
balance of $22 million at December 31, 2016. During 2017, additional assets were sold for $1 million and the remaining $6 million in escrow was released and
applied to the debt balance resulting in an outstanding amount of $15 million at December 31, 2017. Upon final resolution, CEU Holdings will be released of its
obligations regardless of the amount of asset sale proceeds received. The ultimate resolution of this matter has no direct effect on any Exelon or Generation
credit facilities or other debt of an Exelon entity. At December 31, 2018 , the outstanding debt balance of $15 million was classified within Long term debt due
within one year in Exelon’s and Generation’s Consolidated Balance Sheets. See Note 5 — Mergers, Acquisitions and Dispositions and Note 7 — Impairment of
Long-Lived Assets and Intangibles for additional information.
Holyoke Solar Cooperative. In October 2011, Generation entered into a 20-year, $11 million solar loan agreement related to a solar construction project in
Holyoke, Massachusetts. The agreement is scheduled to mature on December 2031. The agreement bears interest at a fixed rate of 5.25% annually with
interest payable monthly. As of December 31, 2018 , $8 million was outstanding.
Antelope Valley Solar Ranch One. In December 2011, the DOE Loan Programs Office issued a guarantee for up to $646 million for 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, 2018 , $508 million was outstanding. In addition, Generation has issued letters of credit to support its equity investment in the
project. As of December 31, 2018 , 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.
Continental Wind. In September 2013, Continental Wind, LLC (Continental Wind), an indirect subsidiary of Exelon and Generation, completed the issuance
and sale of $613 million senior secured notes. Continental Wind owns and operates a portfolio of wind farms in Idaho, Kansas, Michigan, Oregon, New Mexico
and Texas with a total net capacity of 667 MW. The net proceeds were distributed to Generation for its general business purposes. The notes are scheduled to
mature on February 28, 2033. The notes bear interest at a fixed rate of 6.00% with interest payable semi-annually. As of December 31, 2018 , $479 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, 2018 , the Continental Wind letter of credit facility had $114
million in letters of credit outstanding related to the project.
In 2017, Generation’s interests in Continental Wind were contributed to EGRP. Refer to Note 2 - Variable Interest Entities for additional information on EGRP.
ExGen Texas Power. In September 2014, EGTP, an indirect subsidiary of Exelon and Generation, issued $675 million aggregate principal amount of a
nonrecourse senior secured term loan. The net proceeds were distributed to Generation for general business purposes. The loan was scheduled to mature on
September 18, 2021. In addition to the financing, EGTP entered into various interest rate swaps with an initial notional amount of approximately $505 million at
an interest rate of 2.34% to hedge a portion of the interest rate exposure in connection with this financing, as required by the debt covenants.
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, which permitted EGTP to draw on its revolving credit facility and initiate an orderly sales process of its assets. On November 7, 2017, the
debtors 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, Exelon and Generation deconsolidated the nonrecourse senior secured term loan, the revolving credit facility, and the interest rate swaps
from their consolidated financial statements as of December 31, 2017. Due to their nonrecourse nature, these borrowings are secured solely by the assets of
EGTP and its subsidiaries.
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Combined Notes to Consolidated Financial Statements - (Continued)
(Dollars in millions, except per share data unless otherwise noted)
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. See Note 5 — Mergers, Acquisitions and Dispositions for additional information on EGTP.
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, 2018 , $115 million was outstanding.
In 2017, Generation’s interests in Renewable Power Generation were contributed to EGRP. Refer to Note 2 - 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, 2018 , $137 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, 2018 , $834 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. See Note 2 - Variable interest Entities for additional information on EGRP.
14. Income Taxes (All Registrants)
Corporate Tax Reform (All Registrants)
On December 22, 2017, President Trump signed the TCJA into law. The TCJA makes many significant changes to the Internal Revenue Code, including, but not
limited to, (1) reducing the U.S. federal corporate tax rate from 35% to 21% ; (2) creating a 30% limitation on deductible interest expense (not applicable to
regulated utilities); (3) allowing 100% expensing for the cost of qualified property (not applicable to regulated utilities); (4) eliminating the domestic production
activities deduction; (5) eliminating the corporate alternative minimum tax and changing how existing alternative minimum tax credits can be realized; and (6)
changing rules related to uses and limitations of net operating loss carryforwards created in tax years beginning after December 31, 2017. The most significant
change that impacts the Registrants is the reduction of the corporate federal income tax rate from 35% to 21% beginning January 1, 2018.
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 amount and timing of potential settlements of the established net regulatory liabilities are determined by the Utility Registrants’ respective
rate regulators, subject to certain IRS “normalization” rules. See Note 4 — Regulatory Matters for additional information regarding settlements for passing back
of TCJA income tax savings benefits to customers.
374
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Combined Notes to Consolidated Financial Statements - (Continued)
(Dollars in millions, except per share data unless otherwise noted)
The Registrants assessed the applicable provisions in the TCJA and recorded the associated impacts as of December 31, 2017. The Registrants recorded
provisional income tax amounts as of December 31, 2017, as allowed under SAB 118 issued by the SEC in December 2017, for changes pursuant to the TCJA
related to depreciation because the impacts could not be finalized upon issuance of the Registrants’ financial statements, but for which reasonable estimates
could be determined.
On August 3, 2018, the U.S. Department of Treasury, in conjunction with the IRS, released proposed regulations clarifying the immediate expensing provisions
enacted by the TCJA, specifically that regulated utility property acquired after September 27, 2017, and placed in service by December 31, 2017, qualifies for
100% expensing. Until the proposed regulations are finalized, taxpayers may rely on the proposed regulations for tax years ending after September 28, 2017.
The Registrants recorded the impact of these proposed regulations and the adjustment was immaterial.
While the Registrants have recorded the impacts of the TCJA based on their interpretation of the provisions as enacted, it is expected the U.S. Department of
Treasury and the IRS will issue additional interpretative guidance in the future that could result in changes to previously finalized provisions. At this time, many of
the states in which Exelon does business have issued guidance regarding TCJA and the impact was not material.
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:
Exelon (b)
Generation
ComEd
PECO
BGE
PHI
Pepco
DPL
ACE
Successor
Net Decrease to Deferred
Income Tax Liability Balances
$8,624
$1,895
$2,819
$1,407
$1,120
$1,944
$968
$540
$456
Net Regulatory Liability
Recorded (a)
$7,315
N/A
$2,818
$1,394
$1,124
$1,979
$976
$545
$458
Exelon
Generation
ComEd
PECO (c)
BGE
PHI
Pepco
DPL
ACE
Successor
Exelon (b)
Generation
ComEd
PECO
BGE
PHI
Pepco
DPL
ACE
Successor
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
$1,895
$1,309
$(35)
$(8)
$(4)
$(2)
$(5)
$13
$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.
The net regulatory liabilities above include (1) amounts subject to IRS “normalization” rules that are required to be passed back to customers generally over the
remaining useful life of the underlying assets giving rise to the associated deferred income taxes, and (2) amounts for which the timing of settlement with
customers is subject to determinations by the rate regulators. The table below sets forth the Registrants’ estimated categorization of their net regulatory liabilities
as of December 31, 2017. The amounts in the table below are shown on an after-tax basis reflecting future net cash outflows after taking into consideration the
income tax benefits associated with the ultimate settlement with customers.
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Table of Contents
Combined Notes to Consolidated Financial Statements - (Continued)
(Dollars in millions, except per share data unless otherwise noted)
Subject to IRS Normalization Rules
Subject to Rate Regulator Determination
Net Regulatory Liabilities
Exelon
$3,040
1,694
$4,734
ComEd
$1,400
573
$1,973
PECO (a)
$533
43
$576
BGE
$459
324
$783
Successor
PHI
$648
754
$1,402
PEPCO
$299
391
$690
DPL
$195
194
$389
$
ACE
$153
170
323
_________
(a) Given the regulatory treatment of income tax benefits related to electric and gas distribution repairs, PECO was in an overall net regulatory asset position as of December
31, 2017 after recording the impacts related to the TCJA. As a result, the amount of customer benefits resulting from the TCJA subject to the discretion of PECO's rate
regulators are lower relative to the other Utility Registrants.
The net regulatory liability amounts subject to the IRS normalization rules generally relate to property, plant and equipment with remaining useful lives ranging
from 30 to 40 years across the Utility Registrants. For the other amounts, rate regulators could require the passing back of amounts to customers over shorter
time frames. See Note 4 - Regulatory Matters for additional information.
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
Exelon
Generation
ComEd
PECO
BGE
PHI
Pepco
DPL
ACE
For the Year Ended December 31, 2018
Successor
$
226 $
337 $
(63) $
11 $
(5) $
(4)
$
28 $
(3) $
(14)
(98)
(24)
(1)
17
(347)
(21)
6
(83)
145
(2)
(29)
117
10
—
1
(16)
47
—
—
32
24
(1)
7
9
(21)
—
—
6
13
—
—
12
$
120 $
(108) $
168 $
6 $
74 $
35 $
13 $
22 $
18
—
—
8
12
Exelon
Generation
ComEd
PECO
BGE
PHI
Pepco
DPL
ACE
For the Year Ended December 31, 2017 (a)
Successor
$
194 $
584 $
(191) $
71 $
74 $
(60) $
(20) $
(24) $
(12)
(471)
(25)
14
162
(2,005)
(21)
65
1
523
(2)
(49)
136
28
—
14
(9)
101
(1)
(5)
49
250
(1)
114
—
(4)
32
(2)
13
82
—
—
13
$
(126) $
(1,376) $
417 $
104 $
218 $
217 $
105 $
71 $
34
—
—
4
26
376
Table of Contents
Included in operations:
Federal
Current
Deferred
Investment tax credit
amortization
State
Current
Deferred
Total
Combined Notes to Consolidated Financial Statements - (Continued)
(Dollars in millions, except per share data unless otherwise noted)
For the Year Ended December 31, 2016 (a)
Successor
Predecessor
March 24, 2016 to
December 31, 2016
January 1, 2016 to
March 23, 2016
Exelon
Generation
ComEd
PECO
BGE
Pepco
DPL
ACE
PHI
PHI
$
60 $
513 $
(135) $
63 $
51 $ (118) $ (88) $ (26) $
(281) $
600
(24)
39
78
(254)
379
(20)
(2)
45
(2)
(4)
63
72
—
9
5
88
136
97
22
(1)
—
—
—
5
31
7
16
1
12
—
—
283
(1)
(11)
13
$
753 $
282 $
301 $
149 $
174 $
41 $ 22 $
(4) $
3 $
—
10
—
—
7
17
__________
(a) Exelon retrospectively adopted the new standard Revenue from Contracts with Customers. The standard was adopted as of January 1, 2018. Components of income tax
expense or benefit are recast to reflect the impact of the new standard.
Rate Reconciliation
The effective income tax rate from continuing operations varies from the U.S. federal statutory rate principally due to the following:
U.S. Federal statutory rate
Increase (decrease) due to:
State income taxes, net of Federal income
tax benefit
Qualified NDT fund income
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
For the Year Ended December 31, 2018
Successor
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 %
0.6
(1.9)
(1.2)
(3.5)
(2.2)
(1.0)
(8.3)
0.9
1.0
5.4 %
(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 %
377
(2.6)
—
6.6
—
(0.1)
(14.1)
—
—
(0.1)
(1.3)
—
—
(3.2)
(8.0)
—
0.3
1.3 %
—
0.9
19.1 %
3.0
—
(0.2)
(1.6)
—
—
(14.5)
0.1
0.3
8.1 %
2.2
—
6.7
—
(0.1)
(2.7)
—
—
(0.3)
(0.3)
—
—
7.4
—
(0.4)
(0.5)
—
—
(14.8)
(12.0)
(14.9)
—
0.2
5.8 %
—
0.4
15.5 %
—
1.2
13.8 %
Table of Contents
U.S. Federal statutory rate
Increase (decrease) due to:
Combined Notes to Consolidated Financial Statements - (Continued)
(Dollars in millions, except per share data unless otherwise noted)
For the Year Ended December 31, 2017 (a)
Successor
Exelon
Generation
ComEd
PECO
35.0 %
35.0 %
35.0 %
35.0 %
BGE
35.0 %
PHI
Pepco
35.0 %
35.0 %
DPL
35.0 %
ACE
35.0 %
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 (b)
Production tax credits and other credits
Like-kind exchange
Merger expenses
FitzPatrick bargain purchase gain
2.3
3.8
(0.9)
(1.7)
(1.8)
(1.2)
(3.6)
(2.2)
2.9
9.9
(2.1)
—
(4.7)
—
(1.2)
(5.6)
Tax Cuts and Jobs Act of 2017 (c)
(33.1)
(128.3)
Other
Effective income tax rate
0.1
(3.3)%
(0.5)
(94.6)%
0.6
—
(0.1)
(13.8)
—
—
—
—
5.4
—
(0.1)
0.1
—
—
—
—
(2.3)
0.9
(0.1)
19.3 %
0.2
41.5 %
4.8
—
(0.2)
1.1
—
—
(9.5)
—
6.4
3.2
—
5.4
—
5.6
—
(0.1)
(0.4)
—
—
(0.2)
(0.4)
2.0
—
—
3.6
—
—
(6.3)
(7.8)
(19.8)
—
—
2.7
2.5
—
1.6
(0.1)
37.5 %
(0.2)
33.9 %
0.1
37.0 %
(0.4)
25.2 %
5.7
—
(0.2)
0.3
—
1.3
—
—
0.1
0.2
42.4 %
378
Table of Contents
Combined Notes to Consolidated Financial Statements - (Continued)
(Dollars in millions, except per share data unless otherwise noted)
U.S. Federal statutory rate
35.0 %
35.0 %
35.0 %
Exelon
Generation
ComEd
PECO
35.0 %
BGE
35.0 %
Pepco
DPL (d)
ACE (d)
PHI (d)
PHI
35.0 %
35.0 %
35.0 %
35.0 %
35.0 %
For the Year Ended December 31, 2016 (a)
Successor
Predecessor
March 24, 2016 to
December 31,
2016
January 1, 2016 to
March 23, 2016
Increase (decrease) due to:
State income taxes,
net of Federal income
tax benefit (e)
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
Statute of limitations
expiration
Penalties
Merger Expenses
Other (f)
3.3
3.4
(1.2)
(4.9)
(3.6)
(0.2)
(0.4)
1.9
5.6
3.2
7.9
(2.3)
—
(8.3)
(0.6)
(1.7)
—
1.1
5.6
1.3
5.0
15.7
52.7
6.2
—
—
—
—
—
—
(0.3)
(0.6)
—
—
—
4.5
—
(0.1)
(9.6)
(0.1)
(2.7)
(0.2)
(22.8)
(3.7)
(25.5)
0.8
10.3
—
—
—
—
—
—
—
—
—
—
—
—
—
—
—
—
—
—
—
—
—
—
—
23.5
(1.8)
112.9
(2.2)
(44.9)
1.3
5.8
—
1.4
39.0
—
—
—
(0.7)
(89.0)
3.3
(5.2)%
11.9
—
(0.9)
(13.5)
—
—
—
—
11.1
3.6
(0.7)
38.2 %
(1.4)
32.9 %
0.1
44.3 %
(1.2)
25.4 %
Effective income tax rate
__________
(a) Exelon retrospectively adopted the new standard Revenue from Contracts with Customers. The standard was adopted as of January 1, 2018. The effective income tax
37.2 %
49.4 %
169.2 %
47.2 %
8.7 %
(b)
(c)
rates are recast to reflect the impact of the new standard.
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 4 - Regulatory Matters for additional information.
Included are impacts for TCJA other than the corporate rate change, including revisions further limiting tax deductions for compensation of certain highest paid executives,
the write-off of foreign tax credit carryforwards, and loss of a 2015 domestic production activities deduction due to an NOL carryback.
(d) DPL and ACE recognized a loss before income taxes for the year ended December 31, 2016, and PHI recognized a loss before income taxes for the period of March 24,
2016, through December 31, 2016. As a result, positive percentages represent an income tax benefit for the periods presented.
Includes a remeasurement of uncertain state income tax positions for Pepco and DPL.
(e)
(f) At PECO, includes a cumulative adjustment related to an anticipated gas repairs tax return accounting method change. The method change request was filed and
accepted in 2017. No change to the results recorded as of December 31, 2016.
379
Table of Contents
Tax Differences and Carryforwards
Combined Notes to Consolidated Financial Statements - (Continued)
(Dollars in millions, except per share data unless otherwise noted)
The tax effects of temporary differences and carryforwards, which give rise to significant portions of the deferred tax assets (liabilities), as of December 31, 2018
and 2017 are presented below:
As of December 31, 2018
Successor
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
(749)
237
811
(797)
934
(44)
35
(188)
(351)
23
—
78
816
(775)
239
—
69
—
—
(255)
(26)
—
(7)
300
—
—
—
151
—
—
(129)
18
—
—
67
—
—
(26)
—
(3)
172
25
—
—
12
161
3
—
—
—
—
(102)
(78)
(46)
—
187
(90)
96
—
—
196
—
(4)
58
12
—
—
98
—
(2)
96
52
—
—
17
(10,573)
$
(2,662)
$
(3,801)
$
(1,932)
$
(1,219)
$
(2,126)
$
(1,062)
$
(626)
$
(724)
(700)
(12)
(1)
(3)
(8)
(2)
(2)
—
—
(14)
—
(1)
83
26
—
—
19
(532)
(3)
(11,297)
$
(3,362)
$
(3,813)
$
(1,933)
$
(1,222)
$
(2,134)
$
(1,064)
$
(628)
$
(535)
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Table of Contents
Combined Notes to Consolidated Financial Statements - (Continued)
(Dollars in millions, except per share data unless otherwise noted)
As of December 31, 2017 (a)
Successor
Plant basis differences
$
(12,490)
$
(2,819)
$
(3,825)
$
(1,762)
$
(1,368)
$
(2,521)
$
(1,152)
$
(717)
$
(607)
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
$
$
150
(85)
1,463
(553)
217
(688)
344
861
(434)
746
(66)
(66)
(205)
(553)
26
—
76
868
(416)
78
—
(2)
(285)
—
(8)
489
33
1
—
141
—
—
(15)
—
(1)
(90)
9
—
—
71
—
—
(29)
—
(3)
136
11
—
—
13
216
3
(130)
—
203
(184)
156
6
—
193
—
—
(78)
—
(4)
39
40
—
—
94
—
—
(51)
—
(2)
88
68
—
—
14
—
—
(18)
—
(1)
86
35
—
—
16
(10,469)
$
(3,077)
$
(3,456)
$
(1,788)
$
(1,240)
$
(2,058)
$
(1,061)
$
(600)
$
(489)
(732)
(705)
(13)
(1)
(4)
(8)
(2)
(3)
(4)
(11,201)
$
(3,782)
$
(3,469)
$
(1,789)
$
(1,244)
$
(2,066)
$
(1,063)
$
(603)
$
(493)
__________
(a)
Includes remeasurement impacts related to the TCJA.
381
Table of Contents
Combined Notes to Consolidated Financial Statements - (Continued)
(Dollars in millions, except per share data unless otherwise noted)
The following table provides the Registrants’ carryforwards and any corresponding valuation allowances as of December 31, 2018 :
Exelon
Generation
ComEd
PECO
BGE
PHI
Pepco
DPL
ACE
Successor
811
(a)
816
—
—
—
—
—
—
—
Federal
Federal general business credits
carryforwards
State
State net operating losses
4,103
(b)
1,544
(b)
Deferred taxes on state tax attributes
(net)
272
104
—
—
224
(c)
395 (d)
1,492
(e)
192
(f)
772
(g)
365
(h)
18
26
102
12
52
26
35
Valuation allowance on state tax
attributes
__________
(a) Exelon’s federal general business credit carryforwards will begin expiring in 2033.
(b) Exelon’s and Generation's state net operating losses and credit carryforwards, which are presented on a post-apportioned basis, will begin expiring in 2019.
(c) PECO's state net operating loss carryforwards, which are presented on a post-apportioned basis, will begin expiring in 2031.
(d) BGE's state net operating loss carryforwards, which are presented on a post-apportioned basis, will begin expiring in 2026.
(e) PHI's state net operating loss carryforwards, which are presented on a post-apportioned basis, will begin expiring in 2036.
(f) Pepco's state net operating loss carryforwards, which are presented on a post-apportioned basis, will begin expiring in 2033.
(g) DPL's state net operating loss carryforwards, which are presented on a post-apportioned basis, will begin expiring in 2030.
(h) ACE's state net operating loss carryforwards, which are presented on a post-apportioned basis, will begin expiring in 2031.
—
—
—
—
1
6
26
—
Tabular Reconciliation of Unrecognized Tax Benefits
The following tables provide a reconciliation of the Registrants’ unrecognized tax benefits as of December 31, 2018 , 2017 and 2016 :
Exelon
Generation
ComEd
PECO
BGE
PHI
Pepco
DPL
ACE
Unrecognized tax benefits at January 1, 2018
$
Change to positions that only affect timing
Increases based on tax positions prior to 2018
Decreases based on tax positions prior to 2018
Decrease from settlements with taxing authorities
Decreases from expiration of statute of limitations
Unrecognized tax benefits at December 31, 2018
$
743 $
15
30
(251)
(53)
(7)
477 $
468
$
15
21
(36)
(53)
(7)
408
$
2 $
—
—
—
—
—
2 $
— $
—
—
—
—
—
— $
120 $
—
—
(120)
—
—
125 $
—
8
(88)
—
—
59 $
—
7
(66)
—
—
21 $
—
1
(22)
—
—
— $
45
$
— $
— $
14
—
—
—
—
—
14
Exelon
Generation
ComEd
PECO
BGE
PHI
Pepco
DPL
ACE
Unrecognized tax benefits at January 1, 2017
Increases based on tax positions prior to 2017
Decreases based on tax positions prior to 2017
Decrease from settlements with taxing authorities
Unrecognized tax benefits at December 31, 2017
$
$
$
916
28
(196)
(5)
$
490
—
(17)
(5)
$
(12)
14
—
—
— $
—
—
—
120 $
—
—
—
172 $
14
(61)
—
80 $
—
(21)
—
37 $
—
(16)
—
743
$
468
$
2
$
— $
120
$
125
$
59
$
21
$
22
14
(22)
—
14
382
Table of Contents
Combined Notes to Consolidated Financial Statements - (Continued)
(Dollars in millions, except per share data unless otherwise noted)
Exelon
Generation
ComEd
PECO
BGE
PHI
Pepco
DPL
ACE
Unrecognized tax benefits at January 1, 2016
$
1,078
$
534
$
Merger balance transfer
Increases based on tax positions related to 2016
Change to positions that only affect timing
Increases based on tax positions prior to 2016
Decreases based on tax positions prior to 2016
Decreases from settlements with taxing authorities
Unrecognized tax benefits at December 31, 2016
$
22
108
(332)
88
(21)
(27)
916 $
5
10
(12)
—
(20)
(27)
142 $
—
—
(154)
—
—
—
— $
—
—
—
—
—
—
— $
120 $
—
—
—
—
—
—
120
$
22 $
(5)
59
—
96
—
—
8 $
—
21
—
51
—
—
3 $
—
16
—
18
—
—
172
$
80
$
37
$
—
—
22
—
—
—
—
22
490
$
(12)
$
As a result of a court decision issued in July 2018 to an unrelated taxpayer, Exelon's and Generation’s unrecognized federal and state tax benefits increased in
the third quarter of 2018 by approximately $71 million . Approximately $20 million of this increase impacted Exelon's and Generation’s effective tax rate and
resulted in a charge to earnings in the third quarter of 2018. Exelon’s and Generation’s unrecognized federal and state tax benefits decreased in the fourth
quarter of 2018 by approximately $90 million due to the settlement of a federal audit issue with IRS Appeals. The recognition of these tax benefits decreased the
effective tax rate at Exelon and Generation resulting in an income tax benefit of approximately $9 million .
In the fourth quarter of 2018, Exelon, Generation, BGE, PHI, Pepco, and DPL decreased their unrecognized state tax benefits by $241 million , $33 million ,
$120 million , $88 million , $66 million , and $22 million , respectively, due to the receipt of favorable guidance with respect to the deductibility of certain
depreciable fixed assets. The recognition of these tax benefits decreased the effective tax rate at Exelon and Generation resulting in an income tax benefit of
approximately $26 million . 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.
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 in 2012 and PHI in 2016. In the first quarter 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, in the first
quarter of 2017 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.
Exelon reduced the liability related to the uncertain tax position associated with the like-kind exchange in the second quarter of 2017.
Unrecognized tax benefits that if recognized would affect the effective tax rate
Exelon, Generation, ComEd and PHI have $463 million , $408 million , $2 million and $31 million , respectively, of unrecognized tax benefits at December 31,
2018 that, if recognized, would decrease the effective tax rate. PHI has $21 million of unrecognized state tax benefits at December 31, 2018 that, if recognized,
$14 million would be in the form of a net operating loss carryforward, which is expected to require a full valuation allowance based on present circumstances.
PHI and ACE have $14 million of unrecognized tax benefits at December 31, 2018 that, if recognized, may be included in future base rates and that portion
would have no impact to the effective tax rate.
Exelon, Generation, ComEd and PHI had $523 million , $461 million , $2 million and $32 million , respectively, of unrecognized tax benefits at December 31,
2017 that, if recognized, would decrease the effective tax rate. BGE, PHI, Pepco, DPL, and ACE have $120 million , $94 million , $59 million , $21 million and
$14 million of unrecognized tax benefits at December 31, 2017 that, if recognized, may be included in future base rates and that portion would have no impact to
the effective tax rate.
383
Table of Contents
Combined Notes to Consolidated Financial Statements - (Continued)
(Dollars in millions, except per share data unless otherwise noted)
Exelon, Generation, PHI, Pepco, DPL, and ACE had $633 million , $483 million , $93 million , $21 million , $16 million , and $22 million , respectively, of
unrecognized tax benefits at December 31, 2016 that, if recognized, would decrease the effective tax rate. BGE, PHI, Pepco and DPL had $120 million , $80
million , $59 million , and $21 million of unrecognized tax benefits at December 31, 2016 that, if recognized, may be included in future base rates and that portion
would have no impact to the effective tax rate.
Unrecognized tax benefits that if recognized would affect only the timing of tax payments
There are no unrecognized tax benefits as of December 31, 2018 that affect only the timing of tax payments.
Exelon and Generation had $7 million of unrecognized tax benefits at December 31, 2017 for which the ultimate tax benefit is highly certain, but for which there
is uncertainty about the timing of such benefits.
Exelon, Generation and ComEd had $83 million , $7 million and $(12) million of unrecognized tax benefits at December 31, 2016 for which the ultimate tax
benefit is highly certain, but for which there is uncertainty about the timing of such benefits.
The disallowance of such positions would not materially affect the annual effective tax rate but would accelerate the payment of cash to, or defer the receipt of
the cash tax benefit from, the taxing authority to an earlier or later period respectively.
Reasonably possible the total amount of unrecognized tax benefits could significantly increase or decrease within 12 months after the reporting date
Like-Kind Exchange
As of December 31, 2018 , Exelon and ComEd have approximately $33 million and $ 2 million , respectively, of unrecognized federal and state income tax
benefits related to the like-kind exchange litigation described further below. If Exelon does not appeal the October 2018 U.S. Court of Appeals for the Seventh
Circuit's decision to the U.S. Supreme Court, Exelon's and ComEd's unrecognized tax benefits will decrease in the first quarter of 2019. See below for further
details.
Settlement of Income Tax Audits, Refund Claims, and Litigation
As of December 31, 2018 , Exelon, Generation, PHI and ACE have approximately $425 million , $411 million , $14 million , and $ 14 million respectively, of
unrecognized federal and state tax benefits that could significantly decrease within the 12 months after the reporting date as a result of completing audits,
potential settlements, refund claims, and the outcomes of pending court cases. Of the above unrecognized tax benefits, Exelon and Generation have $411
million that, if recognized, would decrease the effective tax rate. The unrecognized tax benefit related to PHI and ACE, if recognized, may be included in future
base rates and that portion would have no impact to the effective tax rate.
Total amounts of interest and penalties recognized
The following tables represent the net interest and penalties receivable (payable), including interest and penalties related to tax positions reflected in the
Registrants’ Consolidated Balance Sheets.
Net interest receivable (payable) as of
Exelon
Generation
ComEd
PECO
BGE
PHI
Pepco
DPL
ACE
December 31, 2018
December 31, 2017
$
236 $
233
$
(2)
(3)
4 $
4
— $
— $
—
—
1 $
2
— $
— $
—
—
Net penalties payable as of
Exelon
Generation
ComEd
PECO
BGE
PHI
Pepco
DPL
ACE
December 31, 2018
December 31, 2017
$
(17) $
(17)
— $
—
— $
—
— $
— $
— $
— $
— $
—
—
—
—
—
—
—
—
—
384
Table of Contents
Combined Notes to Consolidated Financial Statements - (Continued)
(Dollars in millions, except per share data unless otherwise noted)
The following tables set forth the net interest and penalty expense, including interest and penalties related to tax positions, recognized in Interest expense, net
and Other, net in Other income and deductions in the Registrants’ Consolidated Statements of Operations and Comprehensive Income.
Net interest expense (income) for the years
ended
December 31, 2018
December 31, 2017
December 31, 2016
Net penalty expense (income) for the
years ended
December 31, 2018
December 31, 2017
December 31, 2016
PHI
Net interest expense
Exelon
Generation
ComEd
PECO
BGE
Pepco
DPL
ACE
$
(3) $
— $
— $
— $
— $
— $
— $
37
165
(1)
(13)
11
117
—
—
—
—
—
6
—
—
Exelon
Generation
ComEd
PECO
BGE
Pepco
DPL
ACE
$
— $
— $
— $
— $
— $
— $
— $
(2)
106
—
—
—
86
—
—
—
—
—
—
—
—
—
—
(1)
—
—
—
December 31, 2018
December 31, 2017
March 24, 2016 to December 31,
2016
January 1, 2016 to March 23, 2016
$
— $
— $
(2)
$
—
Successor
Predecessor
Description of tax years open to assessment by major jurisdiction
Taxpayer
Open Years
Exelon (and predecessors) and subsidiaries consolidated federal income tax returns
PHI Holdings and subsidiaries consolidated federal income tax returns
Exelon and subsidiaries Illinois unitary income tax returns
Constellation combined New York corporate income tax returns
Exelon combined New York corporate income tax returns
Exelon New Jersey corporate income tax returns
Exelon Pennsylvania corporate net income tax returns
PECO Pennsylvania separate company returns
DPL Delaware separate company returns
ACE New Jersey separate company returns
Exelon and subsidiaries District of Columbia corporate income tax returns
PHI Holdings and subsidiaries District of Columbia corporate income tax returns
Various separate company Maryland corporate net income tax returns
Other Tax Matters
Like-Kind Exchange
1999, 2001-2017
2013, 2015-2016
2010-2017
2010-March 2012
2011-2017
2013-2017
2011-2017
2015-2017
Same as federal
2014-2017
2015-2017
2015-2016
Same as federal
Exelon, through its ComEd subsidiary, took a position on its 1999 income tax return to defer approximately $1.2 billion of tax gain on the sale of ComEd’s fossil
generating assets. The gain was deferred by reinvesting a portion of the proceeds from the sale in qualifying replacement property under the like-kind exchange
provisions of the IRC. The like-kind exchange replacement property purchased by Exelon included interests in three municipal-owned
385
Table of Contents
Combined Notes to Consolidated Financial Statements - (Continued)
(Dollars in millions, except per share data unless otherwise noted)
electric generation facilities which were properly leased back to the municipalities. As previously disclosed, Exelon terminated its investment in one of the leases
in 2014 and the remaining two leases were terminated in 2016.
The IRS asserted that the Exelon purchase and leaseback transaction was substantially similar to a leasing transaction, known as a SILO, which is a listed
transaction that the IRS has identified as a potentially abusive tax shelter. Thus, they disagreed with Exelon's position and asserted that the entire gain of
approximately $1.2 billion was taxable in 1999. In 2013, the IRS issued a notice of deficiency to Exelon and Exelon filed a petition to initiate litigation in the
United States Tax Court. In 2016, the Tax Court held that Exelon was not entitled to defer gain on the transaction. In addition to the tax and interest related to
the gain deferral, the Tax Court also ruled that Exelon was liable for $90 million in penalties and interest on the penalties. Exelon has fully paid the amounts
assessed resulting from the Tax Court decision.
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. Exelon has until March 5, 2019 to seek a further review by the U.S. Supreme Court.
State Income Tax Law Changes
On April 24, 2018, Maryland enacted companion bills, House Bill 1794 and Senate Bill 1090, providing for a phase in of a single sales factor apportionment
formula from the current three factor formula for determining an entity's Maryland state income taxes. The single sales factor will be fully phased in by 2022.
In the second quarter of 2018, Exelon, Generation, PHI, Pepco and DPL recorded a one-time increase to deferred income taxes of approximately $16 million ,
$5 million , $17 million , $16 million and $1 million , respectively. At PHI, Pepco and DPL, the increase to the Maryland deferred income tax liability was offset by
regulatory assets. Further, the change in tax law is not expected to have a material ongoing impact to Exelon's, Generation's, PHI's, Pepco's or DPL's future
results of operations.
Long-Term Marginal State Income Tax Rate (Exelon, Generation, PHI and Pepco)
In the third quarter of 2018, Exelon reviewed and updated its marginal state income tax rates based on 2017 state apportionment rates. As a result of the rate
changes, in the third quarter of 2018, Exelon, Generation, PHI and DPL recorded a one-time decrease to deferred income taxes of approximately $50 million ,
$53 million , $4 million and $2 million respectively. Pepco recorded a one-time increase to deferred income taxes of approximately $1 million . Exelon, PHI and
DPL recorded a corresponding regulatory liability of approximately $1 million , $1 million and $2 million respectively. Pepco recorded a corresponding regulatory
asset of approximately $1 million . Further, Exelon, Generation and PHI recorded a decrease to income tax expense (net of federal taxes) of approximately $50
million , $53 million and $3 million .
Allocation of Tax Benefits (All Registrants)
Generation, ComEd, PECO, BGE, PHI, Pepco, DPL and ACE 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. During 2018, Generation, PECO, BGE, PHI and ComEd
recorded an allocation of federal tax benefits from Exelon under the Tax Sharing Agreement of $155 million , $48 million , $26 million , $2 million and $1 million
respectively. 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.
During 2017, Generation, PECO, BGE, and PHI recorded an allocation of federal tax benefits from Exelon under the Tax Sharing Agreement of $102 million ,
$16 million , $10 million and $7 million respectively. 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.
During 2016, Generation, PECO and BGE recorded an allocation of federal tax benefits from Exelon under the Tax Sharing Agreement of $94 million , $18
million and $8 million respectively. ComEd 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. PHI, Pepco,
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Combined Notes to Consolidated Financial Statements - (Continued)
(Dollars in millions, except per share data unless otherwise noted)
DPL and ACE did not record an allocation of federal tax benefits from Exelon as they were not a part of Exelon's 2015 consolidated tax return.
15. Asset Retirement Obligations (All Registrants)
Nuclear Decommissioning Asset Retirement Obligations
Generation has a legal obligation to decommission its nuclear power plants following the expiration of their operating licenses. To estimate its decommissioning
obligation related to its nuclear generating stations for financial accounting and reporting purposes, Generation uses a probability-weighted, discounted cash
flow model which, on a unit-by-unit basis, considers multiple outcome scenarios that include significant estimates and assumptions, and are based on
decommissioning cost studies, cost escalation rates, probabilistic cash flow models and discount rates. Generation updates its ARO annually unless
circumstances warrant more frequent updates, based on its review of updated cost studies and its annual evaluation of cost escalation factors and probabilities
assigned to various scenarios.
The following table provides a rollforward of the nuclear decommissioning ARO reflected in Exelon’s and Generation’s Consolidated Balance Sheets, from
January 1, 2017 to December 31, 2018 :
Nuclear decommissioning ARO at January 1, 2017
$
8,734
Accretion expense
Acquisition of FitzPatrick
Net increase due to changes in, and timing of, estimated future cash flows
Costs incurred related to decommissioning plants
Nuclear decommissioning ARO at December 31, 2017 (a)
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)
__________
(a)
458
444
34
(8)
9,662
478
(77)
(58)
$
10,005
Includes $22 million and $13 million as the current portion of the ARO at December 31, 2018 and 2017 , 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 5 — Mergers, Acquisitions and Dispositions for additional information.
(b)
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 include a $203 million decrease 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. These adjustments also include a decrease due to changes in decommissioning scenarios and their
probabilities. These decreases were partially offset by a $116 million increase for the impact of the early retirement and the announced pending sale of Oyster
Creek and a $122 million increase for estimated cost escalation rates, primarily for labor, energy and waste burial costs. See Note 5 — Mergers, Acquisitions
and Dispositions and Note 8 — Early Plant Retirements for additional information regarding Oyster Creek.
The net $34 million increase in the ARO during 2017 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 include a $178 million increase due to higher assumed probabilities of early
retirement of Salem and a $138 million increase in TMI’s ARO liability associated with the May 30, 2017 announcement to early retire the unit on September 30,
2019. The increase in TMI's ARO liability incorporates the early shutdown date, increases in the probabilities of longer term decommissioning scenarios, and an
increase in the estimated costs to decommission based on an updated decommissioning cost study. See Note 8 — Early Plant Retirements for
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Combined Notes to Consolidated Financial Statements - (Continued)
(Dollars in millions, except per share data unless otherwise noted)
additional information regarding Salem and TMI. These increases in the ARO were partially offset by a $180 million decrease for refinements in estimated fleet
wide labor costs expected to be incurred for certain on-site personnel during decommissioning as well as net decreases resulting from updates to the cost
studies of Clinton, Quad Cities and Dresden.
NDT Funds
NDT funds have been established for each generation station unit to satisfy Generation’s nuclear decommissioning obligations. Generally, NDT funds
established for a particular unit may not be used to fund the decommissioning obligations of any other unit.
The NDT funds associated with Generation's nuclear units have been funded with amounts collected from the previous owners and their respective utility
customers. PECO is authorized to collect funds, in revenues, for decommissioning the former PECO nuclear plants through regulated rates, and these
collections are scheduled through the operating lives of the former PECO plants. The amounts collected from PECO customers are remitted to Generation and
deposited into the NDT funds for the unit for which funds are collected. Every five years, PECO files a rate adjustment with the PAPUC that reflects PECO’s
calculations of the estimated amount needed to decommission each of the former PECO units based on updated fund balances and estimated decommissioning
costs. The rate adjustment is used to determine the amount collectible from PECO customers. On March 31, 2017, PECO filed its Nuclear Decommissioning
Cost Adjustment with the PAPUC proposing an annual recovery from customers of approximately $4 million . This amount reflects a decrease from the
previously approved annual collection of approximately $ 24 million primarily due to the removal of the collections for Limerick Units 1 and 2 as a result of the
NRC approving the extension of the operating licenses for an additional 20 years. On August 8, 2017, the PAPUC approved the filing and the new rates became
effective January 1, 2018.
Any shortfall of funds necessary for decommissioning, determined for each generating station unit, is ultimately required to be funded by Generation, with the
exception of a shortfall for the current decommissioning activities at Zion Station, where certain decommissioning activities have been transferred to a third-party
(see Zion Station Decommissioning below) and the CENG units, where any shortfall is required to be funded by both Generation and EDF. Generation, through
PECO, has recourse to collect additional amounts from PECO customers related to a shortfall of NDT funds for the former PECO units, subject to certain
limitations and thresholds, as prescribed by an order from the PAPUC. Generally, PECO, and likewise Generation will not be allowed to collect amounts
associated with the first $50 million of any shortfall of trust funds compared to decommissioning costs, as well as 5% of any additional shortfalls, on an
aggregate basis for all former PECO units. The initial $50 million and up to 5% of any additional shortfalls would be borne by Generation. No recourse exists to
collect additional amounts from utility customers for any of Generation's other nuclear units. With respect to the former ComEd and PECO units, any funds
remaining in the NDTs after all decommissioning has been completed are required to be refunded to ComEd’s or PECO’s customers, subject to certain
limitations that allow sharing of excess funds with Generation related to the former PECO units. With respect to Generation's other nuclear units, Generation
retains any funds remaining after decommissioning. However, in connection with CENG's acquisition of the Nine Mile Point and Ginna plants and settlements
with certain regulatory agencies, CENG is subject to certain conditions pertaining to NDT funds that, if met, could possibly result in obligations to make payments
to certain third parties (clawbacks). For Nine Mile Point and Ginna, the clawback provisions are triggered only in the event 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, 2018 and 2017 , Exelon and Generation had NDT funds totaling $12,695 million and $ 13,349 million , respectively. Included within the
December 31, 2018 balance is the $890 million reclassification of Oyster Creek NDT as Assets held for sale in Exelon's and Generation's Consolidated Balance
Sheets. See Note 5 — Mergers, Acquisitions and Dispositions for additional information regarding the announced pending sale of Oyster Creek. The NDT funds
include $144 million and $77 million for the current portion of the NDT at December 31, 2018 and 2017 , respectively, which are included in Other current assets
in Exelon's and Generation's Consolidated
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Combined Notes to Consolidated Financial Statements - (Continued)
(Dollars in millions, except per share data unless otherwise noted)
Balance Sheets. See Note 11 — Fair Value of Financial Assets and Liabilities for additional information related to the NDT funds.
The following table provides unrealized (losses) gains on NDT funds of Exelon and Generation for the years ended 2018 , 2017 and 2016 :
Net unrealized (losses) gains on NDT funds—Regulatory Agreement Units (a)
$
(715) $
455 $
216
2018
2017
2016
Net unrealized (losses) gains on NDT funds—Non-Regulatory Agreement Units (b)
__________
(a) Net unrealized (losses) gains related to Generation’s NDT funds associated with Regulatory Agreement Units are included in Regulatory liabilities in Exelon’s
194
(483)
521
Consolidated Balance Sheets and Noncurrent payables to affiliates in Generation’s Consolidated Balance Sheets.
(b) Net unrealized (losses) gains related to Generation’s NDT funds with Non-Regulatory Agreement Units are included within Other, net in Exelon’s and Generation’s
Consolidated Statements of Operations and Comprehensive Income.
Realized earnings, including interest and dividends on the NDT funds, for the non-Regulatory Agreement Units investments are recognized when earned and
are included in Other, net in Exelon’s and Generation’s Consolidated Statements of Operations and Comprehensive Income whereas the Regulatory Agreement
Units are eliminated within Other, net.
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, 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, 2018 , 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 4 — Regulatory Matters and Note 25 — Related Party Transactions for additional information regarding regulatory liabilities at ComEd and PECO and
intercompany balances between Generation, ComEd and PECO
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Combined Notes to Consolidated Financial Statements - (Continued)
(Dollars in millions, except per share data unless otherwise noted)
reflecting the obligation to refund to customers any decommissioning-related assets in excess of the related decommissioning obligations.
Zion Station Decommissioning
In 2010, Generation completed an 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. Pursuant to the ASA, ZionSolutions will
periodically request reimbursement, subject to certain restrictions, from the Zion Station-related NDT funds for costs incurred related to its decommissioning
efforts at Zion Station. As the transfer of the Zion Station assets did not qualify for asset sale accounting treatment, the related NDT funds were reclassified as
pledged assets for Zion Station decommissioning, which are recorded within Other current assets within Generation’s and Exelon’s Consolidated Balance
Sheets and will continue to be measured in the same manner as prior to the completion of the transaction, and the transferred ARO for decommissioning was
replaced with a payable for Zion Station decommissioning, which is recorded in Other current liabilities in Exelon’s and Generation’s Consolidated Balance
Sheets. Changes in the value of the Zion Station NDT fund assets, net of applicable taxes, are recorded as a change in the payable to ZionSolutions. At no point
will the payable to ZionSolutions exceed the project budget of the costs remaining to decommission Zion Station.
Generation has retained its obligation for the SNF. 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 has a liability of $120 million , which is included within the nuclear decommissioning ARO at
December 31, 2018 . Generation also has retained 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.
The following table provides Exelon's and Generation's pledged assets and payables to ZionSolutions, and withdrawals by ZionSolutions at December 31, 2018
and 2017 :
$
2018
2017
9 $
9
965
39
37
942
Carrying value of Zion Station pledged assets
Current payable to ZionSolutions (a)
Cumulative withdrawals by ZionSolutions to pay decommissioning costs (b)
_______
(a)
Included in Other current liabilities within Exelon's and Generation's Consolidated Balance Sheets. Excludes a liability recorded within Exelon’s and Generation’s
Consolidated Balance Sheets related to the tax obligation on the unrealized gains and losses associated with the Zion Station NDT funds. The NDT funds will be utilized
to satisfy the tax obligations as gains and losses are realized.
Includes project expenses to decommission Zion Station and estimated tax payments on Zion Station NDT fund earnings.
(b)
ZionSolutions leased the land associated with Zion Station from Generation pursuant to a Lease Agreement. Under the Lease Agreement, ZionSolutions has
committed to complete the required decommissioning work according to an established schedule and constructed a dry cask storage facility on the land and has
loaded the SNF from the SNF pools onto the dry cask storage facility at Zion Station. Rent payable under the Lease Agreement is $1.00 per year, although the
Lease Agreement requires ZionSolutions to pay property taxes associated with Zion Station and penalty rents may accrue if there are unexcused delays in the
progress of decommissioning work at Zion Station or the construction of the dry cask SNF storage facility. To reduce the risk of default by ZionSolutions,
EnergySolutions provided a $200 million letter of credit to be used to fund decommissioning costs in the event the NDT assets are insufficient. In accordance
with the terms of the ASA, the letter of credit was reduced to $45 million in May 2018 due to the completion of key decommissioning milestones.
EnergySolutions and its parent company have also provided a performance guarantee and EnergySolutions has entered into other agreements that will provide
rights and remedies for Generation and the NRC in the case of other specified events of default, including a special purpose easement for disposal capacity at
the EnergySolutions site in Clive, Utah, for all LLRW volume of Zion Station.
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NRC Minimum Funding Requirements
Combined Notes to Consolidated Financial Statements - (Continued)
(Dollars in millions, except per share data unless otherwise noted)
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, 2018 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 and with an assumed end-of-operations date of 2019 for TMI); (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,
2018 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 5.0% to 6.2% (as compared to a historical 5-year annual average pre-tax
return of approximately 4.9% ).
Generation is required to provide to the NRC a biennial report by unit (annually for units that have been retired or are within five years of the current approved
license life), based on values as of December 31, addressing Generation’s ability to meet the NRC minimum funding levels. Depending on the value of the trust
funds, Generation may be required to take steps, such as providing financial guarantees through letters of credit or parent company guarantees or making
additional contributions to the trusts, which could be significant, to ensure that the trusts are adequately funded and that NRC minimum funding requirements are
met. As a result, Exelon’s and Generation’s cash flows and financial positions may be significantly adversely affected.
Generation filed its biennial decommissioning funding status report with the NRC on March 30, 2017 for all units except for Zion Station which is included in a
separate report to the NRC submitted by ZionSolutions (see Zion Station Decommissioning above) and FitzPatrick which is still owned by Entergy as of the NRC
reporting period. This status report demonstrated adequate decommissioning funding assurance for all units except for Peach Bottom Unit 1. As a former PECO
plant, financial assurance for decommissioning Peach Bottom Unit 1 is provided by the NDT fund in addition to collections from PECO ratepayers. See NDT
Funds section above for additional information.
On March 28, 2018, Generation submitted its annual decommissioning funding status report with the NRC 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),
and reactor involved in an acquisition. This report reflected the status of decommissioning funding assurance as of December 31, 2017 and included an update
for the acquisition of FitzPatrick on March 31, 2017, the early retirement of TMI announced on May 30, 2017, an adjustment for the February 2, 2018 announced
retirement date of Oyster Creek and the updated status of Peach Bottom Unit 1 based on the new collections rate described above. As of December 31, 2017,
Generation provided adequate decommissioning funding assurance for all of its shutdown reactors, reactors within five years of shutdown, and reactor involved
in an acquisition.
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Table of Contents
Combined Notes to Consolidated Financial Statements - (Continued)
(Dollars in millions, except per share data unless otherwise noted)
Generation will file its next decommissioning funding status report for all units with the NRC by March 31, 2019. This report will reflect the status of
decommissioning funding assurance as of December 31, 2018. A shortfall at any unit could necessitate 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 guarantee or other assurance will ultimately
depend on the decommissioning approach, 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, 2017 to
December 31, 2018 :
Non-nuclear AROs at
January 1, 2017
Net (decrease) increase due to changes in, and
timing of, estimated future cash flows
Development projects
Accretion expense (a)
Deconsolidation of EGTP
Payments
Non-nuclear AROs at December 31, 2017
Net increase due to changes in, and timing of,
estimated future cash flows (b)
Accretion expense (a)
Asset divestitures
Payments
Exelon
Generation
ComEd
PECO
BGE
PHI
Pepco
DPL
ACE
$
393 $
199
$
121
$
28
$ 24 $
14 $
2 $
9 $
3
(11)
1
18
(7)
(10)
384
80
16
(3)
(6)
(1)
1
10
(7)
(5)
197
35
10
(3)
(1)
(13)
—
7
—
(2)
113
7
4
—
(3)
(1)
—
1
—
(1)
27
—
1
—
—
28
2
—
—
—
(2)
24
2
1
—
(2)
2
—
—
—
—
16
36
—
—
—
1
—
—
—
—
3
34
—
—
—
1
—
—
—
—
10
1
—
—
—
$ 25 $
52 $
37
$ 11
$
—
—
—
—
—
3
1
—
—
—
4
Non-nuclear AROs at December 31, 2018
$
471 $
238
$
121
$
__________
(a) For ComEd and PECO, the majority of the accretion is recorded as an increase to a regulatory asset due to the associated regulatory treatment.
(b)
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.
16. Retirement Benefits (All Registrants)
Exelon sponsors defined benefit pension plans and other postretirement benefit 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
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Table of Contents
Combined Notes to Consolidated Financial Statements - (Continued)
(Dollars in millions, except per share data unless otherwise noted)
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 is merging the Exelon Corporation Cash Balance Pension Plan (CBPP) into the Exelon Corporation Retirement Program
(ECRP). The merging of the plans is not changing the benefits offered to the plan participants and, thus, has no impact on Exelon's pension obligation. However,
beginning in 2019, actuarial losses and gains related to the CBPP and ECRP will be amortized over participants’ average remaining service period of the
merged ECRP rather than each individual plan.
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Table of Contents
Combined Notes to Consolidated Financial Statements - (Continued)
(Dollars in millions, except per share data unless otherwise noted)
The table below shows the pension and other postretirement benefit plans in which employees of each operating company participated at December 31, 2018 :
Name of Plan:
Qualified Pension Plans:
Exelon Corporation Retirement Program (a)
Exelon Corporation Cash Balance Pension Plan (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
BSC
PHI
Pepco
DPL
ACE
Operating Company (e)
X
X
X
X
X
X
X
X
X
X
X
X
X
X
X
X
X
X
X
X
X
X
X
X
X
X
X
X
X
X
X
394
X
X
X
X
X
X
X
X
X
X
X
X
X
X
X
X
X
X
X
X
X
X
X
X
X
X
X
X
X
X
X
X
X
X
X
X
X
X
X
X
X
X
X
X
X
X
X
X
X
X
X
X
X
X
X
X
X
X
X
X
X
X
X
X
Table of Contents
Combined Notes to Consolidated Financial Statements - (Continued)
(Dollars in millions, except per share data unless otherwise noted)
Operating Company (e)
Name of Plan:
Generation
ComEd
PECO
BGE
BSC
PHI
Pepco
DPL
ACE
Other Postretirement Benefit 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
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
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
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), in accordance with the applicable authoritative guidance. The measurement date for the plans is December 31.
During the first quarter of 2018, Exelon received an updated valuation of its pension and OPEB to reflect actual census data as of January 1, 2018. This
valuation resulted in an increase to the pension and OPEB obligations of $23 million and $14 million, respectively. Additionally, accumulated other
comprehensive loss decreased by $18 million (after-tax) and regulatory assets and liabilities increased by $61 million and $1 million, respectively.
395
Table of Contents
Combined Notes to Consolidated Financial Statements - (Continued)
(Dollars in millions, except per share data unless otherwise noted)
In connection with the acquisition of FitzPatrick in 2017, Exelon recorded pension and OPEB obligations for FitzPatrick employees of $16 million and $17 million
, respectively. See Note 5 — Mergers, Acquisitions and Dispositions for additional information of the acquisition of FitzPatrick.
The following tables provide a rollforward of the changes in the benefit obligations and plan assets for the most recent two years for all plans combined:
Exelon
Change in benefit obligation:
Pension Benefits
Other
Postretirement Benefits
2018
2017
2018
2017
Net benefit obligation at beginning of year
$
22,337 $
21,060 $
4,856 $
4,457
Service cost
Interest cost
Plan participants’ contributions
Actuarial (gain) loss (a)
Plan amendments
Acquisitions (b)
Settlements
Gross benefits paid
Net benefit obligation at end of year
Exelon
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
405
802
—
(1,561)
(4)
—
(48)
387
842
—
1,182
9
16
(34)
112
175
45
(540)
—
—
(4)
(1,239)
20,692 $
(1,125)
22,337 $
(275)
4,369 $
Pension Benefits
Other
Postretirement Benefits
2018
2017
2018
2017
18,573 $
16,791 $
2,732 $
(945)
337
—
(1,239)
(48)
2,600
341
—
(1,125)
(34)
(136)
46
45
(275)
(4)
16,678 $
18,573 $
2,408 $
106
182
53
350
—
17
—
(309)
4,856
2,578
346
64
53
(309)
—
2,732
$
$
$
__________
(a) 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. The pension and OPEB actuarial losses in 2017 primarily reflect a decrease in the discount rate.
(b) Exelon recorded pension and OPEB obligations associated with its acquisition of Fitzpatrick on March 31, 2017.
Exelon presents its benefit obligations and plan assets net on its balance sheet within the following line items:
Exelon
Other current liabilities
Pension obligations
Non-pension postretirement benefit obligations
Unfunded status (net benefit obligation less plan assets)
Pension Benefits
Other
Postretirement Benefits
2018
2017
2018
2017
$
$
26 $
3,988
—
4,014
$
396
28 $
3,736
—
3,764
$
33 $
—
1,928
1,961
$
31
—
2,093
2,124
Table of Contents
Combined Notes to Consolidated Financial Statements - (Continued)
(Dollars in millions, except per share data unless otherwise noted)
The funded status of the pension and other postretirement benefit obligations refers to the difference between plan assets and estimated obligations of the plan.
The funded status changes over time due to several factors, including contribution levels, assumed discount rates and actual returns on plan assets.
The following tables provide the projected benefit obligations (PBO), accumulated benefit obligation (ABO), and fair value of plan assets for all pension plans
with a PBO or ABO in excess of plan assets.
PBO in excess of plan assets
Projected benefit obligation
Fair value of net plan assets
ABO in excess of plan assets
Projected benefit obligation
Accumulated benefit obligation
Fair value of net plan assets
$
$
Exelon
2018
2017
20,692 $
16,678
Exelon
2018
2017
20,692 $
19,656
16,678
22,337
18,573
22,337
21,153
18,573
On a PBO basis, the Exelon plans were funded at 81% and 83% at December 31, 2018 and 2017 , respectively. On an ABO basis, the Exelon plans were
funded at 85% and 88% at December 31, 2018 and 2017 , respectively. The ABO differs from the PBO in that the ABO includes no assumption about future
compensation levels.
Components of Net Periodic Benefit Costs
The majority of the 2018 pension benefit cost for the Exelon-sponsored plans is calculated using an expected long-term rate of return on plan assets of 7.00%
and a discount rate of 3.62% . The majority of the 2018 other postretirement benefit cost is calculated using an expected long-term rate of return on plan assets
of 6.60% for funded plans and a discount rate of 3.61% .
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, 2018 , 2017 and 2016 and PHI's net periodic benefit costs, prior to
capitalization, for the predecessor period of January 1, 2016 to March 23, 2016 .
Exelon
Components of net periodic
benefit cost:
Service cost
Interest cost
Expected return on assets
Amortization of:
Prior service cost (credit)
Actuarial loss
Settlement and other charges (c)
Net periodic benefit cost
$
$
Pension Benefits
Other
Postretirement Benefits
2018
2017 (a)
2016 (b)
2018
2017 (a)
2016 (b)
$
405
802
$
387
842
$
354
830
(1,252)
(1,196)
(1,141)
2
629
3
1
607
3
14
554
2
$
112
175
(173)
(186)
66
1
$
106
182
(162)
(188)
61
—
589 $
644 $
613 $
(5) $
(1) $
107
185
(162)
(185)
63
—
8
__________
(a) FitzPatrick net benefit costs are included for the period after acquisition.
(b) PHI net periodic benefit costs for the period prior to the merger are not included in the table above.
(c) 2016 amount includes an additional termination benefit for PHI.
397
Table of Contents
Combined Notes to Consolidated Financial Statements - (Continued)
(Dollars in millions, except per share data unless otherwise noted)
PHI
Components of net periodic benefit cost:
Service cost
Interest cost
Expected return on assets
Amortization of:
Prior service cost (credit)
Actuarial loss
Net periodic benefit cost
Components of AOCI and Regulatory Assets
Pension Benefits
Other
Postretirement Benefits
Predecessor
January 1, 2016 to March 23, 2016
January 1, 2016 to March 23, 2016
$
$
12 $
26
(30)
—
14
22 $
1
6
(5)
(3)
2
1
Under the authoritative guidance for regulatory accounting, a portion of current year actuarial gains and losses and prior service costs (credits) is capitalized
within Exelon’s Consolidated Balance Sheets to reflect the expected regulatory recovery of these amounts, which would otherwise be recorded to AOCI. The
following tables provide the components of AOCI and regulatory assets (liabilities) for the years ended December 31, 2018 , 2017 and 2016 for all plans
combined and the components of PHI's predecessor AOCI and regulatory assets (liabilities) for the period January 1, 2016 to March 23, 2016 .
Exelon
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
Settlements
Acquisitions
Total recognized in AOCI and
regulatory assets (liabilities)
Total recognized in AOCI
Total recognized in regulatory
assets (liabilities)
$
$
$
Pension Benefits
Other
Postretirement Benefits
2018
2017
2016 (a)
2018
2017
2016 (a)
635 $
(629)
(222) $
(607)
644 $
(554)
(232) $
(66)
(4)
(2)
(3)
—
9
(1)
(3)
—
(60)
(14)
—
994
—
186
—
—
166 $
(61)
—
188
—
—
(3)
$
(824) $
1,010 $
(112)
$
293 $
3 $
(401) $
51 $
(55) $
168 $
(6) $
(423) $
959 $
(57) $
125 $
398
(101)
(63)
—
185
—
94
115
20
95
Table of Contents
Combined Notes to Consolidated Financial Statements - (Continued)
(Dollars in millions, except per share data unless otherwise noted)
PHI
Changes in plan assets and benefit
obligations recognized in AOCI and regulatory assets (liabilities):
Current year actuarial loss (gain)
Amortization of actuarial loss
Amortization of prior service (cost) credit
Total recognized in AOCI and regulatory assets (liabilities)
Total recognized in AOCI
$
$
$
Total recognized in regulatory assets (liabilities)
__________
(a) 2016 amounts include PHI for the period of March 24, 2016 through December 31, 2016.
$
Pension Benefits
Other
Postretirement Benefits
Predecessor
January 1, 2016 to March 23, 2016
January 1, 2016 to March 23, 2016
— $
(14)
—
(14) $
(1) $
(13) $
—
(2)
3
1
—
1
The following table provides the components of gross accumulated other comprehensive loss and regulatory assets (liabilities) that have not been recognized as
components of periodic benefit cost at December 31, 2018 and 2017 , 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
Exelon
Pension Benefits
Exelon
Other
Postretirement Benefits
2018
2017
2018
2017
$
$
$
$
(29)
$
7,558
7,529 $
3,899 $
3,630 $
(24) $
7,556
7,532 $
3,896 $
3,636 $
(337) $
531
194 $
70 $
124 $
(522)
829
307
125
182
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. The average remaining service period of Exelon's defined benefit pension plan participants was 12.0 years, 11.8 years and 11.9
years for the years ended December 31, 2018 , 2017 and 2016 , respectively.
For other postretirement benefits, 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 average remaining service
period of postretirement benefit plan participants related to benefit eligibility age was 8.8 years, 8.8 years and 9.0 years for the years ended December 31, 2018
, 2017 and 2016 , respectively. The average remaining service period of postretirement benefit plan participants related to expected retirement was 9.5 years,
9.6 years and 9.7 years for the years ended December 31, 2018 , 2017 and 2016 , respectively.
Assumptions
399
Table of Contents
Combined Notes to Consolidated Financial Statements - (Continued)
(Dollars in millions, except per share data unless otherwise noted)
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, including the discount rate applied to benefit obligations, the long-term EROA, Exelon’s expected level of contributions to the
plans, the long-term expected investment rate credited to employees participating in cash balance plans and the anticipated rate of increase of health care costs.
Additionally, assumptions related to plan participants include the incidence of mortality, the expected remaining service period, the level of compensation and
rate of compensation increases, employee age and length of service, 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. Exelon’s mortality assumption is supported by an actuarial experience
study of Exelon's plan participants and utilizes 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. There were no changes to the mortality assumption in
2016 , 2017 or 2018 .
The following assumptions were used to determine the benefit obligations for the plans at December 31, 2018 , 2017 and 2016 . Assumptions used to determine
year-end benefit obligations are the assumptions used to estimate the subsequent year’s net periodic benefit costs.
Exelon
Discount rate
Investment Crediting
Rate
Rate of compensation
increase
Mortality table
Pension Benefits
Other Postretirement Benefits
2018
2017
2016 (f)
2018
2017
2016 (f)
4.31% (a)
3.62% (b)
4.04%
(c)
4.30% (a)
3.61% (b)
4.04%
(c)
4.46%
4.00%
4.46%
N/A
N/A
N/A
(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)
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)
N/A
N/A
Health care cost trend
on covered charges
__________
(a) The discount rates above represent the blended rates used to determine the majority of Exelon’s pension and other postretirement benefits obligations as of
December 31, 2018 . Certain benefit plans used individual rates ranging from 4.13% - 4.36% and 4.27% - 4.38% for pension and other postretirement plans, respectively.
(b) The discount rates above represent the blended rates used to determine the majority of Exelon’s pension and other postretirement benefits obligations as of
December 31, 2017 . Certain benefit plans used individual rates ranging from 3.49% - 3.65% and 3.57% - 3.68% for pension and other postretirement plans, respectively.
(c) The discount rates above represent the blended rates used to determine the majority of Exelon’s pension and other postretirement benefits obligations as of
December 31, 2016 . Certain benefit plans used individual rates ranging from 3.66% - 4.11% and 4.00% - 4.17% for pension and other postretirement plans, respectively.
N/A
5.00% with ultimate
trend of 5.00% in
2017
5.00% with
ultimate
trend of
5.00% in
2017
5.00%
decreasing
to
ultimate
trend of
5.00% in
2017
(d) 3.25% through 2019 and 3.75% thereafter.
400
Table of Contents
Combined Notes to Consolidated Financial Statements - (Continued)
(Dollars in millions, except per share data unless otherwise noted)
(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 other postretirement plans used a weighted-average rate of compensation increase of 5% for all periods.
(f) Obligation was not remeasured for the PHI predecessor for the period from January 1, 2016, to March 23, 2016.
The following assumptions were used to determine the net periodic benefit costs for the plans for the years ended December 31, 2018 , 2017 and 2016 , as well
as for the PHI predecessor period January 1, 2016 to March 23, 2016 :
Exelon
Discount rate
Investment
Crediting Rate
Expected return on
plan assets
Rate of
compensation
increase
2018
3.62% (a)
4.00%
Pension Benefits
2017
2016
2018
2017
2016
Other Postretirement Benefits
4.04% (b)
4.29% (c)
3.61% (a)
4.04% (b)
4.29% (c)
4.46%
5.31%
N/A
N/A
N/A
7.00% (d)
7.00% (d)
7.00% (d)
6.60% (d)
6.58% (d)
6.71% (d)
(e)
(f)
(f)
(e)
(f)
(f)
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)
Health care cost
trend on covered
charges
N/A
N/A
N/A
PHI
Discount rate
Investment crediting rate
Expected return on plan assets (h)
Rate of compensation
increase
Mortality table
5.00%
with
ultimate
trend of
5.00% in
2017
5.00%
with
ultimate
trend of
5.00% in
2017
Predecessor
5.50%
decreasing
to
ultimate
trend of
5.00% in
2017
Pension Benefits
Other Postretirement Benefits
January 1, 2016 to March 23, 2016
January 1, 2016 to March 23, 2016
4.65%/4.55% (g)
2.89%
6.50%
5.00%
4.55%
N/A
6.75%
5.00%
RP-2014 table with improvement
scale MP-2015
RP-2014 table with improvement
scale MP-2015
Health care cost trend on covered charges
N/A
6.33% pre-65 and 5.40% post-65
decreasing to ultimate trend of
5.00% in 2020
__________
(a) The discount rates above represent the blended rates used to establish the majority of Exelon’s pension and other postretirement benefits costs for the year ended
December 31, 2018 . Certain benefit plans used individual rates ranging from 3.49% - 3.65% and 3.57% - 3.68% for pension and other postretirement plans, respectively.
(b) The discount rates above represent the blended rates used to establish the majority of Exelon's pension and other postretirement benefits costs for the year ended
December 31, 2017 . Certain benefit plans used individual rates ranging from 3.66% - 4.11% and 4.00% - 4.17% for pension and other postretirement plans, respectively.
(c) The discount rates above represent the blended rates used to establish the majority of Exelon’s pension and other postretirement benefits costs for the year ended
December 31, 2016 . Certain benefit plans used the individual rates ranging from 3.68% - 4.14% and 4.32% - 4.43% for pension and other postretirement plans,
respectively.
401
Table of Contents
Combined Notes to Consolidated Financial Statements - (Continued)
(Dollars in millions, except per share data unless otherwise noted)
(d) Not applicable to pension and other postretirement benefit plans that do not have plan assets.
(e) 3.25% through 2019 and 3.75% thereafter.
(f)
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 other postretirement plans used a weighted-average rate of compensation increase of 5% for all periods.
(g) The discount rate for the qualified and non-qualified pension plans was 4.65% and 4.55% , respectively.
(h) Expected return on other postretirement benefit plan assets is pre-tax.
Contributions
The following tables provide contributions to the pension and other postretirement benefit plans:
Exelon
Generation
ComEd
PECO
BGE
BSC (b)
Pepco
DPL
ACE
PHISCO (c)
Pension Benefits
Other Postretirement Benefits
2018 (a)
2017 (a)
2016 (a)
2018
2017
2016
$
337
$
128
341
$
137
347
$
140
38
28
40
41
6
—
6
50
36
24
39
38
62
—
—
5
33
30
31
39
24
22
15
17
46
$
64
$
11
4
—
14
5
11
—
—
1
11
5
—
14
2
10
2
20
—
50
12
5
—
18
3
8
—
2
2
Pension Benefits
Successor
Predecessor
Other Postretirement Benefits
Successor
Predecessor
2018
2017
March 24, 2016 to
December 31, 2016
January 1, 2016 to March
23, 2016
2018
2017
March 24, 2016 to
December 31, 2016
January 1, 2016 to March
23, 2016
62 $
67 $
$
PHI
__________
(a) Exelon's and Generation's pension contributions include $21 million and $25 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 years ended December 31, 2017 and 2016 , respectively. There were no pension contributions
for the year ended December 31, 2018 .
Includes $2 million , $4 million , and $6 million of pension contributions funded by Exelon Corporate, for the years ended December 31, 2018 , 2017 , and 2016 ,
respectively.
(b)
—
4 $
12 $
32 $
74 $
12 $
(c) PHISCO’s pension contributions for the year ended December 31, 2016 include $4 million of contributions made prior to the closing of Exelon’s merger with PHI on
March 23, 2016 .
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 of contributing the greater of (1) $300 million until all the qualified plans are fully funded on an ABO basis,
and (2) the minimum amounts under ERISA to meet minimum contribution requirement and/or avoid benefit restrictions and at-risk status. This level funding
strategy helps minimize volatility of future period required pension contributions. 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,
402
Table of Contents
Combined Notes to Consolidated Financial Statements - (Continued)
(Dollars in millions, except per share data unless otherwise noted)
Exelon’s management has historically considered several factors in determining the level of contributions to its other postretirement benefit 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 2019:
Exelon
Generation
ComEd
PECO
BGE
BSC
PHI
Pepco
DPL
ACE
PHISCO
Qualified Pension Plans
Non-Qualified Pension Plans
Other
Postretirement
Benefits
$
$
301
135
65
25
34
41
1
—
—
—
1
25
$
7
1
1
1
7
8
2
1
—
5
44
13
2
—
15
2
12
10
—
1
1
Estimated Future Benefit Payments
Estimated future benefit payments to participants in all of the pension plans and postretirement benefit plans at December 31, 2018 were:
2019
2020
2021
2022
2023
2024 through 2028
Total estimated future benefit payments through 2028
Allocation to Exelon Subsidiaries
Pension
Benefits
Other
Postretirement
Benefits
$
$
1,196 $
1,221
1,258
1,284
1,302
6,770
13,031
$
255
263
269
274
282
1,483
2,826
All registrants account for their participation in Exelon’s pension and other postretirement benefit plans by applying multi-employer accounting. Employee-related
assets and liabilities, including both pension and postretirement liabilities, for the legacy Exelon plans were allocated by Exelon to its subsidiaries based on the
number of active employees as of January 1, 2001 as part of Exelon’s corporate restructuring. The obligation for Generation, ComEd and PECO reflects the
initial allocation and the cumulative costs incurred and contributions made since January 1, 2001. Historically, Exelon has allocated the components of pension
and other postretirement costs to the subsidiaries in the legacy Exelon plans based upon several factors, including the measures of active employee
participation in each plan. Pension and other postretirement benefit contributions were allocated to legacy Exelon subsidiaries in proportion to active service
costs recognized and total costs recognized, respectively. Beginning in 2015, Exelon began allocating costs related to its legacy Exelon pension and other
postretirement benefit plans to its subsidiaries based on both active and retired employee participation and contributions are allocated based on accounting cost.
The impact of this allocation methodology change was not material to any Registrant. For legacy CEG, legacy
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Table of Contents
Combined Notes to Consolidated Financial Statements - (Continued)
(Dollars in millions, except per share data unless otherwise noted)
CENG, FitzPatrick, and legacy PHI plans, components of pension and other postretirement benefit costs and contributions have been, and will continue to be,
allocated to the subsidiaries based on employee participation (both active and retired).
The amounts below represent the Registrants’ as well as BSC's and PHISCO's 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 years ended
December 31, 2017 and 2016. For Exelon, the service cost component is included in Operating and maintenance expense and Property, plant and equipment,
net, for the years ended December 31, 2018, 2017 and 2016, while the non–service cost components are included in Other, net and Regulatory assets for year
ended December 31, 2018 and in Other, net and Property, plant and equipment, net, for the years ended December 31, 2017 and 2016. For Generation and the
Utility Registrants, the service cost and non–service cost components are included in Operating and maintenance expense and Property, plant and equipment,
net on their consolidated financial statements for the years ended December 31, 2018 , 2017 and 2016 .
For the Years Ended
December 31,
2018
2017
2016
Exelon
Generation (a)
ComEd
PECO
BGE
BSC (b)
Pepco (c)
DPL (c)
ACE (c)
PHISCO (c)(d)
$
583 $
643
621
$
204
227
218
177
176
166
$
18 $
60 $
57 $
15 $
6 $
12 $
29
33
64
68
53
48
25
31
13
18
13
15
34
43
47
PHI
Pension and Other Postretirement Benefit Costs
Successor
Predecessor
For the Year Ended
December 31, 2018
For the Year Ended
December 31, 2017
March 24, 2016 to
December 31, 2016
January 1, 2016 to March 23,
2016
$
67 $
94 $
88 $
23
__________
(a) FitzPatrick net benefit costs are included for the period after acquisition.
(b) These amounts primarily represent amounts billed to Exelon’s subsidiaries through intercompany allocations. These amounts are not included in the Generation, ComEd,
PECO, BGE, PHI, Pepco, DPL or ACE amounts above.
(c) Pepco's, DPL's, ACE's and PHISCO's pension and postretirement benefit costs for the year ended December 31, 2016 include $7 million , $4 million , $3 million and $9
million , respectively, of costs incurred prior to the closing of Exelon’s merger with PHI on March 23, 2016 .
(d) These amounts represent amounts billed to Pepco, DPL and ACE through intercompany allocations. These amounts are not included in Pepco, DPL or ACE amounts
above.
Plan Assets
Investment Strategy. On a regular basis, Exelon evaluates its investment strategy to ensure that plan assets will be sufficient to pay 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 other postretirement benefit plans. The actual asset returns
across Exelon’s pension and other postretirement benefit plans for the year ended December 31, 2018 were (4.86)% and (4.66)% , respectively, compared to an
expected long-term return assumption of 7.00% and 6.60% , respectively.
Exelon used an EROA of 7.00% and 6.67% to estimate its 2019 pension and other postretirement benefit costs, respectively.
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Table of Contents
Combined Notes to Consolidated Financial Statements - (Continued)
(Dollars in millions, except per share data unless otherwise noted)
Exelon’s pension and other postretirement benefit plan target asset allocations at December 31, 2018 and 2017 asset allocations were as follows:
Pension Plans
Asset Category
Equity securities
Fixed income securities
Alternative investments (a)
Total
Other Postretirement Benefit Plans
Asset Category
Equity securities
Fixed income securities
Alternative investments (a)
Total
Exelon
Percentage of Plan Assets
at December 31,
Target Allocation
2018
2017
35%
37%
28%
32%
38
30
100%
Exelon
Percentage of Plan Assets
at December 31,
Target Allocation
2018
2017
47%
28%
25%
44%
28
28
100%
35%
39
26
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 other postretirement benefit plans’ asset portfolios for the existence of significant concentrations
of credit risk as of December 31, 2018 . 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, 2018 , there were no significant concentrations (defined as greater than 10% of plan
assets) of risk in Exelon’s pension and other postretirement benefit plan assets.
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Table of Contents
Fair Value Measurements
Combined Notes to Consolidated Financial Statements - (Continued)
(Dollars in millions, except per share data unless otherwise noted)
The following tables present pension and other postretirement benefit plan assets measured and recorded at fair value in the Registrants' Consolidated Balance
Sheets on a recurring basis and their level within the fair value hierarchy at December 31, 2018 and 2017 :
Exelon
December 31, 2018 (a)
Pension plan assets
Cash equivalents
Equities (c)
Fixed income:
U.S. Treasury and agencies
State and municipal debt
Corporate debt
Other (c)
Fixed income subtotal
Private equity
Hedge funds
Real estate
Private credit
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
$
7,247 $
16,720
December 31, 2018 (a)
Other postretirement benefit 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
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
Other postretirement benefit plan assets subtotal
Total pension and other postretirement benefit plan assets (e)
$
$
753
$
304
$
5,463 $
4,581 $
— $
486 $
1,353
$
2,410
8,600 $
19,130
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Table of Contents
December 31, 2017 (a)(b)
Pension plan assets
Cash equivalents
Equities (c)
Fixed income:
U.S. Treasury and agencies
State and municipal debt
Corporate debt
Other (c)
Fixed income subtotal
Private equity
Hedge funds
Real estate
Private credit (d)
Combined Notes to Consolidated Financial Statements - (Continued)
(Dollars in millions, except per share data unless otherwise noted)
Level 1
Level 2
Level 3
Not subject to leveling
Total
— $
—
— $
2
— $
3,077
$
585 $
3,565
1,150
—
—
—
1,150
—
—
—
—
159
64
3,931
447
4,601
—
—
—
—
—
—
232
—
232
—
—
—
224
458 $
585
6,644
1,309
64
4,163
1,203
6,739
1,034
1,770
884
919
—
—
—
756
756
1,034
1,770
884
695
Pension plan assets subtotal
$
5,300
$
4,601
$
8,216
$
18,575
December 31, 2017 (a)(b)
Other postretirement benefit 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
Level 1
Level 2
Level 3
Not subject to leveling
Total
$
29 $
523
— $
2
— $
—
— $
764
29
1,289
13
—
—
225
238
—
—
—
56
136
47
71
310
—
—
—
—
—
—
—
—
—
—
—
—
—
—
185
185
430
124
123
69
136
47
481
733
430
124
123
Other postretirement benefit plan assets subtotal
$
790
$
312
$
— $
1,626 $
2,728
Total pension and other postretirement benefit plan assets (e)
__________
(a) See Note 11 — Fair Value of Financial Assets and Liabilities for a description of levels within the fair value hierarchy.
(b) Effective March 31, 2017, Exelon became sponsor of FitzPatrick's defined benefit pension and other postretirement benefit plans, and assumed FitzPatrick's benefit plan
6,090 $
4,913 $
9,842 $
458 $
21,303
$
(c)
obligations.
Includes derivative instruments of less than $1 million and $6 million , which have a total notional amount of $5,991 million and $3,606 million at December 31, 2018 and
2017 , 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.
(d) Prior year amounts reflect a reclassification from Not subject to leveling into Level 3.
(e) Excludes net liabilities of $44 million and net assets of $2 million at December 31, 2018 and 2017 , 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.
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Table of Contents
Combined Notes to Consolidated Financial Statements - (Continued)
(Dollars in millions, except per share data unless otherwise noted)
The following table presents the reconciliation of Level 3 assets and liabilities measured at fair value for pension and other postretirement benefit plans for the
years ended December 31, 2018 and 2017 :
Exelon
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 (b)
Balance as of December 31, 2018
Pension Assets
Balance as of January 1, 2017
Actual return on plan assets:
Relating to assets still held at the
reporting date
Purchases, sales and settlements:
Purchases
Sales
Settlements (b)
Balance as of December 31, 2017
Fixed Income
Equities
Private
Credit
Total
$
232
$
2 $
224 $
458
(14)
(1)
19
(8)
(12)
—
—
—
—
—
9
—
35
—
—
216
$
2 $
268 $
Fixed income
Equities
Private
Credit (a)
Total
206
$
2 $
229 $
11
31
(16)
—
—
—
—
—
29
5
—
(39)
232
$
2
$
224 $
(5)
(1)
54
(8)
(12)
486
437
40
36
(16)
(39)
458
$
$
$
__________
(a) Prior year amounts reflect a reclassification from Not subject to leveling into Level 3.
(b) Represents cash settlements only.
There were no significant transfers between Level 1 and Level 2 during the year ended December 31, 2018 for the pension and other postretirement benefit plan
assets.
Valuation Techniques Used to Determine Fair Value
Cash equivalents. Investments with original maturities of three months or less when purchased, including certain short-term fixed income securities 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.
Equities. Equities 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 is 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. Equity securities
are valued based on quoted prices in active
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Table of Contents
Combined Notes to Consolidated Financial Statements - (Continued)
(Dollars in millions, except per share data unless otherwise noted)
markets and are categorized as Level 1. Certain private placement equity securities are categorized as Level 3 because they are not publicly traded and are
priced using significant unobservable inputs.
Equity commingled funds and mutual funds are maintained by investment companies, and certain investments are held in accordance with a stated set of fund
objectives, which are consistent with the plans’ overall investment strategy. 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 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 has obtained an understanding of how these prices are
derived, including the nature and observability of the inputs used in deriving such prices. Additionally, Exelon selectively corroborates the fair values of securities
by comparison to other market-based price sources. Investments in U.S. Treasury securities have been categorized as Level 1 because they trade in highly-
liquid and transparent markets. Certain private placement fixed income securities have been categorized as Level 3 because they are priced using certain
significant unobservable inputs and are typically illiquid. The remaining fixed income securities, including certain other fixed income investments, are based on
evaluated prices that reflect observable market information, such as actual trade information of similar securities, adjusted for observable differences and are
categorized as Level 2.
Other fixed income investments primarily consist of fixed income commingled funds and mutual funds, which are maintained by investment companies and hold
certain investments in accordance with a stated set of fund objectives, which are consistent with Exelon’s overall investment strategy. 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 with 30 or less days of notice and without further restrictions.
Derivative 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 equity. Private equity 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.
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.
Real estate. Real estate funds 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
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Table of Contents
Combined Notes to Consolidated Financial Statements - (Continued)
(Dollars in millions, except per share data unless otherwise noted)
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.
Private credit. Private credit investments primarily consist of limited partnerships that invest 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 are categorized as Level 3
because they are based largely on inputs that are unobservable and utilize complex valuation models. The fair value of private credit funds are determined using
NAV or its equivalent as a practical expedient, and therefore, these investments are not classified within the fair value hierarchy.
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, 2018 , 2017 and 2016 :
For the Year Ended
December 31,
2018
2017
2016
PHI
Exelon (a)
Generation (a)
ComEd
PECO
BGE
BSC (b)
Pepco (c)
DPL (c)
ACE
PHISCO (c)(d)
$
179 $
128
164
$
86
55
79
$
37
31
34
$
9
10
10
$
12
10
12
22 $
9
19
3 $
3
3
2 $
2
2
2 $
2
2
6
6
6
For the Year Ended
December 31, 2018
For the Year Ended
December 31, 2017
March 24, 2016 to
December 31, 2016
January 1, 2016 to March
23, 2016
Successor
Predecessor
Saving Plan Matching Contributions
__________
(a)
(b) These amounts primarily represent amounts billed to Exelon’s subsidiaries through intercompany allocations. These costs are not included in the Generation, ComEd,
Includes $13 million related to CENG for the year ended December 31, 2016.
3
$
10 $
13 $
13 $
PECO, BGE, PHI, Pepco, DPL or ACE amounts above.
(c) Pepco's, DPL's and PHISCO's matching contributions include $1 million , $1 million and $1 million , respectively, of costs incurred prior to the closing of Exelon's merger
with PHI on March 23, 2016, which is not included in Exelon's matching contributions for the year ended December 31, 2016.
(d) These amounts primarily represent amounts billed to Pepco, DPL, and ACE through intercompany allocations. These amounts are not included in Pepco, DPL or ACE
amounts above.
17. Severance (All Registrants)
The Registrants have an ongoing severance plan under which, in general, the longer an employee worked prior to termination the greater the amount of
severance benefits. The Registrants record a liability and expense or regulatory asset for severance once terminations are probable of occurrence and the
related severance benefits can be reasonably estimated. For severance benefits that are incremental to its ongoing severance plan (“one-time termination
benefits”), the Registrants measure the obligation and record the expense at fair value at the communication date if there are no future service requirements, or,
if future service is required to receive the termination benefit, ratably over the required service period.
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Table of Contents
Severance Liability
Combined Notes to Consolidated Financial Statements - (Continued)
(Dollars in millions, except per share data unless otherwise noted)
Amounts included in the table below represent the severance liability recorded for employees of each Registrant. Exelon's severance liability includes amounts
related to BSC that are billed through intercompany allocations .
Severance Liability
Exelon
Generation
ComEd
PECO
BGE
PHI
Pepco
DPL
ACE
Balance at December 31, 2016
$
Severance costs (a)
Payments
Balance at December 31, 2017
$
Severance costs (a)
Payments
88 $
35
(29)
94 $
35
(52)
Balance at December 31, 2018
$
77
$
36 $
31
(9)
58 $
9
(20)
47
$
__________
(a)
Includes salary continuance and health and welfare severance benefits.
Severance Costs Related to the PHI Merger
3 $
2
(2)
3 $
1
(2)
2
— $
— $
29 $
— $
— $
—
—
—
—
3
(12)
—
—
—
—
— $
— $
20 $
— $
— $
—
—
1
—
5
(18)
1
(1)
—
—
$
— $
1
$
7
$
— $
— $
—
—
—
—
—
—
—
Upon closing the PHI Merger, Exelon recorded a severance accrual for the anticipated employee position reductions as a result of the post-merger integration.
Cash payments under the plan began in May 2016 and will continue through 2020.
For the years ended December 31, 2018 and December 31, 2017 , the PHI Merger severance costs were immaterial. For the year ended December 31, 2016 ,
the Registrants recorded the following severance costs associated with the identified job reductions within Operating and maintenance expense in their
Consolidated Statements of Operations and Comprehensive Income:
Severance Benefits
Severance costs (a)
Exelon
Generation
ComEd
PECO
BGE
PHI
Pepco
DPL
ACE
$
57 $
9 $
2 $
1 $
1 $
44 $
21 $
13 $
10
(a) The amounts above for Generation, ComEd, PECO, BGE, Pepco, DPL, and ACE include $8 million , $2 million , $1 million , $1 million , $20 million , $12 million and $10 million ,
respectively, for amounts billed by BSC and/or PHISCO through intercompany allocations.
PHI, Pepco, DPL and ACE recorded regulatory assets for merger related integration costs which include a portion of these severance costs. These regulatory
assets are either currently being recovered in rates or are deemed probable of recovery in future rates. See Note 4 — Regulatory Matters for additional
information.
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Table of Contents
Combined Notes to Consolidated Financial Statements - (Continued)
(Dollars in millions, except per share data unless otherwise noted)
18. Shareholders' Equity (Exelon, ComEd, PECO, BGE, Pepco, DPL and ACE)
The following table presents common stock authorized and outstanding as of December 31, 2018 and 2017 :
Common Stock
Exelon
ComEd
PECO
BGE
Pepco
DPL
ACE
Par Value
Shares Authorized
Shares Outstanding
December 31,
2018
2017
no par value
2,000,000,000
$
$
$
$
12.50
no par value
no par value
0.01
2.25
3.00
250,000,000
500,000,000
1,500
200,000,000
1,000
25,000,000
968,187,955
127,021,331
170,478,507
1,000
100
1,000
963,335,888
127,021,246
170,478,507
1,000
100
1,000
8,546,017
8,546,017
ComEd had 60,285 and 60,584 warrants outstanding to purchase ComEd common stock at December 31, 2018 and 2017 , respectively. 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. At December 31, 2018
and 2017 , 20,095 and 20,195 shares of common stock, respectively, were reserved for the conversion of warrants.
Equity Securities Offering
In June 2014, Exelon marketed an equity offering of 57.5 million shares of its common stock at a public offering price of $35 per share. In connection with such
offering, Exelon entered into forward sale agreements with two counterparties. In July 2015, Exelon settled the forward sale agreement by the issuance of 57.5
million shares of Exelon common stock. Exelon received net cash proceeds of $1.87 billion , which was calculated based on a forward price of $32.48 per share
as specified in the forward sale agreements. The net proceeds were used to fund the merger with PHI and related costs and expenses, and for general
corporate purposes. The forward sale agreements are classified as equity transactions. As a result, no amounts were recorded in the consolidated financial
statements until the July 2015 settlement of the forward sale agreements. However, prior to the July 2015 settlement, incremental shares, if any, were included
within the calculation of diluted EPS using the treasury stock method.
Concurrent with the forward equity transaction, Exelon also issued $1.15 billion of junior subordinated notes in the form of 23 million equity units. On June 1,
2017, Exelon settled the forward purchase contract, which was a component of the June 2014 equity units, through the issuance of Exelon common stock from
treasury stock. See Note 13 — Debt and Credit Agreements for additional information on the equity units.
Share Repurchases
Share Repurchase Programs
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. Under the previous share repurchase programs, 2 million shares of common stock were held as
treasury stock with a historical cost of $123 million at December 31, 2018 and 2017 . During 2017 , Exelon issued approximately 33 million shares of Exelon
common stock from treasury stock in order to settle the forward purchase contract, which was a component of the June 2014 equity units discussed above.
During 2018 , 2017 , and 2016 Exelon had no common stock repurchases.
Preferred and Preference Securities of Subsidiaries
At December 31, 2018 and 2017 , Exelon was authorized to issue up to 100,000,000 shares of preferred securities, none of which were outstanding.
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Combined Notes to Consolidated Financial Statements - (Continued)
(Dollars in millions, except per share data unless otherwise noted)
At December 31, 2018 and 2017 , ComEd prior preferred securities and ComEd cumulative preference securities consisted of 850,000 shares and 6,810,451
shares authorized, respectively, none of which were outstanding.
BGE had $190 million of cumulative preference stock that was redeemable at its option at any time after October 1, 2015 for the redemption price of $100 per
share, plus accrued and unpaid dividends. On July 3, 2016, BGE redeemed all 400,000 shares of its outstanding 7.125% Cumulative Preference Stock, 1993
Series and all 600,000 shares of its outstanding 6.990% Cumulative Preference Stock, 1995 Series for $100 million , plus accrued and unpaid dividends. On
September 18, 2016, BGE redeemed the remaining 500,000 shares of its outstanding 6.970% Cumulative Preference Stock, 1993 Series and the remaining
400,000 shares of its outstanding 6.700% Cumulative Preference Stock, 1993 Series for $90 million , plus accrued and unpaid dividends.
19. Stock-Based Compensation Plans (All Registrants)
Stock-Based Compensation Plans
Exelon grants stock-based awards through its LTIP, which primarily includes stock options, restricted stock units and performance share awards. At
December 31, 2018 , there were approximately 11 million shares authorized for issuance under the LTIP. For the years ended December 31, 2018 , 2017 and
2016 , exercised and distributed stock-based awards were primarily issued from authorized but unissued common stock shares.
ComEd, PECO, BGE and PHI grant cash awards. The following tables do not include expense related to these plans as they are not considered stock-based
compensation plans under the applicable authoritative guidance .
In connection with the acquisition of PHI in March 2016, PHI’s unvested time-based restricted stock units and performance-based restricted stock units issued
prior to April 29, 2014 were immediately vested and paid in cash upon the close of the merger. PHI’s remaining unvested time-based restricted stock units as of
the close of the merger were cancelled. There were no remaining unvested performance-based restricted stock units as of the close of the merger.
For the years ended December 31, 2018 , 2017 and 2016 , there were no significant modifications to the granted stock based awards.
The following tables present the stock-based compensation expense included in Exelon's and PHI’s Consolidated Statements of Operations and Comprehensive
Income for the years ended December 31, 2018 , 2017 and 2016 and PHI's predecessor period January 1, 2016 to March 23, 2016 :
Exelon
Components of Stock-Based Compensation Expense
Performance share awards
Restricted stock units
Stock options
Other stock-based awards
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,
2018
2017
2016 (a)
143 $
107 $
57
—
8
208
(54)
154 $
77
—
7
191
(74)
117 $
93
75
—
7
175
(68)
107
$
$
__________
(a) 2016 amounts include expense related to stock-based compensation granted to eligible PHI employees since the merger date of March 23, 2016 .
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PHI
Combined Notes to Consolidated Financial Statements - (Continued)
(Dollars in millions, except per share data unless otherwise noted)
Components of Stock-Based Compensation Expense
Time-based restricted stock units
Performance-based restricted stock units
Time-based restricted stock awards
Total stock-based compensation expense included in operating and
maintenance expense
Income tax benefit
Total after-tax stock-based compensation expense
Predecessor
January 1 to March 23,
2016
2
1
—
3
(1)
2
$
$
The following tables present the Registrants' stock-based compensation expense (pre-tax) for the years ended December 31, 2018 , 2017 and 2016 , as well as
for the PHI predecessor period January 1, 2016 to March 23, 2016 :
Subsidiaries
Exelon
Generation
ComEd
PECO
BGE
BSC (a)
PHI Successor (b)(c)
Year Ended
December 31,
2018
2017
2016
$
208 $
191 $
77
8
5
3
111
4
88
7
3
1
88
4
Predecessor
January 1 to
March 23,
2016
175
78
8
3
1
81
4
PHI
__________
(a) These amounts primarily represent amounts billed to Exelon’s subsidiaries through intercompany allocations. These amounts are not included in the Generation, ComEd,
3
$
PECO, BGE or PHI amounts above.
(b) Pepco's, DPL's and ACE's stock-based compensation expense for the years ended December 31, 2018 and 2017 was not material.
(c) These amounts primarily represent amounts billed to PHI’s subsidiaries through PHISCO intercompany allocations.
There were no significant stock-based compensation costs capitalized during the years ended December 31, 2018 , 2017 and 2016 for Exelon or PHI, or for PHI
during the predecessor period January 1, 2016 to March 23, 2016 .
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Combined Notes to Consolidated Financial Statements - (Continued)
(Dollars in millions, except per share data unless otherwise noted)
Exelon receives a tax deduction based on the intrinsic value of the award on the exercise date for stock options and the distribution date 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 tables present information regarding Exelon’s tax benefits for the years ended December 31, 2018 , 2017 and 2016 .
Exelon
Realized tax benefit when exercised/distributed:
Restricted stock units
Performance share awards
Stock Options
Year Ended December 31,
2018
2017
2016
28
16
35
29
27
18
Non-qualified stock options to purchase shares of Exelon’s common stock were granted under the LTIP through 2012. Due to changes in the LTIP, there were
no stock options granted in 2018 , 2017 and 2016 . For all stock options granted through 2012, the exercise price of the stock options is equal to the fair market
value of the underlying stock on the date of option grant. The vesting period of stock options is generally four years and all stock options will expire no later than
ten years from the date of grant.
The value of stock options at the date of grant is expensed over the requisite service period using the straight-line method. The requisite service period for stock
options is generally four years . However, certain stock options become fully vested upon the employee reaching retirement-eligibility. The value of the stock
options 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.
The following table presents information with respect to stock option activity for the year ended December 31, 2018 :
Balance of shares outstanding at December 31, 2017
Options exercised
Options forfeited
Options expired
Balance of shares outstanding at December 31, 2018
Exercisable at December 31, 2018 (a)
__________
(a)
Includes stock options issued to retirement eligible employees.
Weighted
Average
Exercise
Price
(per share)
Weighted
Average
Remaining
Contractual
Life
(years)
Aggregate
Intrinsic
Value
47.69
36.54
—
74.99
43.95
43.95
2.65 $
2.90 $
2.90 $
Shares
6,723,611 $
(1,522,952)
—
(1,173,007)
4,027,652 $
4,027,652 $
The following table summarizes additional information regarding stock options exercised for the years ended December 31, 2018 , 2017 and 2016 :
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.
$
415
Year Ended
December 31,
2018
2017
2016
12 $
56
15 $
107
7
14
14
11
19
Table of Contents
Combined Notes to Consolidated Financial Statements - (Continued)
(Dollars in millions, except per share data unless otherwise noted)
At December 31, 2016 , all stock options were vested and at December 31, 2018 there were no unrecognized compensation costs related to nonvested stock
options.
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.
The following table summarizes Exelon’s nonvested restricted stock unit activity for the year ended December 31, 2018 :
Exelon
Nonvested at December 31, 2017 (a)
Granted
Vested
Forfeited
Undistributed vested awards (b)
Nonvested at December 31, 2018 (a)
Shares
Weighted Average
Grant Date Fair
Value (per share)
3,389,503 $
1,321,988
(1,845,300)
(65,046)
(507,804)
2,293,341 $
32.24
38.60
32.03
32.96
36.76
35.06
__________
(a) Excludes 1,131,487 and 1,488,383 of restricted stock units issued to retirement-eligible employees as of December 31, 2018 and 2017 , respectively, as they are fully
vested.
(b) Represents restricted stock units that vested but were not distributed to retirement-eligible employees during 2018 .
For Exelon, the weighted average grant date fair value (per share) of restricted stock units granted for the years ended December 31, 2018 , 2017 and 2016 was
$38.60 , $34.98 and $28.14 , respectively. At December 31, 2018 and 2017 , Exelon had obligations related to outstanding restricted stock units not yet settled
of $83 million and $108 million , respectively, which are included in common stock in Exelon’s Consolidated Balance Sheets. For the years ended December 31,
2018 , 2017 and 2016 , Exelon settled restricted stock units with fair value totaling $106 million , $88 million and $68 million , respectively. At December 31, 2018
, $38 million of total unrecognized compensation costs related to nonvested restricted stock units are expected to be recognized over the remaining weighted-
average period of 2.5 years.
Performance Share Awards
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 - (Continued)
(Dollars in millions, except per share data unless otherwise noted)
Effective January 2017 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.
In 2016 and prior, for nonretirement-eligible employees, stock-based compensation costs are recognized over the vesting period of three years using the
graded-vesting 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 for the year ended December 31, 2018 :
Exelon
Nonvested at December 31, 2017 (a)
Granted
Change in performance
Vested
Forfeited
Undistributed vested awards (b)
Nonvested at December 31, 2018 (a)
Shares
Weighted Average
Grant Date Fair
Value (per share)
2,956,966 $
1,637,542
1,348,029
(848,574)
(50,467)
(1,640,268)
3,403,228 $
32.65
38.15
30.66
36.26
36.24
33.38
33.13
__________
(a) Excludes 3,586,259 and 2,723,440 of performance share awards issued to retirement-eligible employees as of December 31, 2018 and 2017 , respectively, as they are
fully vested.
(b) Represents performance share awards that vested but were not distributed to retirement-eligible employees during 2018 .
The following table summarizes the weighted average grant date fair value and the fair value of performance share awards granted and settled for the years
ended December 31, 2018 , 2017 and 2016 :
Weighted average grant date fair value (per share)
$
Fair value of performance shares settled
2018 (a)
38.15 $
61
Year Ended
December 31,
2017
35.00 $
72
2016
28.85
45
Fair value of performance shares settled in cash
__________
(a) As of December 31, 2018 , $33 million of total unrecognized compensation costs related to nonvested performance shares are expected to be recognized over the
28
56
49
remaining weighted-average period of 1.7 years.
For PHI, the weighted average grant date fair value (per share) of performance-based restricted stock awards was $26.10 for the year ended December 31,
2016 . There were no time-based restricted stock awards granted for the year ended December 31, 2016 . There were no time-based share settlements or
performance-based share settlements for the year-ended December 31, 2016 or the predecessor period January 1, 2016 to March 23, 2016 .
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Combined Notes to Consolidated Financial Statements - (Continued)
(Dollars in millions, except per share data unless otherwise noted)
The following table presents the balance sheet classification of obligations related to outstanding performance share awards not yet settled:
Current liabilities (a)
Deferred credits and other liabilities (b)
Common stock
Total
__________
(a) Represents the current liability related to performance share awards expected to be settled in cash.
(b) Represents the long-term liability related to performance share awards expected to be settled in cash.
20. Earnings Per Share (Exelon)
December 31,
2018
2017
135 $
109
26
270 $
57
100
26
183
$
$
Basic earnings per share is computed by dividing net income attributable to common stockholders by the weighted average number of common shares
outstanding during the period. Diluted earnings per share is computed by dividing net income attributable to common shareholders by the weighted average
number of common shares outstanding, including the effect of issuing common stock assuming (i) stock options are exercised, and (ii) performance share
awards and restricted stock awards are fully vested under the treasury stock method.
The following table sets forth the components of basic and diluted earnings per share and shows the effect of these stock options, performance share awards
and restricted stock awards on the weighted average number of shares outstanding used in calculating diluted earnings per share:
Net income attributable to common shareholders
Weighted average common shares outstanding — basic
Assumed exercise and/or distributions of stock-based awards
Weighted average common shares outstanding — diluted
Year Ended December 31,
2018
2017
2016
$
2,010
$
3,786
$
1,121
967
2
969
947
2
949
924
3
927
The number of stock options not included in the calculation of diluted common shares outstanding due to their antidilutive effect was approximately 3 million in
2018 , 8 million in 2017 , and 12 million in 2016 . There were no equity units related to the PHI merger not included in the calculation of diluted common shares
outstanding due to their antidilutive effect for the years ended December 31, 2018 , 2017 , and 2016 . See Note 18 — Shareholders' Equity for additional
information regarding the equity units and equity forward units.
On June 1, 2017, Exelon settled the forward purchase contract, which was a component of the June 2014 equity units, through the issuance of approximately 33
million shares of Exelon common stock from treasury stock. The issuance of shares on June 1, 2017 triggered full dilution in the EPS calculation, which prior to
settlement were included in the calculation of diluted EPS using the treasury stock method. See Note 18 — Shareholders' Equity for additional information
regarding share repurchases.
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Combined Notes to Consolidated Financial Statements - (Continued)
(Dollars in millions, except per share data unless otherwise noted)
21. Changes in Accumulated Other Comprehensive Income (Exelon, Generation and PECO)
The following tables present changes in accumulated other comprehensive income (loss) (AOCI) by component for the years ended December 31, 2018 and
2017 :
For the Year Ended December 31, 2018
Exelon (a)
Gains and
(Losses) on
Cash Flow
Hedges
Unrealized
Gains and (losses) on
Marketable
Securities
Pension and
Non-Pension
Postretirement
Benefit Plan
Items
Foreign
Currency
Items
AOCI of Investments
Unconsolidated
Affiliates
Total
Beginning balance
$
(14)
$
10 $
(2,998) $
(23) $
(1)
$
(3,026)
OCI before reclassifications
Amounts reclassified from AOCI (b)
Net current-period OCI
Impact of adoption of Recognition
and Measurement of Financial
Assets and Financial Liabilities
standard (c)
Ending balance
Generation (a)
Beginning balance
OCI before reclassifications
Amounts reclassified from AOCI (b)
Net current-period OCI
Impact of adoption of Recognition
and Measurement of Financial
Assets and Financial Liabilities
standard (c)
Ending balance
PECO (a)
Beginning balance
OCI before reclassifications
Amounts reclassified from AOCI (b)
Net current-period OCI
Impact of adoption of Recognition
and Measurement of Financial
Assets and Financial Liabilities
standard (c)
Ending balance
$
$
$
$
$
11
1
12
—
(2)
$
(16)
$
11
1
12
—
(4)
$
— $
—
—
—
—
— $
—
—
—
(143)
181
38
(10)
—
(10)
1
—
1
(141)
182
41
(10)
—
— $
(2,960)
$
—
(33)
$
—
(10)
—
$
(2,995)
3 $
—
—
—
(3)
— $
1 $
—
—
—
(1)
— $
419
— $
(23) $
(1)
$
(37)
—
—
—
(10)
—
(10)
—
— $
—
(33)
$
— $
— $
—
—
—
—
—
—
—
— $
—
— $
—
—
—
—
(1)
$
— $
—
—
—
—
—
$
1
1
2
(3)
(38)
1
—
—
—
(1)
—
Table of Contents
Combined Notes to Consolidated Financial Statements - (Continued)
(Dollars in millions, except per share data unless otherwise noted)
For the Year Ended December 31, 2017
Exelon (a)
Beginning balance
OCI before reclassifications
Amounts reclassified from AOCI (b)
Net current-period OCI
Impact of adoption of Reclassification
of Certain Tax Effects from AOCI (d)
Ending balance
Generation (a)
Beginning balance
OCI before reclassifications
Amounts reclassified from AOCI (b)
Net current-period OCI
Ending balance
PECO (a)
Beginning balance
OCI before reclassifications
Amounts reclassified from AOCI (b)
Net current-period OCI
Ending balance
$
$
$
$
$
$
Gains and
(Losses) on
Cash Flow
Hedges
Unrealized
Gains on
Marketable
Securities
Pension and
Non-Pension
Postretirement
Benefit Plan
items
Foreign
Currency
Items
AOCI of Investments
Unconsolidated
Affiliates
Total
(17)
$
(1)
4
3
—
(14)
$
(19)
$
(1)
4
3
(16)
$
— $
—
—
—
— $
4
6
—
6
—
10
2
1
—
1
3
1
—
—
—
1
$
$
$
$
$
$
(2,610)
$
(30)
$
(7)
$
(2,660)
11
140
151
7
—
7
(539)
—
(2,998)
$
(23)
$
6
—
6
29
144
173
—
(539)
(1)
$
(3,026)
— $
(30)
$
(7)
$
(54)
—
—
—
7
—
7
— $
(23)
$
— $
— $
—
—
—
—
—
—
— $
— $
6
—
6
(1)
13
4
17
$
(37)
— $
—
—
—
—
$
1
—
—
—
1
__________
(a) All amounts are net of tax and noncontrolling interests. Amounts in parenthesis represent a decrease in AOCI.
(b) See next tables for details about these reclassifications.
(c) 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 , $3 million and $1 million for Exelon, Generation and
PECO, respectively. The amounts reclassified related to Rabbi Trusts. See Note 1 — Significant Accounting Policies for additional information.
(d) 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. See Note 1 — Significant Accounting Policies for additional information.
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Combined Notes to Consolidated Financial Statements - (Continued)
(Dollars in millions, except per share data unless otherwise noted)
ComEd, PECO, BGE, PHI, Pepco, DPL and ACE did not have any reclassifications out of AOCI to Net income during the years ended December 31, 2018 and
2017 . The following tables present amounts reclassified out of AOCI to Net income for Exelon and Generation during the years ended December 31, 2018 and
2017 :
For the Year Ended December 31, 2018
Details about AOCI components
Items reclassified out of AOCI (a)
Affected line item in the Statement of Operations and
Comprehensive Income
Exelon
Generation
Gains (Losses) on cash flow hedges
Other cash flow hedges
Amortization of pension and other
postretirement benefit plan items
Prior service costs (b)
Actuarial losses (b)
Total Reclassifications
$
$
$
$
$
(1) $
(1)
—
(1)
$
90 $
(333)
(243)
62
(181)
$
(1)
(1)
Interest expense
Total before tax
— Tax benefit
(1)
Net of tax
—
—
— Total before tax
— Tax benefit
— Net of tax
(182)
$
(1)
Net of tax
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Table of Contents
For the Year Ended December 31, 2017
Combined Notes to Consolidated Financial Statements - (Continued)
(Dollars in millions, except per share data unless otherwise noted)
Details about AOCI components
Items reclassified out of AOCI (a)
Affected line item in the Statement of Operations and
Comprehensive Income
Exelon
Generation
Gains (Losses) on cash flow hedges
Other cash flow hedges
Amortization of pension and other postretirement benefit
plan items
Prior service costs (b)
Actuarial losses (b)
Total Reclassifications
$
$
$
$
$
(5) $
(5)
1
(4)
$
92 $
(324)
(232)
92
(140)
$
(5)
(5)
1
(4)
Interest expense
Total before tax
Tax benefit
Net of tax
—
—
—
Total before tax
— Tax benefit
—
Net of tax
(144)
$
(4)
Net of tax
__________
(a) Amounts in parenthesis represent a decrease in net income.
(b) This AOCI component is included in the computation of net periodic pension and OPEB cost. See Note 16 — Retirement Benefits for additional information.
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Combined Notes to Consolidated Financial Statements - (Continued)
(Dollars in millions, except per share data unless otherwise noted)
The following table presents income tax benefit (expense) allocated to each component of other comprehensive income (loss) during the years ended
December 31, 2018 , 2017 and 2016 :
Exelon
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
Change in unrealized gains on cash flow hedges
Change in unrealized gains (losses) on investments in unconsolidated affiliates
Change in unrealized gains on marketable securities
Total
Generation
Change in unrealized gains on cash flow hedges
Change in unrealized gains (losses) on investments in unconsolidated affiliates
Change in unrealized gains on marketable securities
Total
22. Commitments and Contingencies (All Registrants)
Commitments
For the Year Ended December 31,
2018
2017
2016
$
$
$
$
24 $
(86)
50
(5)
—
—
36 $
(128)
13
(7)
(3)
(1)
(17) $
(90)
$
(4) $
(1)
—
(5) $
(6) $
(3)
(1)
(10)
$
30
(118)
115
—
3
—
30
(2)
3
—
1
Constellation Merger Commitments (Exelon and Generation). In February 2012, the MDPSC issued an Order approving the Exelon and Constellation
merger. As part of the MDPSC Order, Exelon agreed to provide a package of benefits to BGE customers, the City of Baltimore and the State of Maryland,
resulting in an estimated direct investment in the State of Maryland of approximately $1 billion .
The direct investment included the construction of a new 21-story headquarters building in Baltimore for Generation’s competitive energy business that was
substantially complete in November 2016 and is now occupied by approximately 1,500 Exelon employees. Generation's investment in leasehold improvements
totaled approximately $90 million . In addition, Generation entered into a 20 -year operating lease as the primary lessee of the building.
The direct investment commitment also included $450 million to $500 million relating to Exelon and Generation’s development or assistance in the development
of 285 - 300 MWs of new generation in Maryland, which is expected to be completed within a period of 10 years after the merger. The MDPSC order
contemplated various options for complying with the new generation development commitments, including building or acquiring generating assets, making
subsidy or compliance payments, or in circumstances in which the generation build is delayed or certain specified provisions are elected, making liquidated
damages payments. Exelon and Generation have incurred $458 million towards satisfying the commitment for new generation development in the state of
Maryland, with approximately 220 MW of the new generation commencing with commercial operations to date and an additional 10 MW commitment satisfied
through a liquidated damages payment made in the fourth quarter of 2016. Additionally, during the fourth quarter of 2016, given continued declines in projected
energy and capacity prices, Generation terminated rights to certain development projects originally intended to meet its remaining 55 MW commitment amount.
The commitment is expected to be satisfied via payment of liquidated damages or execution of a third party PPA, rather than by Generation constructing
renewable generating assets. As a result, Exelon and Generation
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Table of Contents
Combined Notes to Consolidated Financial Statements - (Continued)
(Dollars in millions, except per share data unless otherwise noted)
recorded a pre-tax $50 million loss contingency in Operating and maintenance expense in Exelon’s and Generation’s Consolidated Statements of Operations
and Comprehensive Income for the year ended December 31, 2016. The remaining commitment is to be paid on or before January 15, 2023 unless the period is
extended by consent of Exelon and the State of Maryland. As of December 31, 2018 and 2017 , Exelon's and Generation's Consolidated Balance Sheets include
a $50 million liability within Deferred credits and other liabilities for this remaining commitment.
Commercial Commitments (All Registrants). Exelon’s commercial commitments as of December 31, 2018 , representing commitments potentially triggered by
future events, were as follows:
Letters of credit
Surety bonds (a)
Financing trust guarantees
Guaranteed lease residual values (b)
Total commercial commitments
Total
$
1,703 $
2019
1,394 $
Expiration within
2020
2021
2022
2023
2024 and beyond
308 $
1 $
— $
— $
1,402
1,331
378
24
—
3
33
—
3
38
—
2
—
—
3
—
—
3
$
3,507 $
2,728 $
344 $
41 $
3 $
3 $
—
—
378
10
388
__________
(a) Surety bonds—Guarantees issued related to contract and commercial agreements, excluding bid bonds.
(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 maximum lease term associated with these assets ranges from 3 to 8 years. The maximum potential obligation at the end of the minimum lease term would be $61
million , $19 million of which is a guarantee by Pepco, $26 million by DPL and $16 million by ACE. The minimum lease term associated with these assets ranges from 1 to
4 years. Historically, payments under the guarantees have not been made and PHI believes the likelihood of payments being required under the guarantees is remote.
Generation’s commercial commitments as of December 31, 2018 , representing commitments potentially triggered by future events, were as follows:
Letters of credit
Surety bonds (a)
Total commercial commitments
$
$
Total
1,680 $
2019
1,380 $
2020
2021
2022
2023
2024 and beyond
299 $
1 $
— $
— $
Expiration within
1,220
1,201
19
2,900 $
2,581 $
318 $
—
1 $
—
— $
—
— $
—
—
—
__________
(a) Surety bonds—Guarantees issued related to contract and commercial agreements, excluding bid bonds.
ComEd’s commercial commitments as of December 31, 2018 , representing commitments potentially triggered by future events, were as follows:
Letters of credit
Surety bonds (a)
Financing trust guarantees
Total commercial commitments
Expiration within
Total
2019
2020
2021
2022
2023
2024 and beyond
$
$
2 $
2 $
— $
— $
— $
— $
12
200
10
—
—
—
2
—
—
—
—
—
214 $
12 $
— $
2 $
— $
— $
—
—
200
200
__________
(a) Surety bonds—Guarantees issued related to contract and commercial agreements, excluding bid bonds.
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Table of Contents
Combined Notes to Consolidated Financial Statements - (Continued)
(Dollars in millions, except per share data unless otherwise noted)
PECO’s commercial commitments as of December 31, 2018 , representing commitments potentially triggered by future events, were as follows:
Surety bonds (a)
Financing trust guarantees
Total commercial commitments
Expiration within
Total
2019
2020
2021
2022
2023
2024 and beyond
$
$
9 $
178
187 $
9 $
—
9 $
— $
—
— $
— $
—
— $
— $
—
— $
— $
—
— $
—
178
178
__________
(a) Surety bonds—Guarantees issued related to contract and commercial agreements, excluding bid bonds.
BGE’s commercial commitments as of December 31, 2018 , representing commitments potentially triggered by future events, were as follows:
Letters of credit
Surety bonds (a)
Total commercial commitments
Total
2019
2020
2021
2022
2023
2024 and beyond
$
$
3 $
17
20 $
2 $
3
5 $
1 $
14
15 $
— $
—
— $
— $
—
— $
— $
—
— $
—
—
—
__________
(a) Surety bonds—Guarantees issued related to contract and commercial agreements, excluding bid bonds.
PHI commercial commitments as of December 31, 2018 , representing commitments potentially triggered by future events, were as follows:
Expiration within
Letters of credit
Surety bonds (a)
Guaranteed lease residual values (b)
Total commercial commitments
Expiration within
Total
2019
2020
2021
2022
2023
2024 and beyond
$
$
$
8 $
41 $
24
73
$
— $
41 $
3
8 $
— $
3
44
$
11
$
— $
— $
2
2
$
— $
— $
3
3
$
— $
— $
3
3
$
—
—
10
10
__________
(a) Surety bonds—Guarantees issued related to contract and commercial agreements, excluding bid bonds.
(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 maximum lease term associated with these assets ranges from 3 to 8 years. The maximum potential obligation at the end of the minimum lease term would be $61
million . The minimum lease term associated with these assets ranges from 1 to 4 years. Historically, payments under the guarantees have not been made and PHI
believes the likelihood of payments being required under the guarantees is remote.
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Table of Contents
Combined Notes to Consolidated Financial Statements - (Continued)
(Dollars in millions, except per share data unless otherwise noted)
Pepco commercial commitments as of December 31, 2018 , representing commitments potentially triggered by future events, were as follows:
Letters of credit
Surety bonds (a)
Guaranteed lease residual values (b)
Total commercial commitments
Expiration within
Total
2019
2020
2021
2022
2023
2024 and beyond
$
$
$
8 $
33 $
8
49 $
— $
33 $
1
34 $
8 $
— $
1
9 $
— $
— $
1
1 $
— $
— $
1
1 $
— $
— $
1
1 $
—
—
3
3
__________
(a) Surety bonds—Guarantees issued related to contract and commercial agreements, excluding bid bonds.
(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 maximum lease term associated with these assets ranges from 3 to 8 years. The maximum potential obligation at the end of the minimum lease term would be $19
million . The minimum lease term associated with these assets ranges from 1 to 4 years. Historically, payments under the guarantees have not been made and Pepco
believes the likelihood of payments being required under the guarantees is remote.
DPL commercial commitments as of December 31, 2018 , representing commitments potentially triggered by future events, were as follows:
Expiration within
Surety bonds (a)
Guaranteed lease residual values (b)
Total commercial commitments
Total
2019
2020
2021
2022
2023
2024 and beyond
$
$
5 $
10
15 $
5 $
1
6 $
— $
1
1 $
— $
1
1 $
— $
1
1 $
— $
1
1 $
—
5
5
__________
(a) Surety bonds—Guarantees issued related to contract and commercial agreements, excluding bid bonds.
(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 maximum lease term associated with these assets ranges from 3 to 8 years. The maximum potential obligation at the end of the minimum lease term would be $26
million . The minimum lease term associated with these assets ranges from 1 to 4 years. Historically, payments under the guarantees have not been made and DPL
believes the likelihood of payments being required under the guarantees is remote.
ACE commercial commitments as of December 31, 2018 , representing commitments potentially triggered by future events, were as follows:
Surety bonds (a)
Guaranteed lease residual values (b)
Total commercial commitments
Total
2019
2020
2021
2022
2023
2024 and beyond
$
$
3 $
6
9 $
3 $
1
4 $
— $
1
1 $
— $
—
— $
— $
1
1 $
— $
1
1 $
—
2
2
__________
(a) Surety bonds—Guarantees issued related to contract and commercial agreements, excluding bid bonds.
(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 maximum lease term associated with these assets ranges from 3 to 8 years. The maximum potential obligation at the end of the minimum lease term would be $16
million . The minimum lease term associated with these assets ranges from 1 to 4 years. Historically, payments under the guarantees have not been made and ACE
believes the likelihood of payments being required under the guarantees is remote.
Expiration within
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Table of Contents
Leases (All Registrants)
Combined Notes to Consolidated Financial Statements - (Continued)
(Dollars in millions, except per share data unless otherwise noted)
Minimum future operating lease payments, including lease payments for contracted generation, vehicles, real estate, computers, rail cars, operating equipment
and office equipment, as of December 31, 2018 were:
2019
2020
2021
2022
2023
Remaining
years
Total minimum
future lease
payments
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)
$
140 $
33 $
7 $
5 $
35 $
48 $
11 $
14 $
149
143
126
97
723
46
46
47
46
5
4
4
3
5
5
5
5
545
—
—
35
33
18
3
19
46
43
42
39
10
9
8
8
159
40
13
12
12
10
35
7
6
5
5
4
5
$
1,378 $
763 $
23 $
25 $
143 $
377 $
86 $
96 $
32
Includes amounts related to shared use land arrangements.
__________
(a)
(b) Excludes Generation’s contingent operating lease payments associated with contracted generation agreements.
(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
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.
The following table presents the Registrants’ rental expense under operating leases for the years ended December 31, 2018, 2017 and 2016:
For the Year Ended December 31,
2018
$
2017
2016
Exelon
Generation (a)
ComEd
PECO
BGE
Pepco
DPL
ACE
670 $
709
777
558 $
578
667
7 $
10 $
35 $
10 $
13 $
9
15
9
7
32
22
11
8
16
15
8
14
13
For the Year Ended
December 31, 2018
For the Year Ended
December 31, 2017
March 24, 2016 to
December 31, 2016
Successor
Predecessor
January 1, 2016 to
March 23, 2016
PHI
Rental expense under
operating leases
$
48 $
63 $
49 $
12
__________
(a)
Includes contingent operating lease payments associated with contracted generation agreements that are not included in the minimum future operating lease payments
table above. Payments made under Generation’s contracted generation lease agreements totaled $493 million , $508 million and $604 million during 2018 , 2017 and
2016 , respectively. Excludes contract amortization associated with purchase accounting and contract acquisitions.
For information regarding capital lease obligations, see Note 13 —Debt and Credit Agreements.
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Table of Contents
Combined Notes to Consolidated Financial Statements - (Continued)
(Dollars in millions, except per share data unless otherwise noted)
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, 2018 , the current liability limit per
incident is $14.1 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 $13.6 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 $3.1 billion , however any amounts payable under this secondary layer would be capped at $454
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 $14.1 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 2 — 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 $58 million for 2018 , and was $60 million and $21 million for 2017 and 2016 , 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 $345 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.
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
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Table of Contents
Combined Notes to Consolidated Financial Statements - (Continued)
(Dollars in millions, except per share data unless otherwise noted)
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. On November 19, 2013, the D.C. Circuit Court ordered the DOE to submit to Congress a proposal to reduce the current
SNF disposal fee to zero, unless and until there is a viable disposal program. On May 9, 2014, the DOE notified Generation that the SNF disposal fee remained
in effect through May 15, 2014, after which time the fee was set to zero. As a result, for the years ended December 31, 2018 , 2017 and 2016 , Generation did
not incur any expense in SNF disposal fees. 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. 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 has been, and is expected to be, delayed significantly.
The 2010 Federal budget (which became effective October 1, 2009) eliminated almost all funding for the creation of the Yucca Mountain repository while the
Obama Administration devised a new strategy for long-term SNF management. The Blue Ribbon Commission (BRC) on America’s Nuclear Future, appointed by
the U.S. Energy Secretary, released a report on January 26, 2012, detailing comprehensive recommendations for creating a safe, long-term solution for
managing and disposing of the nation’s SNF and high-level radioactive waste.
In early 2013, the DOE issued an updated “Strategy for the Management and Disposal of Used Nuclear Fuel and High-Level Radioactive Waste” in response to
the BRC recommendations. This strategy included a consolidated interim storage facility that was planned to be operational in 2025. However, due to continued
delays on the part of the DOE, 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.
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 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 (b)
Total
Net (a)
$
1,274 $
1,100
__________
(a) Total after considering amounts due to co-owners of certain nuclear stations and to the former owner of Oyster Creek.
(b)
Includes $53 and $49 , respectively, for amounts received since April 1, 2014, for costs incurred under the CENG DOE Settlement Agreements prior to the consolidation
of CENG.
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Table of Contents
Combined Notes to Consolidated Financial Statements - (Continued)
(Dollars in millions, except per share data unless otherwise noted)
As of December 31, 2018 and 2017 , 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, 2018
December 31, 2017
$
124 $
15
94
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
(11)
(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 fee
related to the former PECO units has been paid. Pursuant to the Standard Contracts, 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. A prior owner of
FitzPatrick also 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 for the contractual right to reimbursement from NYPA, a prior owner of FitzPatrick, for amounts paid for the FitzPatrick DOE one-time fee obligation. The
amounts were recorded at fair value. See Note 4 - Mergers, Acquisitions and Dispositions for additional information on the FitzPatrick acquisition. As of
December 31, 2018 and 2017 , the SNF liability for the one-time fee with interest was $1,171 million and $1,147 million , respectively, which is included in
Exelon's and Generation's Consolidated Balance Sheets. 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, 2018 was 2.351% for the deferred amount transferred from ComEd and
2.217% for the deferred FitzPatrick amount. The outstanding one-time fee obligations for the Nine Mile Point, Ginna, Oyster Creek and TMI units remain with the
former owners. The Clinton and Calvert Cliffs units have no outstanding obligation. See Note 11 — Fair Value of Financial Assets and Liabilities for additional
information.
Environmental Remediation Matters
General (All Registrants). The Registrants’ operations have in the past, and may in the future, require substantial expenditures to comply with environmental
laws. Additionally, under Federal and state environmental laws, the Registrants are generally liable for the costs of remediating environmental contamination of
property now or formerly owned by them and of property contaminated by hazardous substances generated by them. The Registrants own or lease a number of
real estate parcels, including parcels on which their operations or the operations of others may have resulted in contamination by substances that are considered
hazardous under environmental laws. In addition, the Registrants are currently involved in a number of proceedings relating to sites where hazardous
substances have been deposited and may be subject to additional proceedings in the future. Unless otherwise disclosed, the Registrants cannot reasonably
estimate whether they will incur significant liabilities for additional investigation and remediation costs at these or additional sites identified by the Registrants,
environmental agencies or others, or whether such costs will be recoverable from third parties, including customers. Additional costs could have a material,
unfavorable impact on the Registrants' financial statements.
MGP Sites (Exelon and the Utility Registrants). ComEd, PECO, BGE and DPL have identified sites where former MGP or gas purification activities have or
may have resulted in actual site contamination. For almost all of these sites, there are additional PRPs that may share responsibility for the ultimate remediation
of each location.
•
ComEd has identified 42 sites, 21 of which have been remediated and approved by the Illinois EPA or the U.S. EPA and 21 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 2023.
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Table of Contents
Combined Notes to Consolidated Financial Statements - (Continued)
(Dollars in millions, except per share data unless otherwise noted)
•
•
•
PECO has identified 26 sites, 17 of which have been remediated in accordance with applicable PA DEP regulatory requirements and 9 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 identified 13 sites, 9 of which have been remediated and approved by the MDE and 4 that require some level of remediation and/or ongoing
activity. BGE expects the majority of the remediation at these sites to continue through at least 2019.
DPL has identified 3 sites, 2 of which remediation has been completed and approved by the MDE or the Delaware Department of Natural Resources
and Environmental Control. The remaining site is under study and the required cost at the site is not expected to be material.
The historical nature of the MGP sites and the fact that many of the sites have been buried and built over, impacts the ability to determine 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. See Note 4 — Regulatory Matters for additional information regarding the
associated regulatory assets. 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.
During the third quarter of 2018, the Utility Registrants completed a study of their future estimated environmental remediation requirements. The study resulted
in a $48 million increase to the environmental liability and related regulatory asset for ComEd. The increase was primarily due to a revised closure strategy at
one site, which resulted in an increase in the excavation area and depth of impacted soils from the site. The study did not result in a material change to the
environmental liability for PECO, BGE, Pepco, DPL, and ACE.
As of December 31, 2018 and 2017 , 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:
Exelon
Generation
ComEd
PECO
BGE
PHI
Pepco
DPL
ACE
December 31, 2018
$
Total environmental
investigation
and remediation reserve
Portion of total related to MGP
investigation and remediation
496 $
108
329
27
5
27
25
1
1
431
356
—
327
25
4
—
—
—
—
Table of Contents
Exelon
Generation
ComEd
PECO
BGE
PHI
Pepco
DPL
ACE
Combined Notes to Consolidated Financial Statements - (Continued)
(Dollars in millions, except per share data unless otherwise noted)
December 31, 2017
$
Total environmental
investigation
and remediation reserve
Portion of total related to MGP
investigation and remediation
466 $
117
285
30
5
29
27
1
1
315
—
283
28
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. On May 29, 2008, the EPA issued a Record of Decision (ROD) approving a
landfill cover remediation approach. By letter dated January 11, 2010, the EPA requested that the PRPs perform a supplemental feasibility study for a
remediation alternative that would involve complete excavation of the radiological contamination. On September 30, 2011, the PRPs submitted the supplemental
feasibility study to the EPA for review. Since June 2012, the EPA has requested that the PRPs perform a series of additional analyses and groundwater and soil
sampling as part of the supplemental feasibility study. This further analysis was focused on a partial excavation remedial option. The PRPs provided the draft
final Remedial Investigation and Feasibility Study (RI/FS) to the EPA in January 2018, which formed the basis for EPA’s proposed remedy selection, as further
discussed below. There are currently 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.
On September 27, 2018 the EPA issued its ROD Amendment for the selection of the final remedy for the West Lake Landfill Superfund site. The ROD modifies
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 estimates that the ROD will result in a reduction of both radiological and
non-radiological waste excavated, with corresponding reductions in the cost and schedule for the remedy. The next step is the negotiation of a Consent
Agreement by the EPA with the PRPs to implement the ROD, a process that is expected to be completed in the first quarter of 2020. The estimated cost of the
remedy, taking into account the current EPA technical requirements and the total costs expected to be incurred 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 for the entire remediation effort. 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.
On January 16, 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 RI/FS and reimbursement of EPA’s oversight costs. The purposes of this new RI/FS are to define the nature and extent of any groundwater
contamination from the West Lake Landfill site, determine the potential risk posed to human health and the environment, and evaluate remedial alternatives.
Generation estimates the undiscounted cost for the groundwater RI/FS for West Lake 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
432
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Combined Notes to Consolidated Financial Statements - (Continued)
(Dollars in millions, except per share data unless otherwise noted)
or the extent to which, if any, remediation activities will be required and 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.
During December 2015, the EPA took two actions related to the West Lake Landfill designed to abate what it termed as imminent and dangerous conditions at
the landfill. The first involved installation by the PRPs of a non-combustible surface cover to protect against surface fires in areas where radiological materials
are believed to have been disposed which was completed in 2018. The second action involved EPA's public statement that it will require the PRPs to construct a
barrier wall in an adjacent landfill to prevent a subsurface fire from spreading to those areas of the West Lake Landfill where radiological materials are believed
to have been disposed. At this time, Generation believes that the requirement to build a barrier wall is remote in light of other technologies that have been
employed by the adjacent landfill owner. Finally, one of the other PRPs, the landfill owner and operator of the adjacent landfill, has indicated that 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.
On August 8, 2011, Cotter was notified by the DOJ that Cotter is considered a PRP with respect to the government’s clean-up costs 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. The DOJ and the PRPs agreed to toll the statute of limitations until August 2019 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.
Commencing in February 2012, a number of lawsuits have been filed in the U.S. District Court for the Eastern District of Missouri. Among the defendants were
Exelon, Generation and ComEd, all of which were subsequently dismissed from the case, as well as Cotter, which remains a defendant. The suits allege that
individuals living in the North St. Louis area developed some form of cancer or other serious illness due to Cotter's negligent or reckless conduct in processing,
transporting, storing, handling and/or disposing of radioactive materials. Plaintiffs are asserting public liability claims under the Price-Anderson Act. Their state
law claims for negligence, strict liability, emotional distress, and medical monitoring have been dismissed. In the event of a finding of liability against Cotter, it is
probable that Generation would be financially responsible due to its indemnification responsibilities of Cotter described above. The court has dismissed a
number of the lawsuits as untimely, which has been upheld on appeal. Cotter and the remaining plaintiffs have engaged in settlement discussions pursuant to
court-ordered mediation. During the second quarter of 2018, Generation determined a loss was probable based on the advancement of settlement proceedings
and recorded an immaterial liability.
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. That generating facility was deactivated in June 2012 and plant structure demolition was completed in July 2015. The remaining
portion of the site consists of a Pepco transmission and distribution service center that remains in operation. In December 2011, the U.S. District Court for the
District of Columbia approved a Consent Decree entered into by Pepco and Pepco Energy Services with the DOEE, which requires Pepco and Pepco Energy
Services to conduct a Remediation Investigation (RI)/ Feasibility Study (FS) for the Benning Road site and an approximately 10 to 15-acre portion of the
adjacent Anacostia River. The RI/FS will form the basis for the remedial actions for the Benning Road site and for the Anacostia River sediment associated with
the site. The Consent Decree does not obligate Pepco or Pepco Energy Services to pay for or perform any remediation work, but it is anticipated that DOEE will
look to Pepco and Pepco Energy Services to assume responsibility for cleanup of any conditions in the river
433
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Combined Notes to Consolidated Financial Statements - (Continued)
(Dollars in millions, except per share data unless otherwise noted)
that are determined to be attributable to past activities at the Benning Road site. Pursuant to Exelon's March 23, 2016 acquisition of PHI, Pepco Energy Services
was transferred to Generation.
Since 2013, Pepco and Pepco Energy Services (now Generation) have been performing RI work and have submitted multiple draft RI reports to the DOEE.
Once the RI work is completed, Pepco and Generation will issue a draft “final” RI report for review and comment by DOEE and the public. Pepco and Generation
will then proceed to develop an FS to evaluate possible remedial alternatives for submission to DOEE. The Court has established a schedule for completion of
the RI and FS, and approval by the DOEE, by May 6, 2019.
Upon DOEE’s approval of the final RI and FS Reports, Pepco and Generation will have satisfied their obligations under the Consent Decree. At that point, DOEE
will prepare a Proposed Plan regarding further response actions. After considering public comment on the Proposed Plan, DOEE will issue a Record of Decision
identifying any further response actions determined to be necessary. PHI, Pepco and Generation have determined that a loss associated with this matter is
probable and have accrued an estimated liability, which is included in the table above.
Anacostia River Tidal Reach (Exelon, PHI and Pepco). Contemporaneous with the Benning RI/FS being performed by Pepco and Generation, DOEE and
certain federal agencies have been conducting a separate RI/FS focused on the entire tidal reach of the Anacostia River extending from just north of the
Maryland-D.C. boundary line to the confluence of the Anacostia and Potomac Rivers. In March 2016, DOEE released a draft of the river-wide RI Report for
public review and comment. 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 addressing the entire tidal reach of the river 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 RI/FS. Pepco
responded that it will participate in the Consultative Working Group, but its participation is not an acceptance of any financial responsibility beyond the work that
will be performed at the Benning Road site described above. In April 2018, DOEE released a draft remedial investigation report for public review and comment.
Pepco submitted written comments to the draft RI and participated in a public hearing. Pepco continues outreach efforts as appropriate to the agencies,
governmental officials, community organizations and other key stakeholders. In May 2018 the District of Columbia Council extended the deadline for completion
of the Record of Decision from June 30, 2018 until December 31, 2019. An appropriate liability for Pepco’s share of investigation costs has been accrued and is
included in the table above. Although Pepco has determined that it is probable that costs for remediation will be incurred, Pepco cannot estimate the reasonably
possible range of loss at this time and no liability has been accrued for those future costs. A draft Feasibility Study of potential remedies and their estimated
costs is being prepared by the agencies and is expected to be released in 2019, at which time Pepco will likely be in a better position to estimate the range of
loss.
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 Trustees responsible for those resources to restore them to their condition before injury from the environmental contaminants. If natural
resources are not restored, then compensation for the injury can be sought from the party responsible for the release of the contaminants. 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 it cannot reasonably estimate the range of loss.
Litigation and Regulatory Matters
Asbestos Personal Injury Claims (Exelon, Generation, ComEd and PECO). Generation maintains estimated liabilities 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.
434
Table of Contents
Combined Notes to Consolidated Financial Statements - (Continued)
(Dollars in millions, except per share data unless otherwise noted)
At December 31, 2018 and 2017 , Generation had recorded estimated liabilities of approximately $79 million and $78 million , respectively, in total for asbestos-
related bodily injury claims. As of December 31, 2018 , approximately $24 million of this amount related to 238 open claims presented to Generation, while the
remaining $55 million is for estimated future asbestos-related bodily injury claims anticipated to arise through 2050, 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.
There is a reasonable possibility that Exelon may have additional exposure to estimated future asbestos-related bodily injury claims in excess of the amount
accrued and the increases 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 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.
Conduit Lease with City of Baltimore (Exelon and BGE). On September 23, 2015, the Baltimore City Board of Estimates approved an increase in annual
rental fees for access to the Baltimore City underground conduit system
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Table of Contents
Combined Notes to Consolidated Financial Statements - (Continued)
(Dollars in millions, except per share data unless otherwise noted)
effective November 1, 2015, from $12 million to $42 million , subject to an annual increase thereafter based on the Consumer Price Index. BGE subsequently
entered into litigation with the City regarding the amount of and basis for establishing the conduit fee. On November 30, 2016, the Baltimore City Board of
Estimates approved a settlement agreement entered into between BGE and the City to resolve the disputes and pending litigation related to BGE's use of and
payment for the underground conduit system. As a result of the settlement, the parties entered into a six-year lease that reduces the annual expense to $25
million in the first three years and caps the annual expense in the last three years to not more than $29 million . BGE recorded a decrease to Operating and
maintenance expense in the fourth quarter of 2016 of approximately $28 million for the reversal of the previously higher fees accrued as well as the settlement of
prior year disputed fee true-up amounts.
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 8 & 9 on the grounds that the
total investment in Mystic 8 & 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. Generation vigorously contested the City’s claims before the EACC and will continue to do so in the Massachusetts
Superior Court proceeding. 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 2019, could be
material to Generation’s 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 a reasonable possibility, 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.
23. Supplemental Financial Information (All Registrants)
Supplemental Statement of Operations Information
The following tables provide additional information about the Registrants’ Consolidated Statements of Operations and Comprehensive Income for the years
ended December 31, 2018 , 2017 and 2016 .
For the year ended December 31, 2018
Successor
Exelon
Generation
ComEd
PECO
BGE
PHI
Pepco
DPL
ACE
$
919
$
114
$
243
$
131
$
94
$
337
$
316
$
21
$ —
557
247
60
273
130
39
30
27
11
15
16
1
143
17
—
94
24
—
58
32
5
—
3
—
3
2
—
Taxes other than income
Utility (a)
Property
Payroll
Other
Total taxes other than income
$
1,783
$
556
$
311
$
163
$
254
$
455
$
379
$
56
$
5
436
Table of Contents
Taxes other than income
Utility (a)
Property
Payroll
Other
Total taxes other than income
Taxes other than income
Utility (a)
Property
Payroll
$
Combined Notes to Consolidated Financial Statements - (Continued)
(Dollars in millions, except per share data unless otherwise noted)
For the year ended December 31, 2017
Successor
Exelon
Generation
ComEd
PECO
BGE
PHI
Pepco
DPL
ACE
$
$
898 $
545
230
58
1,731 $
126 $
269
121
39
555 $
240 $
28
26
2
296 $
125 $
14
15
—
154 $
89 $
132
15
4
240
$
318 $
101
26
7
452 $
300 $
62
6
3
18 $ —
32
4
3
1
2
3
371
$
57
$
6
For the year ended December 31, 2016
Successor
Predecessor
March 24, 2016 to
December 31, 2016
January 1, 2016 to
March 23, 2016
Exelon
Generation
ComEd
PECO
BGE
Pepco
DPL
ACE
PHI
PHI
753 $
483
226
114
122 $
246
117
21
242 $
27
28
(4)
136 $
13
15
—
85 $
123
17
4
312 $
53
8
4
18 $ — $
31
5
1
3
3
1
253 $
73
23
5
78
18
8
Other
Total taxes other than
income
__________
(a) Generation’s utility tax represents gross receipts tax related to its retail operations and ComEd’s, PECO’s, BGE’s, Pepco's, DPL's and ACE's utility taxes represent
municipal and state utility taxes and gross receipts taxes related to their operating revenues. The offsetting collection of utility taxes from customers is recorded in
revenues in the Registrants’ Consolidated Statements of Operations and Comprehensive Income.
1,576 $
354 $
293 $
164 $
506 $
105
377
229
55
$
$
$
$
$
7
1
437
Table of Contents
Combined Notes to Consolidated Financial Statements - (Continued)
(Dollars in millions, except per share data unless otherwise noted)
Exelon
Generation
ComEd
PECO
BGE
PHI
Pepco
DPL
ACE
For the year ended December 31, 2018
Successor
Other, Net
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
Net unrealized losses on pledged assets
Zion Station decommissioning
Regulatory offset to NDT fund-related
activities (b)
Total decommissioning-related activities
Investment income
Interest income related to uncertain income tax
positions
AFUDC—Equity
Non-service net periodic benefit cost
Other
Other, net
506 $
302
506 $
302
— $
—
— $ — $
—
—
— $
—
— $ — $ —
—
—
—
(715)
(483)
(8)
171
(227)
43
5
69
(47)
45
(715)
(483)
(8)
171
(227)
32
1
—
—
16
—
—
—
—
—
—
—
19
—
14
—
—
—
—
—
1
—
7
—
—
$
(112)
$
(178)
$
33
$
8
$
438
—
—
—
—
—
1
—
18
—
—
19 $
—
—
—
—
—
4
—
25
—
14
—
—
—
—
—
2
—
22
—
7
—
—
—
—
—
1
—
2
—
7
43
$
31
$
10
$
—
—
—
—
—
—
—
1
—
1
2
Table of Contents
Combined Notes to Consolidated Financial Statements - (Continued)
(Dollars in millions, except per share data unless otherwise noted)
Exelon
Generation
ComEd
PECO
BGE
PHI
Pepco
DPL
ACE
For the year ended December 31, 2017
Successor
Other, Net
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
Net unrealized losses on pledged assets
Zion Station decommissioning
Regulatory offset to NDT fund-related
activities (b)
Total decommissioning-related activities
Investment income
Interest income (expense) related to uncertain
income tax positions
Benefit related to uncertain income tax positions
(c)
AFUDC—Equity
Non-service net periodic benefit cost
Other
Other, net
488 $
209
488 $
209
— $
—
— $ — $
—
—
— $
—
— $ — $ —
—
—
—
455
521
(10)
(724)
939
8
3
2
73
(109)
31
455
521
(10)
(724)
939
6
(1)
—
—
—
4
—
—
—
—
—
—
—
—
12
—
10
—
—
—
—
—
—
—
—
9
—
—
—
—
—
—
—
—
—
—
16
—
—
$
947
$
948
$
22
$
9
$
16
$
439
—
—
—
—
—
2
—
—
36
—
16
54 $
—
—
—
—
—
1
—
—
23
—
8
—
—
—
—
—
—
—
—
7
—
7
32
$
14
$
—
—
—
—
—
—
—
—
6
—
1
7
Table of Contents
Other, Net
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
Net unrealized losses on
pledged assets
Zion Station
decommissioning
Regulatory offset to NDT
fund-related activities (b)
Total decommissioning-related
activities
Investment income (loss)
Long-term lease income
Interest income (expense)
related to uncertain income tax
positions
Penalty related to uncertain
income tax positions (c)
AFUDC—Equity
Non-service net periodic
benefit cost
Loss on debt extinguishment
Other
Other, net
Combined Notes to Consolidated Financial Statements - (Continued)
(Dollars in millions, except per share data unless otherwise noted)
For the year ended December 31, 2016
Successor
Predecessor
March 24, 2016 to
December 31, 2016
January 1, 2016 to
March 23, 2016
Exelon
Generation
ComEd
PECO
BGE
Pepco
DPL
ACE
PHI
PHI
$
237 $
237 $
— $
— $ — $
— $ — $ — $
126
126
—
—
—
—
—
—
216
194
(1)
(372)
400
17
4
13
(106)
64
(116)
(3)
24
216
194
(1)
(372)
400
8
—
—
—
—
—
(2)
(5)
—
—
—
—
—
—
—
—
(86)
14
—
—
7
—
—
—
—
—
(1)
—
—
—
8
—
—
1
—
—
—
—
—
2
—
—
—
19
—
—
—
—
—
—
—
—
1
—
1
—
19
—
—
15
—
—
—
—
—
—
—
—
—
5
—
—
8
$
297
$
401
$
(65)
$
8
$
21
$
36
$
13
$
440
—
—
—
—
—
1
—
—
—
6
—
—
2
9 $
— $
—
—
—
—
—
—
1
—
(1)
—
23
—
—
—
—
—
—
—
—
—
—
—
—
—
7
—
—
21
44
$
(11)
(4)
Table of Contents
Combined Notes to Consolidated Financial Statements - (Continued)
(Dollars in millions, except per share data unless otherwise noted)
__________
(a)
(b)
Includes investment income and realized gains and losses on sales of investments within the NDT funds.
Includes the elimination of decommissioning-related activities for the Regulatory Agreement Units, including the elimination of net income taxes related to all NDT fund
activity for these units. See Note 15 — Asset Retirement Obligations for additional information regarding the accounting for nuclear decommissioning.
(c) See Note 14 — Income Taxes for additional information on the penalty related to the Tax Court’s decision on Exelon’s like-kind exchange tax position.
Supplemental Cash Flow Information
The following tables provide additional information regarding the Registrants’ Consolidated Statements of Cash Flows for the years ended December 31, 2018 ,
2017 and 2016 .
For the year ended December 31, 2018
Successor
Exelon
Generation
ComEd
PECO
BGE
PHI
Pepco
DPL
ACE
Depreciation, amortization and accretion
Property, plant and equipment
$
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 $
3,740 $
555
58
14
1,115
489
5,971 $
1,748 $
—
49
14
1,115
489
3,415 $
820 $
120
—
—
—
—
940
$
274 $
27
—
—
—
—
301 $
335 $
148
—
—
—
—
483
$
480 $
260
—
—
—
—
740 $
218 $
167
—
131 $
51
—
—
—
—
—
—
—
94
42
—
—
—
—
385
$
182
$
136
For the year ended December 31, 2017
Successor
Exelon
Generation
ComEd
PECO
BGE
PHI
Pepco
DPL
ACE
Depreciation, amortization and accretion
Property, plant and equipment
$
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 $
3,293 $
478
57
35
1,096
468
1,409 $
—
48
35
1,096
468
777 $
73
—
261 $
25
—
312 $
161
—
—
—
—
—
—
—
—
—
—
5,427
$
3,056
$
850
$
286
$
473
$
457 $
218
—
—
—
—
675 $
203 $
118
—
124 $
43
—
—
—
—
—
—
—
89
57
—
—
—
—
321
$
167
$
146
441
Table of Contents
Combined Notes to Consolidated Financial Statements - (Continued)
(Dollars in millions, except per share data unless otherwise noted)
Depreciation, amortization and accretion
Exelon
Generation
ComEd
PECO
BGE
Pepco
DPL
ACE
PHI
PHI
For the year ended December 31, 2016
Successor
Predecessor
March 24, 2016 to
December 31, 2016
January 1, 2016 to
March 23, 2016
3,477 $
407
1,835 $
—
708 $
67
244 $
26
299 $
124
175 $
120
110 $
47
82 $
83
325 $
190
52
44
—
—
—
—
—
—
—
35
1,159
446
35
1,159
446
—
—
—
—
—
—
—
—
—
—
—
—
—
—
—
—
—
—
—
—
—
94
58
—
—
—
—
$
5,576 $
3,519
$
775
$
270
$
423
$
295
$
157
$
165 $
515 $
152
Included in Operating revenues or Purchased power and fuel 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.
442
Property, plant and
equipment
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
__________
(a)
(b)
(c)
Table of Contents
Combined Notes to Consolidated Financial Statements - (Continued)
(Dollars in millions, except per share data unless otherwise noted)
Cash paid (refunded) during the year:
Interest (net of amount capitalized)
Income taxes (net of refunds)
Other non-cash operating activities:
Pension and non-pension postretirement benefit
costs
Loss (gain) from equity method investments
Provision for uncollectible accounts
Provision for excess and obsolete inventory
Stock-based compensation costs
Other decommissioning-related activity (a)
Energy-related options (b)
Amortization of regulatory asset related to debt
costs
Amortization of rate stabilization deferral
Amortization of debt fair value adjustment
Merger-related commitments (c)
Severance costs
Asset retirement costs
Amortization of debt costs
Discrete impacts from EIMA and FEJA (d)
Long-term incentive plan
Other
Total other non-cash operating activities
Non-cash investing and financing activities:
Change in capital expenditures not paid
Change in PPE related to ARO update
Dividends on stock compensation
$
$
$
$
Acquisition of land
__________
(a)
For the year ended December 31, 2018
Successor
Exelon
Generation
ComEd
PECO
BGE
PHI
Pepco
DPL
ACE
1,421 $
95
369 $
746
332 $
(153)
125 $
(2)
94 $
14
250 $
(32)
123 $
41
56 $
(6)
61
(12)
583 $
28
159
24
75
(2)
10
8
14
(15)
—
35
20
36
28
140
(19)
204 $
30
48
20
—
(2)
10
—
—
(12)
—
9
—
14
—
—
(23)
177 $
—
40
3
—
—
—
18 $
—
33
—
—
—
—
59 $
—
10
—
—
—
—
3
—
—
—
—
—
5
28
—
(14)
1
—
—
—
—
—
2
—
—
(3)
—
—
—
—
—
—
1
—
—
(12)
1,124
$
298
$
242
$
51
$
58
$
(69) $
(107)
6
3
(199)
$
(130)
—
—
11 $
7
—
—
(12) $
—
—
—
50 $
1
—
—
67 $
(1)
28
—
—
—
—
4
14
(3)
5
—
20
3
—
—
6
143 $
93 $
15
—
3
15 $
—
11
—
—
—
—
2
14
—
—
—
22
2
—
—
(6)
60 $
20 $
12
—
—
6 $
—
6
—
—
—
—
1
—
—
5
—
(1)
—
—
—
7
24 $
22 $
2
—
—
12
—
11
—
—
—
—
1
—
—
—
—
(1)
1
—
—
—
24
46
1
—
3
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 15 — 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 5 - Mergers, Acquisitions and Dispositions for additional information.
(d) Reflects the change in ComEd's distribution and energy efficiency formula rates. See Note 4 — Regulatory Matters for additional information.
443
Table of Contents
Combined Notes to Consolidated Financial Statements - (Continued)
(Dollars in millions, except per share data unless otherwise noted)
$
$
Cash paid (refunded) during the year:
Interest (net of amount capitalized)
Income taxes (net of refunds)
Other non-cash operating activities:
Pension and non-pension postretirement
benefit costs
Loss (gain) from equity method investments
Provision for uncollectible accounts
Provision for excess and obsolete inventory
Stock-based compensation costs
Other decommissioning-related activity (a)
Energy-related options (b)
Amortization of regulatory asset related to
debt costs
Amortization of rate stabilization deferral
Amortization of debt fair value adjustment
Merger-related commitments (c)
Severance costs
Amortization of debt costs
Discrete impacts from EIMA and FEJA (d)
Vacation accrual adjustment (e)
Long-term incentive plan
Change in environmental liabilities
Other
Total other non-cash operating activities
Non-cash investing and financing
activities:
Change in capital expenditures not paid
Change in PPE related to ARO update
$
$
Non-cash financing of capital projects
Indemnification of like-kind exchange
position (f)
Dividends on stock compensation
Dissolution of financing trust due to long-
term debt retirement
For the year ended December 31, 2017
Successor
Exelon
Generation
ComEd
PECO
BGE
PHI
Pepco
DPL
ACE
2,430 $
540
391 $
337
307 $
83
103 $
47
96 $
(2)
236 $
(144)
114 $
(104)
49 $
(49)
59
(2)
643 $
32
125
56
88
(313)
7
9
(10)
(18)
—
35
64
(52)
(68)
109
44
(30)
227 $
33
38
51
—
(313)
7
—
—
(12)
—
31
37
—
(35)
—
44
4
176 $
—
34
3
—
—
—
29 $
—
26
—
—
—
—
4
—
—
—
—
5
(52)
(12)
—
—
6
1
—
—
—
—
2
—
—
—
—
(4)
721
$
112
$
164
$
54
$
62 $
—
8
—
—
—
—
—
7
—
—
—
2
—
—
—
—
(14)
65 $
42 $
29
16
—
7
8
73 $
29
16
—
—
—
(61) $
—
—
22 $
—
—
23 $
—
—
21
—
—
—
—
—
—
—
8
444
94 $
(1)
19
2
—
—
—
4
(17)
(6)
(8)
3
4
—
(8)
—
—
(28)
25 $
—
8
1
—
—
—
13 $
—
3
1
—
—
—
2
(17)
—
(6)
—
2
—
(8)
—
—
(13)
1
—
—
(2)
—
—
—
—
—
—
(7)
58
$
(6)
$
9
$
$
(12)
—
—
—
—
—
5 $
—
—
—
—
—
4 $
—
—
—
—
—
13
—
8
—
—
—
—
1
—
—
—
—
1
—
—
—
—
(6)
17
(13)
—
—
—
—
—
Table of Contents
Combined Notes to Consolidated Financial Statements - (Continued)
(Dollars in millions, except per share data unless otherwise noted)
Fair value adjustment of long-term debt due
to retirement
Fair value of pension and OPEB obligation
transferred in connection with FitzPatrick
__________
(a)
(5)
—
—
33
—
—
—
—
—
—
—
—
—
—
—
—
—
—
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 15 — 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 5 - Mergers, Acquisitions and Dispositions for additional information.
(d) Reflects the change in ComEd's distribution and energy efficiency formula rates . See Note 4 — 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 will now be accrued ratably over the year in 2018.
(f) See Note 14 — Income Taxes for additional information on the like-kind exchange tax position.
For the year ended December 31, 2016
Successor
Predecessor
March 24, 2016 to
December 31,
2016
January 1, 2016 to
March 23, 2016
Exelon
Generation
ComEd
PECO
BGE
Pepco
DPL
ACE
PHI
PHI
Cash paid (refunded) during
the year:
Interest (net of amount
capitalized)
Income taxes (net of refunds)
Other non-cash operating
activities:
Pension and non-pension
postretirement benefit costs
Loss from equity method
investments
Provision for uncollectible
accounts
Stock-based compensation
costs
Other decommissioning-related
activity (a)
Energy-related options (b)
Amortization of regulatory asset
related to debt costs
Amortization of rate stabilization
deferral
Amortization of debt fair value
adjustment
Merger-related commitments (c)
(d)
Severance costs
Discrete impacts from EIMA (e)
Amortization of debt costs
$
1,340 $
(441)
339 $
435
298 $
(444)
104 $
64
92 $
31
118 $
216
47 $
115
62 $
200
209 $
258
$
619 $
218 $
166 $
33 $
67 $
31 $
18 $
15 $
86 $
24
155
111
(384)
(11)
9
76
(11)
558
99
8
35
25
19
—
(384)
(11)
—
—
(11)
53
22
—
17
—
41
—
—
—
4
—
—
—
—
8
4
—
30
—
—
—
1
—
—
—
—
—
3
445
—
1
—
—
—
—
—
—
—
2
81
(12)
—
—
—
—
1
—
125
—
—
—
—
—
—
29
23
32
—
—
—
1
2
—
82
—
—
—
—
—
—
1
—
—
110
—
—
—
—
65
—
—
—
3
(5)
—
317
56
—
1
43
11
23
—
16
3
—
—
1
5
—
—
—
—
—
Table of Contents
Provision for excess and obsolete
inventory
Lower of cost or market inventory
adjustment
Baltimore City Conduit Lease
Settlement
Cash Working Capital Order
Asset retirement costs
Long-term incentive plan
Other
Total other non-cash operating
activities
Non-cash investing and
financing activities:
Change in capital expenditures
not paid
Change in PPE related to ARO
update
Indemnification of like-kind
exchange position (g)
Dividends on stock compensation
Non-cash financing of capital
projects
Sale of Upstream assets (c)
Pending FitzPatrick Acquisition (h)
Fair value of net assets
contributed to Generation in
connection with the PHI merger,
net of cash
Fair value of net assets
distributed to Exelon in
connection with the PHI Merger,
net of cash (c)(f)
Fair value of pension obligation
transferred in connection with the
PHI Merger, net of cash (c)(f)
Assumption of member purchase
liability
Assumption of merger
commitment liability
__________
(a)
Combined Notes to Consolidated Financial Statements - (Continued)
(Dollars in millions, except per share data unless otherwise noted)
12
37
(28)
(13)
2
70
(35)
6
36
—
—
—
—
25
4
—
—
—
—
—
(12)
—
1
—
—
—
—
(3)
—
—
(28)
(13)
—
—
(21)
3
—
—
—
—
—
(3)
1
—
—
—
1
—
(14)
1
—
—
—
2
—
(6)
1
—
—
—
2
—
(11)
$
1,333
$
15
$
215
$
65
$
88
$
175 $ 114 $ 155 $
515 $
$
(128)
$
50 $
(91) $
(11) $ (86) $
27 $ (12) $
11 $
21 $
191
—
6
95
37
(54)
191
—
—
95
37
(54)
—
158
—
—
—
—
—
—
—
—
—
—
—
—
—
—
—
—
—
—
—
—
—
—
—
—
—
—
—
—
—
—
—
—
—
—
—
—
—
—
—
—
—
119
—
—
—
—
—
—
—
—
—
—
—
—
—
—
—
—
—
—
—
—
—
127
—
—
—
—
—
—
—
—
—
—
—
33
—
—
—
—
—
—
53
29
33
1
—
—
—
—
—
(3)
46
11
—
—
—
—
—
—
—
—
—
—
—
Includes the elimination of NDT fund activity 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 15 — 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 5 - Mergers, Acquisitions and Dispositions for additional information.
(d) Excludes $5 million of forgiveness of Accounts receivable related to merger commitments recorded in connection with the PHI Merger, the balance is included within
Provision for uncollectible accounts.
(e) Reflects the change in distribution rates pursuant to EIMA, which allows for the recovery of costs by a utility through a pre-established performance-based formula rate.
See Note 4 — Regulatory Matters for additional information.
446
Table of Contents
Combined Notes to Consolidated Financial Statements - (Continued)
(Dollars in millions, except per share data unless otherwise noted)
(f)
Immediately following closing of the PHI Merger, the net assets associated with PHI’s unregulated business interests were distributed by PHI to Exelon. Exelon
contributed a portion of such net assets to Generation.
(g) See Note 14 — Income Taxes for additional information on the like-kind exchange tax position.
(h) Reflects the transfer of nuclear fuel to Entergy under the cost reimbursement provisions of the FitzPatrick acquisition agreements. See Note 5 - Mergers, Acquisitions and
Dispositions for additional information.
The following tables provide a reconciliation of cash, cash equivalents and restricted cash reported within the Registrants' Consolidated Balance Sheets that
sum to the total of the same amounts in their Consolidated Statements of Cash Flows.
December 31, 2018
Exelon
Generation
ComEd
PECO
BGE
PHI
Pepco
DPL
ACE
Cash and cash equivalents
Restricted cash
Restricted cash included in other long-term
assets
Total cash, cash equivalents and restricted
cash
$
1,349 $
247
750 $
153
135 $
29
130 $
5
7 $
6
124 $
43
16 $
37
23 $
1
185
—
166
—
—
19
—
—
$
1,781 $
903 $
330 $
135 $
13 $
186 $
53 $
24 $
7
4
19
30
Successor
December 31, 2017
Exelon
Generation
ComEd
PECO
BGE
PHI
Pepco
DPL
ACE
Successor
Cash and cash equivalents
$
Restricted cash
Restricted cash included in other long-term
assets
Total cash, cash equivalents and restricted
cash
898 $
207
85
416 $
138
76 $
5
271 $
4
17 $
1
30 $
42
5 $
35
2 $
—
—
63
—
—
23
—
—
$
1,190 $
554 $
144 $
275 $
18 $
95 $
40 $
2 $
December 31, 2016
Successor
Predecessor
December 31, 2016
March 23, 2016
Cash and cash
equivalents
Restricted cash
Restricted cash included
in other long-term
assets
Total cash, cash
equivalents and
restricted cash
Exelon
Generation
ComEd
PECO
BGE
Pepco
DPL
ACE
PHI
PHI
$
635 $
253
290 $
158
56 $
2
63 $
4
23 $
24
9 $
33
46 $
—
101 $
9
170 $
43
26
—
—
—
3
—
—
23
23
$
914 $
448 $
58 $
67 $
50 $
42 $
46 $
133 $
236 $
319
11
18
348
December 31, 2015
Exelon
Generation
ComEd
PECO
BGE
PHI
Pepco
DPL
ACE
Predecessor
Cash and cash equivalents
$
Restricted cash
Restricted cash included in other long-
term assets
Total cash, cash equivalents and
restricted cash
6,502 $
205
431 $
123
67 $
2
295 $
3
9 $
24
26 $
14
5 $
2
5 $
—
5
2
—
—
3
18
—
—
$
6,712 $
556 $
69 $
298 $
36 $
58 $
7 $
5 $
447
2
6
23
31
3
12
18
33
Table of Contents
Combined Notes to Consolidated Financial Statements - (Continued)
(Dollars in millions, except per share data unless otherwise noted)
Supplemental Balance Sheet Information
The following tables provide additional information about assets and liabilities of the Registrants at December 31, 2018 and 2017 .
December 31, 2018
Exelon
Generation
ComEd
PECO
BGE
PHI
Pepco
DPL
ACE
Unbilled customer revenues (a)
Allowance for uncollectible accounts (b)
$
1,656 $
(319)
965 $
(104)
223 $
(81)
114 $
(61)
168 $
(20)
186 $
(53)
97 $
(21)
59 $
(13)
30
(19)
December 31, 2017
Exelon
Generation
ComEd
PECO
BGE
PHI
Pepco
DPL
ACE
Unbilled customer revenues (a)
Allowance for uncollectible
accounts (b)
__________
(a) Represents unbilled portion of receivables estimated under Exelon’s unbilled critical accounting policy.
(b)
Includes the estimated allowance for uncollectible accounts on billed customer and other accounts receivable.
(73)
(56)
(114)
(322)
$
242 $
162 $
1,858 $
1,017 $
205 $
232 $
133 $
68 $
31
(24)
(55)
(21)
(16)
(18)
The Utility Registrants are required, under separate legislation and regulations in Illinois, Pennsylvania, Maryland, District of Columbia and New Jersey, to
purchase certain receivables from alternative retail electric and, as applicable, natural gas suppliers that participate in the utilities' consolidated billing. ComEd,
BGE, Pepco and DPL purchase receivables at a discount to recover primarily uncollectible accounts expense from the suppliers. PECO and ACE purchase
receivables at face value and recover uncollectible accounts expense, including those from alternative retail electric and natural gas supplies, through base
distribution rates and a rate rider, respectively. Exelon and the Utility Registrants do not record unbilled commodity receivables under their POR programs.
Purchased billed receivables are recorded on a net basis in Exelon’s and the Utility Registrant's Consolidated Statements of Operations and Comprehensive
Income and are classified in Other accounts receivable, net in their Consolidated Balance Sheets. The following tables provide information about the purchased
receivables of those companies as of December 31, 2018 and 2017 .
December 31, 2018
Exelon
ComEd
PECO
BGE
PHI
Pepco
DPL
ACE
Purchased receivables
Allowance for uncollectible accounts (a)
Purchased receivables, net
Purchased receivables
Allowance for uncollectible accounts (a)
December 31, 2017
$
$
$
313 $
(34)
279 $
94 $
(17)
77 $
74 $
(5)
69 $
61 $
(3)
58 $
84 $
(9)
75 $
57 $
(5)
52 $
8 $
(1)
7 $
19
(3)
16
Exelon
ComEd
PECO
BGE
PHI
Pepco
DPL
ACE
298 $
(31)
267 $
87 $
(14)
73 $
70 $
(5)
65 $
58 $
(3)
55 $
83 $
(9)
74 $
56 $
(5)
51 $
9 $
(1)
8 $
18
(3)
15
Purchased receivables, net
__________
(a) For ComEd, BGE, Pepco and DPL, reflects the incremental allowance for uncollectible accounts recorded, which is in addition to the purchase discount. For ComEd, the
incremental uncollectible accounts expense is recovered through a rate rider. BGE, Pepco and DPL recover actual write-offs which are reflected in the POR discount rate.
$
448
Table of Contents
Combined Notes to Consolidated Financial Statements - (Continued)
(Dollars in millions, except per share data unless otherwise noted)
The following tables provide additional information about Registrants' investments at December 31, 2018 and 2017 .
December 31, 2018
Exelon
Generation
ComEd
PECO
BGE
PHI
Pepco
DPL
ACE
Investments
Equity method investments:
Financing trusts (a)
$
Bloom
NET Power
Other equity method investments
Total equity method investments
Other investments:
Employee benefit trusts and
investments (b)
Equity investments without readily
determinable fair values
Other available for sale debt security
investments
Other
Total investments
14 $
180
70
3
267
244
72
40
2
— $
180
70
1
251
49
72
40
2
$
625
$
414
$
6 $
—
—
—
6
—
—
—
—
6
$
8 $
—
—
—
8
17
—
—
—
25
$
— $
—
—
—
—
— $
—
—
—
—
— $
—
—
—
—
5
—
—
—
5
130
105
—
—
—
—
—
—
$
130
$
105
$
— $
—
—
—
—
—
—
—
—
— $
December 31, 2017
Exelon
Generation
ComEd
PECO
BGE
PHI
Pepco
DPL
ACE
Investments
Equity method investments:
Financing trusts (a)
$
Bloom
NET Power
Other equity method investments
Total equity method investments
Other investments:
Employee benefit trusts and
investments (b)
Equity investments without readily
determinable fair values
Other available for sale debt security
investments
14 $
206
76
1
297
244
62
37
640
$
$
Total investments
__________
(a)
— $
206
76
1
283
51
62
37
433
$
6 $
—
—
—
6
—
—
—
6
$
8 $
—
—
—
8
17
—
—
25
$
— $
—
—
—
—
— $
—
—
—
—
— $
—
—
—
—
5
—
—
5
132
102
—
—
—
—
$
132
$
102
$
— $
—
—
—
—
—
—
—
— $
Includes investments in affiliated financing trusts, which were not consolidated within the financial statements of Exelon and are shown as investments in the Consolidated
Balance Sheets. See Note 1 — Significant Accounting Policies for additional information.
(b) The Registrants’ debt and equity security investments are recorded at fair market value.
449
—
—
—
—
—
—
—
—
—
—
—
—
—
—
—
—
—
—
—
Table of Contents
Combined Notes to Consolidated Financial Statements - (Continued)
(Dollars in millions, except per share data unless otherwise noted)
The following tables provide additional information about liabilities of the Registrants at December 31, 2018 and 2017 .
December 31, 2018
Exelon
Generation
ComEd
PECO
BGE
PHI
Pepco
DPL
ACE
Accrued expenses
Compensation-related
accruals (a)
Taxes accrued
Interest accrued
Severance accrued
Other accrued expenses
Total accrued expenses
$
$
1,191 $
412
334
44
131
2,112 $
479 $
226
77
26
90
898 $
187 $
71
105
2
8
373 $
49 $
28
33
—
3
113 $
68 $
46
39
—
2
99 $
74
50
5
28
29 $
58
25
—
14
155
$
256
$
126
$
19 $
4
8
—
8
39
$
12
5
12
—
6
35
December 31, 2017
Exelon
Generation
ComEd
PECO
BGE
PHI
Pepco
DPL
ACE
Accrued expenses
Compensation-related
accruals (a)
Taxes accrued
Interest accrued
Severance accrued
Other accrued expenses
Total accrued expenses
$
$
978 $
373
328
58
100
1,837 $
407 $
444
78
30
63
1,022 $
158 $
60
102
2
5
327 $
64 $
15
33
—
2
114 $
58 $
71
34
—
1
106 $
61
48
17
29
29 $
68
23
—
17
164
$
261
$
137
$
17 $
4
8
—
6
35
$
11
5
12
—
5
33
__________
(a) Primarily includes accrued payroll, bonuses and other incentives, vacation and benefits.
24. Segment Information (All Registrants)
Operating segments for each of the Registrants are determined based on information used by the chief operating decision maker(s) (CODM) in deciding how to
evaluate performance and allocate resources at each of the Registrants.
Exelon has twelve reportable segments, which include Generation's six reportable segments consisting of the Mid-Atlantic, Midwest, New England, New York,
ERCOT and all other power regions referred to collectively as “Other Power Regions” and ComEd, PECO, BGE, 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 six reportable segments are as follows:
• Mid-Atlantic represents operations in the eastern half of PJM, which includes New Jersey, Maryland, Virginia, West Virginia, Delaware, the District of
Columbia and parts of Pennsylvania and North Carolina.
• Midwest represents operations in the western half of PJM and the United States footprint of MISO, excluding MISO’s Southern Region.
450
Table of Contents
Combined Notes to Consolidated Financial Statements - (Continued)
(Dollars in millions, except per share data unless otherwise noted)
•
•
•
•
New England represents operations within ISO-NE.
New York represents operations within ISO-NY.
ERCOT represents operations within Electric Reliability Council of Texas.
Other Power Regions :
•
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 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 is changing 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. As a result,
beginning in the first quarter of 2019, Generation will disclose five reportable segments consisting of Mid-Atlantic, Midwest, New York, ERCOT and Other Power
Regions. Beginning in the first quarter of 2019, Other Power Regions will include:
•
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.
New England represents operations within ISO-NE.
451
Table of Contents
Combined Notes to Consolidated Financial Statements - (Continued)
(Dollars in millions, except per share data unless otherwise noted)
An analysis and reconciliation of the Registrants’ reportable segment information to the respective information in the consolidated financial statements for the
years ended December 31, 2018 , 2017 , and 2016 is as follows:
Generation (a)
ComEd
PECO
BGE
PHI (e)
Other (b)
Intersegment
Eliminations
Exelon
Successor
Operating revenues (c) :
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
$
$
17,411 $
— $
— $
— $
— $
— $
(1,256) $
16,155
2,718
308
—
—
—
—
—
—
—
—
5,882
2,470
2,428
—
568
741
—
—
4,609
181
—
—
—
—
(8)
(5)
(45)
(20)
—
20,437 $
—
5,882 $
—
3,038 $
—
3,169 $
15
4,805 $
1,948
1,948 $
(1,960)
(3,294) $
2,710
303
15,344
1,470
3
35,985
15,332 $
— $
— $
— $
— $
— $
(1,105) $
14,227
2,575
593
—
—
—
—
—
—
—
—
5,536
2,375
2,489
—
495
687
—
—
4,469
161
—
—
—
—
—
(1)
(29)
(10)
—
18,500 $
—
5,536 $
—
2,870 $
—
3,176 $
49
4,679 $
1,831
1,831 $
(1,880)
(3,025) $
2,575
592
14,840
1,333
—
33,567
452
Table of Contents
2016
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) :
2018
2017
2016
Depreciation and
amortization:
2018
2017
2016
Operating expenses (c) :
2018
2017
2016
Interest expense, net:
2018
2017
2016
Income (loss) before income
taxes:
2018
2017
2016
Income taxes:
2018
2017
2016
$
$
$
$
$
$
Combined Notes to Consolidated Financial Statements - (Continued)
(Dollars in millions, except per share data unless otherwise noted)
Generation (a)
ComEd
PECO
BGE
PHI (e)
Other (b)
Intersegment
Eliminations
Exelon
Successor
$
15,400 $
— $
— $
— $
— $
— $
(1,430) $
13,970
2,146
211
—
—
—
—
—
—
—
—
—
—
5,254
2,531
2,609
3,506
—
463
624
92
—
—
—
—
—
(4)
(31)
(13)
—
17,757 $
—
5,254 $
—
2,994 $
—
3,233 $
45
3,643 $
1,648
1,648 $
(1,686)
(3,164) $
1,269 $
1,110
1,428
1,797 $
1,457
1,879
27 $
15
15
940 $
850
775
8 $
7
8
301 $
286
270
29 $
16
21
483 $
473
423
15 $
50
45
1,942 $
1,824
1,647
740 $
675
515
92 $
87
74
19,510 $
18,001
16,878
4,741 $
4,214
4,056
2,452 $
2,215
2,292
2,696 $
2,562
2,683
4,156 $
3,911
3,549
1,929 $
1,742
1,812
432 $
440
364
365 $
1,455
857
(108)
$
(1,376)
282
347 $
361
461
832 $
984
679
168 $
417
301
106 $
105
103
387 $
525
468
74 $
218
174
129 $
126
123
466 $
538
587
6 $
104
149
453
261 $
245
195
432 $
578
(58)
35 $
217
3
279 $
283
290
(249) $
(296)
(555)
(55) $
294
(156)
(3,289) $
(3,020)
(3,159)
— $
—
—
(3,341) $
(3,026)
(3,164)
— $
—
—
(1) $
(2)
(5)
— $
—
—
2,146
207
13,869
1,166
7
31,365
1
2
5
4,353
3,828
3,936
32,143
29,619
28,106
1,554
1,560
1,536
2,232
3,782
1,973
120
(126)
753
Table of Contents
Net income (loss):
2018
2017
2016
Capital expenditures:
2018
2017
2016
Total assets:
2018
$
$
$
$
$
Combined Notes to Consolidated Financial Statements - (Continued)
(Dollars in millions, except per share data unless otherwise noted)
Generation (a)
ComEd
PECO
BGE
PHI (e)
Other (b)
Intersegment
Eliminations
Exelon
Successor
443 $
2,798
550
2,242 $
2,259 $
3,078 $
664 $
567
378
2,126 $
2,250 $
2,734 $
460 $
434
438
849 $
732 $
686 $
313 $
307
294
959 $
882 $
934 $
398 $
362
(61)
1,375 $
1,396 $
1,008 $
(193) $
(590)
(398)
43 $
65 $
113 $
(1) $
(2)
(5)
— $
— $
— $
2,084
3,876
1,196
7,594
7,584
8,553
47,556 $
48,457
31,213 $
29,726
10,642 $
10,170
9,716 $
9,104
21,984 $
21,247
8,355 $
8,618
(9,800) $
(10,552)
119,666
116,770
2017
__________
(a) See Note 25 — 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.
(e) Amounts included represent activity for PHI's successor period, March 24, 2016 through December 31, 2018 .
454
Table of Contents
Successor and Predecessor PHI:
Operating revenues (a) :
December 31, 2018 - Successor
Rate-regulated electric revenues
Rate-regulated natural gas revenues
Shared service and other revenues
Total operating revenues
December 31, 2017 - Successor
Rate-regulated electric revenues
Rate-regulated natural gas revenues
Shared service and other revenues
Total operating revenues
March 24, 2016 to December 31, 2016 - Successor
Rate-regulated electric revenues
Rate-regulated natural gas revenues
Shared service and other revenues
Total operating revenues
January 1, 2016 to March 23, 2016 - Predecessor
Rate-regulated electric revenues
Rate-regulated natural gas revenues
Shared service and other revenues
Total operating revenues
Intersegment revenues:
December 31, 2018 - Successor
December 31, 2017 - Successor
March 24, 2016 to December 31, 2016 - Successor
January 1, 2016 to March 23, 2016 - Predecessor
Depreciation and amortization:
December 31, 2018 - Successor
December 31, 2017 - Successor
March 24, 2016 to December 31, 2016 - Successor
January 1, 2016 to March 23, 2016 - Predecessor
Operating expenses:
December 31, 2018 - Successor
December 31, 2017 - Successor
March 24, 2016 to December 31, 2016 - Successor
January 1, 2016 to March 23, 2016 - Predecessor
Combined Notes to Consolidated Financial Statements - (Continued)
(Dollars in millions, except per share data unless otherwise noted)
Pepco
DPL
ACE
Other (b)
Intersegment
Eliminations
PHI
$
$
$
$
$
$
$
$
$
$
$
2,239 $
—
—
2,239 $
2,158 $
—
—
2,158 $
1,675 $
—
—
1,675 $
511 $
—
—
511 $
6 $
6
4
1
385 $
321
224
71
1,151 $
181
—
1,332 $
1,139 $
161
—
1,300 $
850 $
92
—
942 $
279 $
56
—
335 $
8 $
8
5
2
182 $
167
120
37
1,236 $
—
—
1,236 $
1,186 $
—
—
1,186 $
989 $
—
—
989 $
268 $
—
—
268 $
3 $
2
2
1
136 $
146
128
37
1,919 $
1,760
1,577
443
1,143 $
1,071
952
284
1,087 $
1,029
1,000
251
455
— $
—
435
435 $
— $
—
52
52 $
5 $
—
45
50 $
42 $
1
—
43 $
435 $
53
47
—
37 $
42
43
11
442 $
68
33
73
$
(17)
—
(420)
4,609
181
15
(437)
$
4,805
$
(14)
—
(3)
4,469
161
49
(17)
$
4,679
$
(13)
—
—
3,506
92
45
(13)
$
3,643
$
(4)
—
—
1,096
57
—
(4)
$
1,153
(437)
$
(19)
(13)
(4)
— $
$
(1)
— $
$
(4)
15
50
45
—
740
675
515
152
(435)
(17)
(13)
(3)
$
$
$
$
4,156
3,911
3,549
1,048
Table of Contents
Combined Notes to Consolidated Financial Statements - (Continued)
(Dollars in millions, except per share data unless otherwise noted)
Pepco
DPL
ACE
Other (b)
Intersegment
Eliminations
PHI
Interest expense, net:
December 31, 2018 - Successor
December 31, 2017 - Successor
March 24, 2016 to December 31, 2016 - Successor
January 1, 2016 to March 23, 2016 - Predecessor
Income (loss) before income taxes:
December 31, 2018 - Successor
December 31, 2017 - Successor
March 24, 2016 to December 31, 2016 - Successor
January 1, 2016 to March 23, 2016 - Predecessor
Income taxes:
December 31, 2018 - Successor
December 31, 2017 - Successor
March 24, 2016 to December 31, 2016 - Successor
January 1, 2016 to March 23, 2016 - Predecessor
Net income (loss):
December 31, 2018 - Successor
December 31, 2017 - Successor
March 24, 2016 to December 31, 2016 - Successor
January 1, 2016 to March 23, 2016 - Predecessor
Capital expenditures:
December 31, 2018 - Successor
December 31, 2017 - Successor
March 24, 2016 to December 31, 2016 - Successor
January 1, 2016 to March 23, 2016 - Predecessor
Total assets:
December 31, 2018 - Successor
December 31, 2017 - Successor
$
$
$
$
$
$
128 $
121
98
29
223 $
310
36
47
13 $
105
26
15
210 $
205
10
32
656 $
628
489
97
58 $
51
38
12
142 $
192
(30)
43
22 $
71
5
17
120 $
121
(35)
26
364 $
428
277
72
64 $
61
47
15
87 $
103
(51)
5
12 $
26
(5)
1
75 $
77
(47)
5
335 $
312
218
93
11 $
13
12
11
388 $
377
(84)
59
(10) $
15
(23)
(16)
(22) $
(91)
(34)
(44)
20 $
28
24
11
— $
(1) $
— $
(2) $
(408) $
(404) $
71 $
(118) $
(2) $
— $
— $
— $
15 $
50 $
45 $
— $
— $
— $
—
—
261
245
195
65
432
578
(58)
36
35
217
3
17
398
362
(61)
19
1,375
1,396
1,008
273
8,299 $
7,832
4,588 $
4,357
3,699 $
3,445
10,819 $
10,600
(5,421) $
(4,987)
21,984
21,247
456
Table of Contents
Combined Notes to Consolidated Financial Statements - (Continued)
(Dollars in millions, except per share data unless otherwise noted)
__________
(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. For the predecessor periods presented, Other
includes the activity of PHI’s unregulated businesses which were distributed to Exelon and Generation as a result of the PHI Merger.
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 England
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)
2018
Contracts with customers
$
5,241
$
4,527
2,660
1,723
572
870
15,593
1,524
510
17,627
457
Other (b)
Total
Intersegment Revenues
Total Revenues
233 $
5,474 $
190
185
(36)
560
686
1,818
1,194
(202)
4,717
2,845
1,687
1,132
1,556
17,411
2,718
308
$
13
(11)
(4)
—
1
(62)
(63)
62
1
2,810 $
20,437 $
— $
5,487
4,706
2,841
1,687
1,133
1,494
17,348
2,780
309
20,437
Combined Notes to Consolidated Financial Statements - (Continued)
(Dollars in millions, except per share data unless otherwise noted)
Revenues from external customers (a)
2017
Contracts with customers
$
5,523 $
Other (b)
Total
Intersegment Revenues
Total Revenues
(8) $
5,515 $
25
$
3,923
2,064
1,605
641
594
14,350
1,658
744
283
(54)
(38)
317
482
982
917
(151)
4,206
2,010
1,567
958
1,076
15,332
2,575
593
(25)
(8)
(17)
4
(27)
(48)
53
(5)
Total Generation Consolidated Operating Revenues
$
16,752 $
1,748 $
18,500 $
— $
Revenues from external customers (a)
2016
Contracts with customers
$
6,182 $
Other (b)
Total
Intersegment Revenues
Total Revenues
30 $
6,212 $
(33)
$
Table of Contents
Mid-Atlantic
Midwest
New England
New York
ERCOT
Other Power Regions
Total Competitive Businesses Electric Revenues
Competitive Businesses Natural Gas Revenues
Competitive Businesses Other Revenues (c)
Mid-Atlantic
Midwest
New England
New York
ERCOT
Other Power Regions
Total Competitive Businesses Electric Revenues
Competitive Businesses Natural Gas Revenues
Competitive Businesses Other Revenues (c)
4,007
1,953
1,198
810
670
14,820
1,953
756
395
(175)
10
21
299
580
193
(545)
4,402
1,778
1,208
831
969
15,400
2,146
211
10
(9)
(42)
6
(62)
(130)
135
(5)
5,540
4,181
2,002
1,550
962
1,049
15,284
2,628
588
18,500
6,179
4,412
1,769
1,166
837
907
15,270
2,281
206
17,757
Total Generation Consolidated Operating Revenues
$
17,529 $
228 $
17,757 $
— $
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 and $52 million decrease to revenues for
the amortization of intangible assets and liabilities related to commodity contracts recorded at fair value in 2017 and 2016 , respectively, unrealized mark-to-market losses
of $262 million , $131 million , and $500 million in 2018 , 2017 , and 2016 , respectively, and elimination of intersegment revenues.
458
Table of Contents
Combined Notes to Consolidated Financial Statements - (Continued)
(Dollars in millions, except per share data unless otherwise noted)
Revenues net of purchased power and fuel expense (Generation):
RNF from
external
customers (a)
2018
Intersegment
RNF
Mid-Atlantic
$
3,022
$
Midwest
New England
New York
ERCOT
Other Power Regions
Total Revenues net of
purchased power and
fuel for Reportable
Segments
3,112
368
1,112
501
515
$
8,630
$
RNF from
external
customers (a)
2016
Intersegment
RNF
3,282
$
2,969
35 $
2
Total
RNF
3,073 $
3,135
354
1,122
258
375
51 $
23
(14)
10
(243)
(140)
$
(313)
313
8,317 $
427
RNF from
external
customers (a)
3,105
$
2,810
538
1,007
575
476
8,511
$
2017
Intersegment
RNF
109 $
10
(24)
1
(243)
(171)
Total
RNF
3,214 $
2,820
514
1,008
332
305
$
(318)
318
8,193 $
617
467
771
412
483
8,384
$
Total
RNF
3,317
2,971
438
752
281
336
8,095
(29)
(19)
(131)
(147)
$
(289)
289
$
114
299
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 and $57 million decrease in RNF for the
amortization of intangible assets and liabilities related to commodity contracts in 2017 and 2016 , respectively, unrealized mark-to-market losses of $319 million , $175
million , and $41 million in 2018 , 2017 , and 2016 , respectively, accelerated nuclear fuel amortization associated with the announced early plant retirements as discussed
in Note 8 - Early Plant Retirements of $57 million , $12 million and $60 million for the year ended December 31, 2018 , 2017 , and 2016 and the elimination of
intersegment RNF.
Includes purchases and sales from/to third parties and affiliated sales to the Utility Registrants.
8,744 $
8,810 $
— $
— $
— $
8,927
8,744
8,810
8,927
832
543
$
$
$
459
Table of Contents
Combined Notes to Consolidated Financial Statements - (Continued)
(Dollars in millions, except per share data unless otherwise noted)
Electric and Gas Revenue by Customer Class (Utility Registrants):
Revenues from contracts with customers
ComEd
PECO
BGE
PHI
Pepco
DPL
ACE
2018
Successor
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)
—
10
1
11
—
7
—
7
4
3
1
8
(4)
—
—
(4)
$
5,882 $
3,038 $
3,169 $
4,805 $
2,239 $
1,332 $
1,236
460
Table of Contents
Combined Notes to Consolidated Financial Statements - (Continued)
(Dollars in millions, except per share data unless otherwise noted)
2017
Successor
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)
Other revenues (f)
Total other revenues
Total rate-regulated revenues for reportable
segments
2,715 $
1,363
455
44
886
5,463
—
—
—
—
—
—
1,505 $
401
223
30
204
2,363
331
131
1
23
8
494
1,365 $
254
427
31
299
2,376
437
75
119
—
28
659
2,246 $
490
1,086
60
541
4,423
90
38
8
15
9
160
964 $
137
794
33
199
2,127
—
—
—
—
—
—
663 $
187
103
14
163
1,130
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
40
8
1
47
96
26
5
—
—
31
6
3
1
—
10
8
—
—
—
8
$
5,536 $
2,870 $
3,176 $
4,679 $
2,158 $
1,300 $
1,186
461
Table of Contents
Combined Notes to Consolidated Financial Statements - (Continued)
(Dollars in millions, except per share data unless otherwise noted)
Revenues from contracts with customers
ComEd
PECO
BGE
Pepco
DPL
ACE
PHI
PHI
2016
Successor
Predecessor
March 24, 2016 to
December 31, 2016
January 1, 2016 to
March 23, 2016
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)
2,603 $
1,318
462
45
820
5,248
1,631 $
430
234
32
192
2,519
1,504 $
276
434
35
276
2,525
1,004 $
150
790
32
190
2,166
672 $
188
99
13
160
1,132
664 $
183
201
13
187
1,248
—
—
—
—
—
—
309
121
—
24
9
463
432
66
114
—
28
640
—
—
—
—
—
—
86
35
6
13
8
148
—
—
—
—
—
—
1,779 $
400
835
45
400
3,459
50
21
4
10
7
92
561
121
255
13
169
1,119
36
14
2
3
2
57
5,248
2,982
3,165
2,166
1,280
1,248
3,551
1,176
(24)
30
—
—
6
—
12
—
—
12
53
13
2
—
68
14
6
—
—
20
(6)
3
—
—
(3)
9
—
—
—
9
43
6
—
43
92
(26)
3
—
—
(23)
$
5,254 $
2,994 $
3,233 $
2,186 $
1,277 $
1,257 $
3,643 $
1,153
Includes revenues from transmission revenue from PJM, wholesale electric revenue and mutual assistance revenue.
Includes operating revenues from affiliates of $ 27 million , $7 million , $8 million , $15 million , $6 million , $8 million and $3 million at ComEd, PECO, BGE, PHI, Pepco,
DPL and ACE, respectively, in 2018 , $15 million , $6 million , $5 million , $3 million , $6 million , $8 million and $2 million at ComEd, PECO, BGE, PHI, Pepco, DPL and
ACE, in 2017 , and $15 million , $7 million , $7 million , $2 million , $5 million , $7 million and $3 million at ComEd, PECO, BGE, PHI, Pepco, DPL and ACE, respectively,
in 2016 .
Includes revenues from off-system natural gas sales.
Includes operating revenues from affiliates of $1 million and $21 million at PECO and BGE, respectively, in 2018 , $1 million and $11 million at PECO and BGE,
respectively, in 2017 , and $1 million and $14 million at PECO and BGE, respectively, in 2016 .
Includes late payment charge revenues.
Includes operating revenues from affiliates of $47 million and $43 million at PHI in 2017 and 2016 , respectively.
(c)
(d)
(e)
(f)
462
Table of Contents
Combined Notes to Consolidated Financial Statements - (Continued)
(Dollars in millions, except per share data unless otherwise noted)
25. Related Party Transactions (All Registrants)
Exelon
The financial statements of Exelon include related party transactions as presented in the tables below:
Operating revenues from affiliates:
Generation (a)
PECO (a)
BGE (a)
ACE (a)
Other
Total operating revenues from affiliates
Interest expense to affiliates, net:
ComEd Financing III
PECO Trust III
PECO Trust IV
BGE Capital Trust II
Total interest expense to affiliates, net
Earnings (losses) in equity method investments:
Qualifying facilities and domestic power projects
Other
Total losses in equity method investments
Payables to affiliates (current):
ComEd Financing III
PECO Trust III
Total payables to affiliates (current)
Long-term debt to financing trusts:
ComEd Financing III
PECO Trust III
PECO Trust IV
Total long-term debt to financing trusts
$
$
$
$
$
For the Years Ended
December 31,
2018
2017
2016
(2)
—
—
—
1
(1) $
13 $
6
6
—
25 $
(29) $
1
(28) $
$
$
$
$
—
1
4
—
2
7 $
14 $
6
6
10
36 $
(33) $
1
(32) $
December 31,
2018
2017
4 $
1
5 $
206 $
81
103
390 $
1
4
—
5
10
13
6
6
16
41
(25)
1
(24)
4
1
5
205
81
103
389
__________
(a) The intersegment profit associated with the sale of certain products and services by and between Exelon’s segments is not eliminated in consolidation due to the
recognition of intersegment profit in accordance with regulatory authoritative guidance. For Exelon, these amounts are included in operating revenues in the Consolidated
Statements of Operations. See Note 4 — Regulatory Matters for additional information.
463
Table of Contents
Combined Notes to Consolidated Financial Statements - (Continued)
(Dollars in millions, except per share data unless otherwise noted)
Transactions involving Generation, ComEd, PECO, BGE, PHI, Pepco, DPL and ACE are further described in the tables below.
Generation
The financial statements of Generation include related party transactions as presented in the tables below:
Operating revenues from affiliates:
ComEd (a)
PECO (b)
BGE (c)
Pepco (d)
DPL (e)
ACE (f)
BSC
Other
Total operating revenues from affiliates
Purchased power and fuel from affiliates:
ComEd
BGE
Other
Total purchased power and fuel from affiliates
Operating and maintenance from affiliates:
ComEd (g)
PECO (g)
BGE (g)
Pepco
PHISCO
BSC (h)
Other
Total operating and maintenance from affiliates
Interest expense to affiliates, net:
Exelon Corporate (i)
PCI
PECO
Total interest expense to affiliates, net:
Earnings (losses) in equity method investments
Qualifying facilities and domestic power projects
Capitalized costs
BSC (h)
Cash distributions paid to member
Contributions from member
For the Years Ended
December 31,
2018
2017
2016
$
523
128
260
206
120
29
2
—
$
121
138
388
255
179
29
1
4
47
290
608
295
154
37
2
6
1,268 $
1,115 $
1,439
(6) $
20
—
14 $
7 $
2
2
1
1
652
(4)
661 $
36 $
—
—
36 $
13 $
9
(3)
19 $
7 $
1
1
—
1
689
(2)
697 $
37 $
1
1
39 $
(30) $
(33) $
67 $
1,001 $
155 $
98 $
659 $
102 $
—
12
—
12
7
3
1
1
1
650
—
663
39
—
—
39
(25)
98
922
142
$
$
$
$
$
$
$
$
$
$
$
$
464
Table of Contents
Combined Notes to Consolidated Financial Statements - (Continued)
(Dollars in millions, except per share data unless otherwise noted)
Receivables from affiliates (current):
ComEd (a)
PECO (b)
BGE (c)
Pepco (d)
DPL (e)
ACE (f)
PHISCO (h)
Other
Total receivables from affiliates (current)
Intercompany money pool (current):
Exelon Corporate
PCI
Total intercompany money pool (current)
Payables to affiliates (current):
Exelon Corporate (i)
BSC (h)
ComEd
PECO (b)
Other
Total payables to affiliates (current)
Other liabilities to affiliates (current):
ComEd (a)
Long-term debt to affiliates (noncurrent):
Exelon Corporate (k)
Payables to affiliates (noncurrent):
ComEd (j)
PECO (j)
Total payables to affiliates (noncurrent)
465
December 31,
2018
2017
69 $
30
24
28
7
5
—
10
28
26
24
36
12
6
1
7
173 $
140
100 $
—
100 $
17 $
95
19
—
8
139 $
14 $
898 $
2,217 $
389
2,606 $
—
54
54
21
74
12
4
12
123
—
910
2,528
537
3,065
$
$
$
$
$
$
$
$
$
$
Table of Contents
Combined Notes to Consolidated Financial Statements - (Continued)
(Dollars in millions, except per share data unless otherwise noted)
__________
(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) 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.
(c) Generation provides a portion of BGE’s energy requirements under its MDPSC-approved market-based SOS and gas commodity programs.
(d) Generation provides electric supply to Pepco under contracts executed through Pepco's competitive procurement process approved by the MDPSC and DCPSC.
(e) Generation provides a portion of DPL's energy requirements under its MDPSC and DPSC approved market based SOS and gas commodity programs.
(f) Generation provides electric supply to ACE under contracts executed through ACE's competitive procurement process.
(g) Generation requires electricity for its own use at its generating stations. Generation purchases electricity and distribution and transmission services from PECO and BGE
and only distribution and transmission services from ComEd for the delivery of electricity to its generating stations.
(h) Generation receives a variety of corporate support services from BSC and PHISCO, including legal, human resources, financial, information technology and supply
(i)
management services. All services are provided at cost, including applicable overhead. A portion of such services is capitalized.
The balance consists of interest owed to Exelon Corporation related to the senior unsecured notes, as well as, expense related to certain invoices Exelon Corporation
processed on behalf of Generation.
(j) 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 15 — Asset Retirement Obligations for additional information.
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.
(k)
466
Table of Contents
ComEd
Combined Notes to Consolidated Financial Statements - (Continued)
(Dollars in millions, except per share data unless otherwise noted)
The financial statements of ComEd include related party transactions as presented in the tables below:
Operating revenues from affiliates
Generation
BSC
PECO
BGE
Total operating revenues from affiliates
Purchased power from affiliates
Generation (a)
Operating and maintenance from affiliates
BSC (b)
PECO
BGE
Total operating and maintenance from affiliates
Interest expense to affiliates, net:
ComEd Financing III
Capitalized costs
BSC (b)
Cash dividends paid to parent
Contributions from parent
Prepaid voluntary employee beneficiary association trust (c)
Receivables from affiliates (current):
Voluntary employee beneficiary association trust
Generation
Total receivables from affiliates (current)
Receivables from affiliates (noncurrent):
Generation (d)
Payables to affiliates (current):
Generation (a)
BSC (b)
ComEd Financing III
Exelon Corporate
Total payables to affiliates (current)
Long-term debt to ComEd financing trust:
ComEd Financing III
For the Years Ended
December 31,
2018
2017
2016
$
$
$
$
$
$
$
$
$
9
$
7
10
1
27 $
9
$
6
—
—
15 $
529 $
108 $
265 $
1
1
267 $
270 $
—
—
270 $
13 $
13 $
135 $
459 $
500 $
118 $
422 $
651 $
7
6
1
1
15
47
225
1
1
227
13
112
369
315
2
1
12
13
December 31,
2018
2017
5 $
1 $
19
20 $
2,217 $
2,528
55 $
56
4
4
119 $
28
39
4
3
74
205 $
205
$
$
$
$
$
$
$
__________
(a) ComEd procures a portion of its electricity supply requirements from Generation under an ICC-approved RFP contract. ComEd also purchases RECs and ZECs from
Generation.
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Table of Contents
Combined Notes to Consolidated Financial Statements - (Continued)
(Dollars in millions, except per share data unless otherwise noted)
(b) ComEd 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. A portion of such services is capitalized.
(c) The voluntary employee benefit association trusts covering active employees are included in corporate operations and are funded by the Registrants. A prepayment to the
active welfare plans has accumulated due to actuarially determined contribution rates, which are the basis for ComEd’s contributions to the plans, being higher than actual
claim expense incurred by the plans over time. The prepayment is included in other current assets.
(d) ComEd has a long-term receivable from Generation as a result of the nuclear decommissioning contractual construct for generating facilities previously owned by ComEd.
To the extent the assets associated with decommissioning are greater than the applicable ARO at the end of decommissioning, such amounts are due back to ComEd for
payment to ComEd’s customers.
PECO
The financial statements of PECO include related party transactions as presented in the tables below:
Operating revenues from affiliates:
Generation (a)
BSC
ComEd
BGE
ACE
Total operating revenues from affiliates
Purchased power from affiliates
Generation (b)
Operating and maintenance from affiliates:
BSC (c)
Generation
ComEd
BGE
Total operating and maintenance from affiliates
Interest expense to affiliates, net:
PECO Trust III
PECO Trust IV
Exelon Corporate
Generation
Total interest expense to affiliates, net:
Capitalized costs
BSC (c)
Cash dividends paid to parent
Contributions from parent
For the Years Ended
December 31,
2018
2017
2016
2
$
3
1
1
1
8 $
1
$
5
—
1
—
7 $
126 $
135 $
146 $
146 $
2
7
1
2
—
1
156 $
149 $
6 $
6
2
—
14 $
64 $
306 $
89 $
6 $
6
—
(1)
11 $
59 $
288 $
16 $
3
3
1
1
—
8
287
142
2
1
1
146
6
6
—
—
12
57
277
18
$
$
$
$
$
$
$
$
$
$
468
Table of Contents
Combined Notes to Consolidated Financial Statements - (Continued)
(Dollars in millions, except per share data unless otherwise noted)
Prepaid voluntary employee beneficiary association trust (d)
Receivables from affiliates (noncurrent):
Generation (e)
Payables to affiliates (current):
Generation (b)
BSC (c)
Exelon Corporate
PECO Trust III
Total payables to affiliates (current)
Long-term debt to financing trusts:
PECO Trust III
PECO Trust IV
Total long-term debt to financing trusts
December 31,
2018
2017
1 $
389 $
30 $
26
2
1
59 $
81 $
103
184 $
—
537
22
29
1
1
53
81
103
184
$
$
$
$
$
$
__________
(a) PECO provides energy to Generation for Generation’s own use.
(b) PECO purchases electric supply from Generation under contracts executed through its competitive procurement process. In addition, PECO has five-year and ten-year
agreements with Generation to purchase non-solar and solar AECs, respectively.
(c) PECO 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. A portion of such services is capitalized.
(d) The voluntary employee beneficiary association trusts covering active employees are included in corporate operations and are funded by the Registrants. A prepayment to
the active welfare plans has accumulated due to actuarially determined contribution rates, which are the basis for PECO’s contributions to the plans, being higher than
actual claim expense incurred by the plans over time.
(e) PECO has a long-term receivable from Generation as a result of the nuclear decommissioning contractual construct, whereby, to the extent the assets associated with
decommissioning are greater than the applicable ARO at the end of decommissioning, such amounts are due back to PECO for payment to PECO’s customers.
469
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BGE
Combined Notes to Consolidated Financial Statements - (Continued)
(Dollars in millions, except per share data unless otherwise noted)
The financial statements of BGE include related party transactions as presented in the tables below:
Operating revenues from affiliates:
Generation (a)
BSC
ComEd
PECO
Total operating revenues from affiliates
Purchased power from affiliates
Generation (b)
Operating and maintenance from affiliates:
BSC (c)
Generation
ComEd
PECO
Total operating and maintenance from affiliates
Interest expense to affiliates, net:
BGE Capital Trust II
Capitalized costs
BSC (c)
Cash dividends paid to parent
Contributions from parent
Receivables from affiliates (current):
Other
Payables to affiliates (current):
Generation (b)
BSC (c)
Exelon Corporate
Other
Total payables to affiliates (current)
For the Years Ended
December 31,
2018
2017
2016
$
$
$
$
$
$
$
$
$
22
$
5
1
1
29 $
10
$
5
—
1
16 $
257 $
384 $
157 $
152 $
3
1
1
—
—
1
162 $
153 $
— $
10 $
79 $
209 $
109 $
54 $
198 $
184 $
December 31,
2018
2017
$
$
$
1 $
24 $
38
2
1
65 $
13
6
1
1
21
604
130
—
1
1
132
16
36
179
61
1
24
25
1
2
52
__________
(a) BGE provides energy to Generation for Generation’s own use.
(b) BGE procures a portion of its electricity and gas supply requirements from Generation under its MDPSC-approved market-based SOS and gas commodity programs.
(c) BGE 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. A portion of such services is capitalized.
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PHI
Combined Notes to Consolidated Financial Statements - (Continued)
(Dollars in millions, except per share data unless otherwise noted)
The financial statements of PHI include related party transactions as presented in the tables below:
$
$
$
$
$
$
$
$
$
$
Operating revenues from affiliates:
BSC
PHISCO
Generation
Total operating revenues from affiliates
Purchased power from affiliates
Generation
Operating and maintenance from affiliates:
BSC (a)
Other
Total operating and maintenance from affiliates
Earnings (losses) in equity method investments:
Other
Capitalized costs:
BSC (a)
PHISCO (a)
Total capitalized costs
Cash dividends paid to parent
Contributions from parent
Payables to affiliates (current):
Generation
BGE
BSC (a)
Exelon Corporate
Other
Total payables to affiliates (current)
For the Year Ended
December 31,
Successor
For the Year Ended
December 31,
March 24, 2016 to
December 31,
2018
2017
2016
12 $
1
2
15 $
355 $
147 $
5
152 $
1 $
102 $
79
181 $
326 $
385 $
$
$
48 $
2
—
50 $
463 $
145 $
5
150 $
— $
— $
—
— $
311 $
758 $
December 31,
2018
2017
40 $
—
41
6
7
94 $
44
—
1
45
486
86
3
89
—
—
—
—
273
1,251
54
1
24
6
5
90
__________
(a) PHI receives a variety of corporate support services from BSC and PHISCO, including legal, human resources, financial, information technology and supply management
services. All services are provided at cost, including applicable overhead. A portion of such services is capitalized.
471
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Pepco
Combined Notes to Consolidated Financial Statements - (Continued)
(Dollars in millions, except per share data unless otherwise noted)
The financial statements of Pepco include related party transactions as presented in the tables below:
Operating revenues from affiliates:
Generation (a)
BSC
PHISCO
Total operating revenues from affiliates
Purchased power from affiliates
Generation (b)
Operating and maintenance:
PHISCO (c), (e)
PES (d)
Total operating and maintenance
Operating and maintenance from affiliates:
BSC (c)
PHISCO (c), (e)
Total operating and maintenance from affiliates
Capitalized costs:
BSC (c)
PHISCO (c)
Total capitalized costs
Cash dividends paid to parent
Contributions from parent
Receivables from affiliates (current):
DPL
Payables to affiliates (current):
Exelon Corporation
Generation (b)
BSC (c)
PHISCO (c)
Total payables to affiliates (current)
$
$
$
$
$
$
$
$
$
$
$
For the Years Ended
December 31,
2018
2017
2016
1 $
1
4
6 $
— $
—
6
6 $
206 $
255 $
— $
—
— $
89 $
137
226 $
40 $
32
72 $
169 $
166 $
$
$
$
219 $
29
248 $
53 $
5
58 $
— $
—
— $
133 $
161 $
December 31,
2018
2017
1 $
1 $
28
19
14
62 $
1
—
4
5
295
263
39
302
31
4
35
—
—
—
136
187
—
—
36
11
27
74
__________
(a) Pepco provides energy to Generation for Generation’s own use.
(b) Pepco procures a portion of its electricity supply requirements from Generation under its MDPSC and DCPSC approved market based SOS commodity programs.
(c) Pepco receives a variety of corporate support services from BSC and PHISCO, including legal, human resources, financial, information technology and supply
management services. All services are provided at cost, including applicable overhead. A portion of such services is capitalized.
(d) PES performed underground transmission, distribution construction and maintenance services, including services that are treated as capital costs, for Pepco.
472
Table of Contents
Combined Notes to Consolidated Financial Statements - (Continued)
(Dollars in millions, except per share data unless otherwise noted)
(e) 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 in 2018.
DPL
The financial statements of DPL include related party transactions as presented in the tables below:
Operating revenues from affiliates:
BSC
PHISCO
ComEd
ACE
Other
Total operating revenues from affiliates
Purchased power from affiliates
Generation (a)
Operating and maintenance:
PHISCO (b), (d)
PES (c)
Total operating and maintenance
Operating and maintenance from affiliates:
BSC (b)
PHISCO (b), (d)
Other
Total operating and maintenance from affiliates
Capitalized costs:
BSC (b)
PHISCO (b)
Total capitalized costs
Cash dividends paid to parent
Contributions from parent
Payables to affiliates (current):
Exelon Corporate
Generation (a)
BSC (b)
PHISCO (b)
Pepco
ACE
Total payables to affiliates (current)
__________
$
$
$
$
$
$
$
$
$
$
$
For the Years Ended
December 31,
2018
2017
2016
1 $
4
1
1
1
8 $
— $
6
—
—
2
8 $
120 $
179 $
— $
—
— $
51 $
111
—
162 $
28 $
25
53 $
96 $
150 $
$
$
165 $
9
174 $
31 $
—
1
32 $
— $
—
— $
112 $
— $
December 31,
2018
2017
1 $
7
11
12
1
1
33 $
—
5
—
—
2
7
154
194
8
202
18
—
1
19
—
—
—
54
152
—
12
7
27
—
—
46
473
Table of Contents
Combined Notes to Consolidated Financial Statements - (Continued)
(Dollars in millions, except per share data unless otherwise noted)
(a) DPL procures a portion of its electricity and gas supply requirements from Generation under its MDPSC and DPSC approved market based SOS and gas commodity
programs.
(b) DPL receives a variety of corporate support services from BSC and PHISCO, including legal, human resources, financial, information technology and supply management
services. All services are provided at cost, including applicable overhead. A portion of such services is capitalized.
(c) PES performed underground transmission construction services, including services that are treated as capital costs, for DPL.
(d) 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 in 2018.
ACE
The financial statements of ACE include related party transactions as presented in the tables below:
Operating revenues from affiliates:
PHISCO
Other
Total operating revenues from affiliates
Purchased power from affiliates
Generation (a)
Operating and maintenance:
PHISCO (b), (c)
Operating and maintenance from affiliates:
BSC (b)
PHISCO (b), (c)
Other
Total operating and maintenance from affiliates
Capitalized costs:
BSC (b)
PHISCO (b)
Total capitalized costs
Cash dividends paid to parent
Contributions from parent
Receivable from affiliate (current):
DPL
Payables to affiliates (current):
Generation (a)
BSC (b)
PHISCO (b)
Other
Total payables to affiliates (current)
$
$
$
$
$
$
$
$
$
$
For the Years Ended
December 31,
2018
2017
2016
2 $
1
3 $
29 $
— $
42 $
98
2
142 $
20 $
21
41 $
59 $
67 $
$
$
$
1 $
1
2 $
29 $
135 $
25 $
—
3
28 $
— $
—
— $
68 $
— $
December 31,
2018
2017
1 $
5 $
8
13
2
28
$
2
1
3
37
155
15
—
3
18
—
—
—
63
139
—
6
5
18
—
29
__________
(a) ACE purchases electric supply from Generation under contracts executed through its competitive procurement process.
474
Table of Contents
Combined Notes to Consolidated Financial Statements - (Continued)
(Dollars in millions, except per share data unless otherwise noted)
(b) ACE receives a variety of corporate support services from BSC and PHISCO, including legal, human resources, financial, information technology and supply management
services. All services are provided at cost, including applicable overhead. A portion of such services is capitalized.
(c) 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 in 2018.
26. 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:
Operating Revenues
Operating Income
Net Income
Attributable to
Common Shareholders
2018
2017
2018
2017
2018
2017
Quarter ended:
March 31
June 30
September 30
December 31
Quarter ended:
March 31
June 30
September 30
December 31
Generation
$
9,693 $
8,747 $
1,101 $
1,308 $
585 $
8,076
9,403
8,814
7,665
8,768
8,384
942
1,146
708
300
1,499
1,288
Net Income
per Basic Share
539
733
152
Net Income
per Diluted Share
2018
2017
2018
2017
$
0.61 $
0.56
0.76
0.16
1.07 $
0.10
0.86
1.95
0.60 $
0.56
0.76
0.16
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 (Loss)
Net Income (Loss)
Attributable to
Membership Interest
2018
2017
2018
2017
2018
2017
$
5,512 $
4,878 $
347 $
373 $
136 $
4,579
5,278
5,069
4,216
4,750
4,657
282
311
35
(427)
497
504
178
234
(178)
475
990
95
823
1,880
1.06
0.10
0.85
1.94
418
(235)
304
2,224
Table of Contents
ComEd
Combined Notes to Consolidated Financial Statements - (Continued)
(Dollars in millions, except per share data unless otherwise noted)
The data shown below includes all adjustments that ComEd considers necessary for a fair presentation of such amounts:
Operating Revenues
Operating Income
Net Income
2018
2017
2018
2017
2018
2017
$
1,512 $
1,298 $
292 $
314 $
165 $
1,398
1,598
1,373
1,357
1,571
1,309
288
323
242
319
404
286
164
193
141
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
2018
2017
2018
2017
2018
2017
$
866 $
796 $
142 $
192 $
113 $
653
757
765
630
715
729
127
154
165
137
169
157
96
126
124
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
2018
2017
2018
2017
2018
2017
$
977 $
951 $
177 $
228 $
128 $
662
731
799
674
738
813
476
85
103
109
98
124
163
51
63
71
141
118
189
120
127
88
112
107
125
45
62
76
Table of Contents
PHI
Combined Notes to Consolidated Financial Statements - (Continued)
(Dollars in millions, except per share data unless otherwise noted)
The data shown below includes all adjustments that PHI considers necessary for a fair presentation of such amounts:
Operating Revenues
Operating Income
Net Income Attributable to
Membership Interest
2018
2017
2018
2017
2018
2017
$
1,251 $
1,175 $
126 $
180 $
65 $
1,076
1,361
1,117
1,074
1,310
1,121
153
245
126
148
285
159
84
187
62
Quarter ended:
March 31
June 30
September 30
December 31
Pepco
The data shown below includes all adjustments that Pepco considers necessary for a fair presentation of such amounts:
Operating Revenues
Operating Income
Net Income
2018
2017
2018
2017
2018
2017
$
557 $
530 $
56 $
79 $
523
628
531
514
604
510
85
112
65
84
149
87
31 $
54
89
36
Quarter ended:
March 31
June 30
September 30
December 31
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
2018
2017
2018
2017
2018
2017
$
384 $
362 $
289
328
331
282
327
330
49 $
42
51
48
78 $
41
59
52
31 $
26
33
30
Quarter ended:
March 31
June 30
September 30
December 31
ACE
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)
2018
2017
2018
2017
2018
2017
$
310 $
275 $
265
406
254
270
370
271
477
23 $
25
84
14
25 $
25
79
28
7 $
8
61
(1)
140
66
153
4
58
43
87
17
57
19
31
14
28
8
41
—
Table of Contents
Combined Notes to Consolidated Financial Statements - (Continued)
(Dollars in millions, except per share data unless otherwise noted)
27. Subsequent Events (Exelon and Generation)
Generation’s Antelope Valley, a 242 MW solar facility in Lancaster, CA, sells all of its output to Pacific Gas and Electric Company (PG&E) through a PPA. As of
December 31, 2018, Generation had approximately $750 million and $510 million of net long-lived assets and nonrecourse debt outstanding, respectively,
related to Antelope Valley. The nonrecourse debt is guaranteed by the DOE Loan Programs Office. Neither the guarantor nor the lender have recourse against
Exelon or Generation in the event of default.
On January 29, 2019, PG&E filed for protection under Chapter 11 of the U.S. Bankruptcy Code. PG&E’s bankruptcy creates an event of default for Antelope
Valley’s nonrecourse debt. As such, Antelope Valley is currently in discussions with the DOE Loan Programs Office, and the debt has not yet been accelerated.
Given that the event of default did not occur until January 2019, the debt continued to be classified as non-current on Exelon’s and Generation’s Consolidated
Balance Sheets as of December 31, 2018, and may be reclassified to current in 2019.
Generation has also assessed and determined that Antelope Valley’s long-lived assets are not impaired as of December 31, 2018. 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. The
impairment loss could be substantially all of the net long-lived assets if Antelope Valley was valued without the PPA. 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.
Antelope Valley is a wholly owned indirect subsidiary of EGR IV, which had approximately $1,990 million and $830 million of additional net long-lived assets and
nonrecourse debt outstanding, respectively, as of December 31, 2018. 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. EGR IV is currently not in default, however, an acceleration of Antelope Valley’s
debt could impact EGR IV. The lenders do not have recourse against Exelon or Generation in the event of default by EGR IV. See Note 2 - Variable Interest
Entities for additional details on EGRP and Note 13 — Debt and Credit Agreements for additional details on Generation's nonrecourse project financings .
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Table of Contents
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 2018 , 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, 2018 , 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 2018 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, 2018 . As a result of that
assessment, management determined that there were no material weaknesses as of December 31, 2018 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.
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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 for a
reduced disclosure format. Accordingly, all items in this section relating to Generation, PECO, BGE, PHI, Pepco, DPL and ACE are not presented.
ITEM 10.
DIRECTORS, EXECUTIVE OFFICERS AND CORPORATE GOVERNANCE
Executive Officers
The information required by ITEM 10. relating to executive officers is set forth above in ITEM 1. BUSINESS — Executive officers of the Registrants at
February 8, 2019 .
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 2019 proxy statement ( 2019 Exelon Proxy Statement) and the
ComEd information statement ( 2019 ComEd Information Statement) to be filed with the SEC on or before April 30, 2019 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.
480
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ITEM 11.
EXECUTIVE COMPENSATION
The information required by this item will be set forth under Executive Compensation Data and Report of the Compensation Committee in the Exelon Proxy
Statement for the 2019 Annual Meeting of Shareholders or the ComEd 2019 Information Statement, which are incorporated herein by reference.
481
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ITEM 12.
SECURITY OWNERSHIP OF CERTAIN BENEFICIAL OWNERS AND MANAGEMENT AND RELATED STOCKHOLDER
MATTERS
The additional information required by this item will be set forth under Ownership of Exelon Stock in the 2019 Exelon Proxy Statement or the ComEd 2019
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 [B]) (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 2016, 2017 and 2018 , 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 4,942,100 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 2,471,000 . The deferred stock units granted to directors includes 433,400 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 19 — Stock-Based Compensation Plans of the Combined Notes to Consolidated Financial Statements for
additional information about the material features of the plans.
10,401,300 $
30,071,500
23.77
(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 18,410,700 shares remaining available for issuance from the employee stock purchase plan.
No ComEd securities are authorized for issuance under equity compensation plans.
482
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ITEM 13.
CERTAIN RELATIONSHIPS AND RELATED TRANSACTIONS AND DIRECTOR INDEPENDENCE
The additional information required by this item will be set forth under Related Persons Transactions and Director Independence in the Exelon Proxy Statement
for the 2019 Annual Meeting of Shareholders or the ComEd 2019 Information Statement, which are incorporated herein by reference.
483
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ITEM 14.
PRINCIPAL ACCOUNTING FEES AND SERVICES
The information required by this item will be set forth under The Ratification of PricewaterhouseCoopers LLP as Exelon’s Independent Accountant for 2019 in
the Exelon Proxy Statement for the 2019 Annual Meeting of Shareholders and the ComEd 2019 Information Statement, which are incorporated herein by
reference.
484
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PART IV
ITEM 15.
EXHIBITS, FINANCIAL STATEMENT SCHEDULES
(a)
The following documents are filed as a part of this report:
(1) Exelon
(i)
Financial Statements (Item 8):
Report of Independent Registered Public Accounting Firm dated February 8, 2019 of PricewaterhouseCoopers LLP
Consolidated Statements of Operations and Comprehensive Income for the Years Ended December 31, 2018, 2017 and 2016
Consolidated Statements of Cash Flows for the Years Ended December 31, 2018, 2017 and 2016
Consolidated Balance Sheets at December 31, 2018 and 2017
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, 2018 and 2017 and for the Years Ended
December 31, 2018, 2017 and 2016
Schedule II—Valuation and Qualifying Accounts for the Years Ended December 31, 2018, 2017 and 2016
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.
485
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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 (loss) on equity investments
Unrealized (loss) gain on foreign currency translation
Other comprehensive income (loss)
Comprehensive income
For the Years Ended
December 31,
2018
2017
2016
$
(5) $
10 $
9
4
8
(8)
(312)
2,188
42
3
1,921
1,913
(97)
25
4
39
(39)
(315)
4,414
40
1
4,140
4,101
315
$
$
2,010 $
3,786 $
(66) $
247
(143)
12
—
1
(10)
41
(56) $
197
10
3
6
6
7
173
221
51
4
276
(276)
(312)
1,508
39
7
1,242
966
(155)
1,121
(48)
184
(181)
2
1
(4)
10
(36)
$
2,051 $
3,959 $
1,085
See the Notes to Financial Statements
486
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Exelon Corporation and Subsidiary Companies
Schedule I – Condensed Financial Information of Parent (Exelon Corporate)
Condensed Statements of Cash Flows
(In millions)
Net cash flows provided by operating activities
Cash flows from investing activities
Changes in Exelon intercompany money pool
Investment in affiliates
Acquisition of business
Other investing activities
Net cash flows used in investing activities
Cash flows from financing activities
Issuance of long-term debt
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) 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
$
See the Notes to Financial Statements
487
For the Years Ended
December 31,
2018
2017
2016
$
2,581 $
1,921 $
1,029
1
(1,236)
—
—
(129)
(1,717)
—
(5)
(1,235)
(1,851)
—
—
—
—
(1,332)
105
(4)
(1,231)
115
74
189 $
—
500
(569)
1,150
(1,236)
150
(9)
(14)
56
18
74 $
1,390
(1,757)
(6,962)
5
(7,324)
1,800
—
(46)
—
(1,166)
55
(20)
623
(5,672)
5,690
18
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
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,
2018
2017
$
189 $
48
44
216
182
4
683
48
3,742
40,448
1,455
898
235
46,778
47,509 $
$
See the Notes to Financial Statements
488
74
431
33
217
284
4
1,043
50
3,697
39,311
1,431
910
234
45,583
46,676
Table of Contents
(In millions)
Current liabilities
Exelon Corporation and Subsidiary Companies
Schedule I – Condensed Financial Information of Parent (Exelon Corporate)
Condensed Balance Sheets
LIABILITIES AND SHAREHOLDERS’ EQUITY
Short-term borrowings
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, 968 shares and 963 shares outstanding
at December 31, 2018 and 2017, respectively)
Treasury stock, at cost (2 shares at December 31, 2018 and 2017)
Retained earnings
Accumulated other comprehensive loss, net
Total shareholders’ equity
Total liabilities and shareholders’ equity
December 31,
2018
2017
$
500 $
1
184
360
15
63
14
1,137
7,147
32
7,795
199
233
202
8,461
16,745
19,116
(123)
14,766
(2,995)
30,764
500
2
99
360
16
65
46
1,088
7,161
15
7,792
322
220
180
8,529
16,778
18,966
(123)
14,081
(3,026)
29,898
46,676
$
47,509 $
See the Notes to Financial Statements
489
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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 BGE, of which Exelon owns 100% of the common stock but none of BGE’s preferred stock. BGE redeemed all of
its outstanding preferred stock in 2016.
2. Mergers
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 Pepco Holdings, Inc. (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 Exelon Energy Delivery Company, LLC (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). See Note 5 — Mergers, Acquisitions and Dispositions of the Combined
Notes to Consolidated Financial Statements for additional information on the PHI Merger.
3. Debt and Credit Agreements
Short-Term Borrowings
Exelon Corporate meets its short-term liquidity requirements primarily through the issuance of commercial paper. Exelon Corporate had no commercial paper
borrowings at both December 31, 2018 and December 31, 2017 .
Short-Term Loan Agreements
On March 23, 2017, Exelon Corporate entered into a $500 million term loan agreement which expired on March 22, 2018. The loan agreement was renewed on
March 22, 2018 and will expire on March 21, 2019. Pursuant to the loan agreement, loans made thereunder bear interest at a variable rate equal to LIBOR plus
1% and all indebtedness thereunder is unsecured. The loan agreement is reflected in Exelon’s Consolidated Balance Sheet within Short-Term borrowings.
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, 2018 , Exelon Corporation had available capacity under
those commitments of $591 million . See Note 13 — Debt and Credit Agreements of the Combined Notes to Consolidated Financial Statements for additional
information regarding Exelon Corporation’s credit agreement.
490
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Long-Term Debt
Exelon Corporation and Subsidiary Companies
Schedule I – Condensed Financial Information of Parent (Exelon Corporate)
Notes to Financial Statements
The following tables present the outstanding long-term debt for Exelon Corporate as of December 31, 2018 and December 31, 2017 :
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 of consolidated subsidiary
Long-term debt
Rates
Maturity
Date
December 31,
2018
2017
2.45%
3.50%
7.60%
2022 $
1,150 $
2020 - 2046
5,889
7,039
(7)
(47)
162
1,150
5,889
7,039
(8)
(49)
179
$
7,147
$
7,161
__________
(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 2019 , 2020 , 2021 , 2022 , 2023 and thereafter are as follows:
2019
2020
2021
2022
2023
Remaining years
Total long-term debt
4. Commitments and Contingencies
$
$
—
1,450
300
1,150
—
4,139
7,039
See Note 22 — 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.
491
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5. Related Party Transactions
Exelon Corporation and Subsidiary Companies
Schedule I – Condensed Financial Information of Parent (Exelon Corporate)
Notes to Financial Statements
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)
PCI
BSC
UII, LLC
Exelon Transmission Company, LLC
Exelon Enterprise
Generation
Total equity in earnings of investments:
Cash contributions received from affiliates
For the Years Ended
December 31,
2018
2017
2016
11 $
(2)
9 $
36 $
4
2 $
42 $
23 $
2
25 $
37 $
3
— $
40 $
51
—
51
39
—
—
39
1,835 $
1,670 $
1,041
(17)
—
—
1
—
369
2,188 $
1
1
41
(10)
1
2,710
4,414 $
6
1
(9)
(13)
(1)
483
1,508
2,302 $
1,879 $
1,912
$
$
$
$
$
$
$
$
492
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
Total accounts receivable from affiliates (current):
Notes receivable from affiliates (current):
BSC (a)
Generation (c)
Total notes receivable from affiliates (current):
Investments in affiliates:
BSC (a)
Exelon Energy Delivery Company, LLC (b)
PCI
UII, LLC
Exelon Transmission Company, LLC
Voluntary Employee Beneficiary Association trust
Exelon Enterprises
Generation
Other
Total investments in affiliates:
Notes receivable from affiliates (non-current):
Generation (c)
Accounts payable to affiliates (current):
December 31,
2018
2017
13 $
17
4
2
2
6
44 $
116 $
100
216 $
197 $
26,702
61
268
1
(1)
22
13,204
(6)
40,448 $
1
21
3
1
1
6
33
217
—
217
196
25,082
78
268
1
(4)
22
13,674
(6)
39,311
898 $
910
$
$
$
$
$
$
$
UII, LLC
__________
(a) Exelon Corporate receives a variety of corporate support services from BSC, including legal, human resources, financial, information technology and supply management services. All
360 $
360
$
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.
493
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Exelon Corporation and Subsidiary Companies
Schedule II – Valuation and Qualifying Accounts
Column A
Column B
Column C
Column D
Column E
Additions and adjustments
Description
Balance at
Beginning
of Period
Charged to
Costs and
Expenses
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
Reserve for obsolete materials
For the year ended December 31, 2016
Allowance for uncollectible accounts (a)
Deferred tax valuation allowance
$
322
$
159
$
37
174
—
25
$
334
$
126
$
20
113
—
56
$
284
$
13
162
$
—
Charged
to Other
Accounts
(in millions)
35
5
(31)
(d)
Deductions
Balance at
End
of Period
(c)
$
197 (e) $
7
12
27
17
10
99
10
(c)
$
165 (e) $
—
5
(b)(c) $
(b)
211 (e) $
3
319
35
156
322
37
174
334
20
Reserve for obsolete materials
__________
(a) Excludes the non-current allowance for uncollectible accounts related to PECO’s installment plan receivables of $13 million , $15 million , and $23 million for the years
113
105
(b)
12
1
5
ended December 31, 2018 , 2017 and 2016 , 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.
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(2) Generation
(i)
Financial Statements (Item 8):
Exelon Generation Company, LLC and Subsidiary Companies
Report of Independent Registered Public Accounting Firm dated February 8, 2019 of PricewaterhouseCoopers LLP
Consolidated Statements of Operations and Comprehensive Income for the Years Ended December 31, 2018, 2017 and 2016
Consolidated Statements of Cash Flows for the Years Ended December 31, 2018, 2017 and 2016
Consolidated Balance Sheets at December 31, 2018 and 2017
Consolidated Statements of Changes in Equity for the Years Ended December 31, 2018, 2017 and 2016
Notes to Consolidated Financial Statements
(ii)
Financial Statement Schedule:
Schedule II—Valuation and Qualifying Accounts for the Years Ended December 31, 2018, 2017 and 2016
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
495
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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, 2018
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
For the year ended December 31, 2016
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
$
77
$
11
102
496
$
$
44
—
20
34
—
51
19
$
—
6
$
4
3
(32)
(a)
—
$
14
9
3
—
—
$
58 $
—
9
11 $
—
—
8 $
2
2
104
26
145
114
23
166
91
9
106
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 8, 2019 of PricewaterhouseCoopers LLP
Consolidated Statements of Operations and Comprehensive Income for the Years Ended December 31, 2018, 2017 and 2016
Consolidated Statements of Cash Flows for the Years Ended December 31, 2018, 2017 and 2016
Consolidated Balance Sheets at December 31, 2018 and 2017
Consolidated Statements of Changes in Shareholders’ Equity for the Years Ended December 31, 2018, 2017 and 2016
Notes to Consolidated Financial Statements
(ii)
Financial Statement Schedule:
Schedule II—Valuation and Qualifying Accounts for the Years Ended December 31, 2018, 2017 and 2016
Schedules not included are omitted because of the absence of conditions under which they are required or because the required information is
provided in the consolidated financial statements, including the notes thereto
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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, 2018
Allowance for uncollectible accounts
Reserve for obsolete materials
For the year ended December 31, 2017
Allowance for uncollectible accounts
Reserve for obsolete materials
For the year ended December 31, 2016
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.
$
$
$
73
5
70
4
75
3
498
$
$
$
44
3
39
3
45
4
23 (a) $
1
20 (a) $
1
23 (a) $
1
59 (b) $
3
56 (b) $
3
73 (b) $
4
81
6
73
5
70
4
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 8, 2019 of PricewaterhouseCoopers LLP
Consolidated Statements of Operations and Comprehensive Income for the Years Ended December 31, 2018, 2017 and 2016
Consolidated Statements of Cash Flows for the Years Ended December 31, 2018, 2017 and 2016
Consolidated Balance Sheets at December 31, 2018 and 2017
Consolidated Statements of Changes in Shareholder's Equity for the Years Ended December 31, 2018, 2017 and 2016
Notes to Consolidated Financial Statements
(ii)
Financial Statement Schedule:
Schedule II—Valuation and Qualifying Accounts for the Years Ended December 31, 2018, 2017 and 2016
Schedules not included are omitted because of the absence of conditions under which they are required or because the required information is
provided in the consolidated financial statements, including the notes thereto
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Table of Contents
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, 2018
Allowance for uncollectible accounts (a)
Reserve for obsolete materials
For the year ended December 31, 2017
Allowance for uncollectible accounts (a)
Reserve for obsolete materials
For the year ended December 31, 2016
Allowance for uncollectible accounts (a)
$
$
$
$
$
56
2
61
2
$
$
33
—
26
—
3 (b) $
—
4 (b) $
—
31 (c) $
—
35 (c) $
—
61
2
56
2
61
Reserve for obsolete materials
__________
(a) Excludes the non-current allowance for uncollectible accounts related to PECO’s installment plan receivables of $13 million , $15 million , and $23 million for the years
—
1
2
1
83
$
32
$
7 (b) $
61 (c) $
—
ended December 31, 2018 , 2017 , and 2016 , respectively.
(b) Primarily charges for late payments.
(c) Write-off of individual accounts receivable.
500
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 8, 2019 of PricewaterhouseCoopers LLP
Consolidated Statements of Operations and Comprehensive Income for the Years Ended December 31, 2018, 2017 and 2016
Consolidated Statements of Cash Flows for the Years Ended December 31, 2018, 2017 and 2016
Consolidated Balance Sheets at December 31, 2018 and 2017
Consolidated Statements of Changes in Shareholder's Equity for the Years Ended December 31, 2018, 2017 and 2016
Notes to Consolidated Financial Statements
(ii)
Financial Statement Schedule:
Schedule II—Valuation and Qualifying Accounts for the Years Ended December 31, 2018, 2017 and 2016
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
501
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, 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
For the year ended December 31, 2016
Allowance for uncollectible accounts
Deferred tax valuation allowance
Reserve for obsolete materials
__________
(a) Write-off of individual accounts receivable.
$
$
$
$
$
24
1
—
32
1
—
49
$
1
—
502
$
$
10
—
1
8
—
—
1
$
—
—
(2)
$
—
—
(3)
$
—
—
9
$
—
—
12 (a) $
—
—
13 (a) $
—
—
27 (a) $
—
—
20
1
1
24
1
—
32
1
—
Table of Contents
(6) PHI
Pepco Holdings LLC and Subsidiary Companies
(i)
Successor Company Financial Statements (Item 8):
Report of Independent Registered Public Accounting Firm dated February 8, 2019 of PricewaterhouseCoopers LLP
Consolidated Statements of Operations and Comprehensive Income (Loss) for the Years Ended December 31, 2018 and 2017 and for the Period
March 24, 2016 to December 31, 2016
Consolidated Statements of Cash Flows for the Years Ended December 31, 2018 and 2017 and for the Period March 24, 2016 to December 31,
2016
Consolidated Balance Sheets at December 31, 2018 and 2017
Consolidated Statements of Changes in Equity for the Years Ended December 31, 2018 and 2017 and for the Period March 24, 2016 to
December 31, 2016
Notes to Consolidated Financial Statements
(ii)
Predecessor Company Financial Statements (Item 8):
Report of Independent Registered Public Accounting Firm dated February 13, 2017 of PricewaterhouseCoopers LLP
Consolidated Statements of Operations and Comprehensive Income for the Period January 1, 2016 to March 23, 2016
Consolidated Statements of Cash Flows for the Period January 1, 2016 to March 23, 2016
Consolidated Statements of Changes in Equity for the Period January 1, 2016 to March 23, 2016
Notes to Consolidated Financial Statements
(iii)
Successor Financial Statement Schedule:
Schedule II – Valuation and Qualifying Accounts - For the Years Ended December 31, 2018 and 2017 and the Period March 24, 2016 to
December 31, 2016
(iv)
Predecessor Financial Statement Schedule:
Schedule II – Valuation and Qualifying Accounts - For the Period January 1, 2016 to March 23, 2016
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
503
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, 2018 (Successor)
Allowance for uncollectible accounts
Deferred tax valuation allowance
Reserve for obsolete materials
For the Year Ended December 31, 2017 (Successor)
Allowance for uncollectible accounts
Deferred tax valuation allowance
Reserve for obsolete materials
March 24, 2016 to December 31, 2016 (Successor)
Allowance for uncollectible accounts
Deferred tax valuation allowance
Reserve for obsolete materials
January 1, 2016 to March 23, 2016 (Predecessor)
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.
$
$
$
$
28 $
—
—
19 $
—
2
65 $
—
1
16 $
—
—
55 $
13
2
80 $
10
2
52 $
63
—
56 $
63
—
504
(a) $
7
2
—
(b) $
37
7
—
6
3
—
(a) $
50
(b) $
—
2
5
(a) $
42
(b) $
(53)
—
—
(1)
2
(a) $
22
(b) $
—
—
—
—
53
8
2
55
13
2
80
10
2
52
63
—
Table of Contents
(7) Pepco
(i)
Financial Statements (Item 8):
Potomac Electric Power Company
Report of Independent Registered Public Accounting Firm dated February 8, 2019 of PricewaterhouseCoopers LLP
Statements of Operations and Comprehensive Income for the Years Ended December 31, 2018, 2017 and 2016
Statements of Cash Flows for the Years Ended December 31, 2018, 2017 and 2016
Balance Sheets at December 31, 2018 and 2017
Statements of Changes in Shareholder's Equity for the Years Ended December 31, 2018, 2017 and 2016
Notes to Financial Statements
(ii)
Financial Statement Schedule:
Schedule II—Valuation and Qualifying Accounts for the Years Ended December 31, 2018, 2017 and 2016
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
505
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, 2018
Allowance for uncollectible accounts
Reserve for obsolete materials
For the year ended December 31, 2017
Allowance for uncollectible accounts
Reserve for obsolete materials
For the year ended December 31, 2016
Allowance for uncollectible accounts
Reserve for obsolete materials
__________
(a) Primarily charges for late payments.
(b) Write-off of individual accounts receivable.
$
$
$
21 $
1
29 $
1
17 $
—
506
11 $
—
8 $
1
29 $
3
3 (a) $
—
2 (a) $
—
3 (a) $
—
14 (b) $
—
18 (b) $
1
20 (b) $
2
21
1
21
1
29
1
Table of Contents
(8) DPL
(i)
Financial Statements (Item 8):
Delmarva Power & Light Company
Report of Independent Registered Public Accounting Firm dated February 8, 2019 of PricewaterhouseCoopers LLP
Statements of Operations and Comprehensive Income (Loss) for the Years Ended December 31, 2018, 2017 and 2016
Statements of Cash Flows for the Years Ended December 31, 2018, 2017 and 2016
Balance Sheets at December 31, 2018 and 2017
Statements of Changes in Shareholder's Equity for the Years Ended December 31, 2018, 2017 and 2016
Notes to Financial Statements
(ii)
Financial Statement Schedule:
Schedule II—Valuation and Qualifying Accounts for the Years Ended December 31, 2018, 2017 and 2016
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
507
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, 2018
Allowance for uncollectible accounts
Reserve for obsolete materials
For the year ended December 31, 2017
Allowance for uncollectible accounts
Reserve for obsolete materials
For the year ended December 31, 2016
Allowance for uncollectible accounts
Reserve for obsolete materials
__________
(a) Primarily charges for late payments.
(b) Write-off of individual accounts receivable.
$
$
$
16 $
—
24 $
—
17 $
—
508
6 $
—
3 $
1
23 $
1
2 (a) $
—
2 (a) $
—
2 (a) $
—
11 (b) $
—
13 (b) $
1
18 (b) $
1
13
—
16
—
24
—
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 8, 2019 of PricewaterhouseCoopers LLP
Consolidated Statements of Operations and Comprehensive Income (Loss) for the Years Ended December 31, 2018, 2017 and 2016
Consolidated Statements of Cash Flows for the Years Ended December 31, 2018, 2017 and 2016
Consolidated Balance Sheets at December 31, 2018 and 2017
Consolidated Statements of Changes in Shareholder's Equity for the Years Ended December 31, 2018, 2017 and 2016
Notes to Consolidated Financial Statements
(ii)
Financial Statement Schedule:
Schedule II—Valuation and Qualifying Accounts for the Years Ended December 31, 2018, 2017 and 2016
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
509
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, 2018
Allowance for uncollectible accounts
Reserve for obsolete materials
For the year ended December 31, 2017
Allowance for uncollectible accounts
Reserve for obsolete materials
For the year ended December 31, 2016
Allowance for uncollectible accounts
Reserve for obsolete materials
__________
(a) Primarily charges for late payments.
(b) Write-off of individual accounts receivable.
$
$
$
18 $
1
27 $
1
17 $
—
510
11 $
—
8 $
—
32 $
1
2 (a) $
—
2 (a) $
—
2 (a) $
—
12 (b) $
—
19 (b) $
—
24 (b) $
—
19
1
18
1
27
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
2-10-1
2-10-2
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).
Purchase Agreement, dated as of February 4, 2010, by and between RF HoldCo LLC and GSS Holdings (Baltimore Gas and Electric
Company Utility), Inc. (Designated as Exhibit No. 99.3 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).
Agreement and Plan of Merger, dated as of April 29, 2014, by and among Exelon Corporation, Pepco Holdings, Inc. and Purple Acquisition
Corp. (File No. 001-16169, Form 8-K dated April 30, 2014, Exhibit 2.1).
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).
511
Table of Contents
Exhibit No.
Description
2-10-3
2-10-4
3-1
3-2
3-3
3-4
3-5
3-6
3-7
3-8
3-9
3-10
3-11
3-12
3-13
3-14
Subscription Agreement for Series A Non-Voting Non-Convertible Preferred Stock, dated as of April 29, 2014, by and between Pepco
Holdings, Inc. and Exelon Corporation (File No. 001-16169, Form 8-K dated April 30, 2014, Exhibit 2.2).
Letter Agreement, dated March 7, 2016, among Pepco Holdings, Inc., Exelon Corporation and Purple Acquisition Corp. (File No. 001-31403,
Form 8-K dated March 7, 2016, Exhibit 2)
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 July 24, 2018 (File No. 001-16169, Form 8-K dated July 27, 2018, Exhibit
3.2).
Certificate of Formation of Exelon Generation Company, LLC (Registration Statement No. 333-85496, Form S-4, Exhibit 3-1).
First Amended and Restated Operating Agreement of Exelon Generation Company, LLC executed as of January 1, 2001 (File No. 333-85496,
2003 Form 10-K, Exhibit 3-8).
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 January 23, 2006 As Further Amended January 28, 2008 and
July 27, 2009. (File No. 001-1839, Form 8-K dated July 27, 2009, Exhibit 3.1).
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 Bylaws (File 000-16844, Form 8-K dated May 6, 2009, Exhibit 99.1).
Articles of Amendment to the Charter of Baltimore Gas and Electric Company as of February 2, 2010. (Designated as Exhibit No. 3.1 to the
Current Report on Form 8-K dated February 4, 2010, filed by Baltimore Gas and Electric Company, File No. 1-1910).
Articles of Restatement to the Charter of Baltimore Gas and Electric Company, restated as of August 16, 1996. (Designated as Exhibit No. 3
to the Quarterly Report on Form 10-Q for the quarter ended September 30, 1996, filed by Baltimore Gas and Electric Company, File No. 1-
1910).
Bylaws of Baltimore Gas and Electric Company, as amended and restated as of May 10, 2012. (File No. 1-16169, 2013 Form 10-K, Exhibit 3-
11).
Operating Agreement, dated as of February 4, 2010, by and among RF HoldCo LLC, Constellation Energy Group, Inc. and GSS Holdings
(BGE Utility), Inc. (Designated as Exhibit No. 99.1 to the Current Report on Form 8-K dated February 4, 2010, filed by Baltimore Gas and
Electric Company, File Nos. 1-12869 and 1-1910).
Certificate of Conversion of Pepco Holdings LLC, dated March 23, 2016 (File No. 001-31403, Form 8-K dated March 24, 2016, 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)
512
Table of Contents
Exhibit No.
3-15
3-16
3-17
3-18
3-19
3-20
3-21
3-22
4-1
4-1-2
4-1-3
Description
Limited Liability Company Agreement of Pepco Holdings LLC, dated March 23, 2016 (File No. 001-31403, Form 8-K dated March 24, 2016,
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)
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)
Reserved.
Supplemental Indentures to PECO Energy Company’s First and Refunding Mortgage:
Dated as of
May 1, 1927
March 1, 1937
December 1, 1941
November 1, 1944
December 1, 1946
September 1, 1957
May 1, 1958
March 1, 1968
March 1, 1981
March 1, 1981
December 1, 1984
March 1, 1993
File Reference
2-2881 (a)
2-2881 (a)
2-4863 (a)
2-5472 (a)
2-6821 (a)
2-13562 (a)
2-14020 (a)
2-34051 (a)
2-72802 (a)
2-72802 (a)
1-01401, 1984 Form 10-K (a)
1-01401, 1992 Form 10-K (a)
513
Exhibit No.
B-1(c)
B-1(g)
B-1(h)
B-1(i)
7-1(j)
2(b)-17
2(b)-18
2(b)-24
4-46
4-47
4-2(b)
4(e)-86
Table of Contents
Dated as of
May 1, 1993
May 1, 1993
April 15, 2004
September 15, 2006
March 1, 2007
March 15, 2009
September 1, 2012
September 15, 2013
September 1, 2014
File Reference
1-01401, March 31, 1993 Form 10-Q (a)
Exhibit No.
4(e)-88
1-01401, March 31, 1993 Form 10-Q (a)
4(e)-89
0-6844, September 30, 2004 Form 10-Q (a)
4-1-1
000-16844, Form 8-K dated September 25,
2006
000-16844, Form 8-K dated March 19, 2007
000-16844, Form 8-K dated March 26, 2009
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
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
000-16844, Form 8-K dated September 11,
2018
4.1
Exhibit No.
Description
4-2
4-3
Exelon Corporation Direct Stock Purchase Plan (Registration Statement No. 333-206474, Form S-3, Prospectus).
Mortgage of Commonwealth Edison Company to Illinois Merchants Trust Company, Trustee (BNY Mellon Trust Company of Illinois, as current
successor Trustee), dated July 1, 1923, as supplemented and amended by Supplemental Indenture thereto dated August 1, 1944.
(Registration No. 2-60201, Form S-7, Exhibit 2-1). (a)
4-3-1
Supplemental Indentures to Commonwealth Edison Company Mortgage.
Dated as of
August 1, 1946
April 1, 1953
March 31, 1967
File Reference
2-60201, Form S-7 (a)
2-60201, Form S-7 (a)
2-60201, Form S-7 (a)
514
Exhibit No.
2-1
2-1
2-1
Table of Contents
Dated as of
April 1, 1967
February 28, 1969
May 29, 1970
June 1, 1971
April 1, 1972
May 31, 1972
June 15, 1973
May 31, 1974
June 13, 1975
May 28, 1976
June 3, 1977
May 17, 1978
August 31, 1978
June 18, 1979
June 20, 1980
April 16, 1981
April 30, 1982
April 15, 1983
April 13, 1984
April 15, 1985
April 15, 1986
January 13, 2003
February 22, 2006
August 1, 2006
File Reference
2-60201, Form S-7 (a)
2-60201, Form S-7 (a)
2-60201, Form S-7 (a)
2-60201, Form S-7 (a)
2-60201, Form S-7 (a)
2-60201, Form S-7 (a)
2-60201, Form S-7 (a)
2-60201, Form S-7 (a)
2-60201, Form S-7 (a)
2-60201, Form S-7 (a)
2-60201, Form S-7 (a)
2-99665, Form S-3 (a)
2-99665, Form S-3 (a)
2-99665, Form S-3 (a)
2-99665, Form S-3 (a)
2-99665, Form S-3 (a)
2-99665, Form S-3 (a)
2-99665, Form S-3 (a)
2-99665, Form S-3 (a)
2-99665, Form S-3 (a)
33-6879, Form S-3 (a)
Exhibit No.
2-1
2-1
2-1
2-1
2-1
2-1
2-1
2-1
2-1
2-1
2-1
4-3
4-3
4-3
4-3
4-3
4-3
4-3
4-3
4-3
4-9
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
4.1
4.1
4.1
4.1
4.1
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
001-01839, Form 8-K dated March 27, 2008
4.1
515
September 17, 2012
001-01839, Form 8-K dated October 1, 2012
Table of Contents
Dated as of
July 12, 2010
August 22, 2011
August 1, 2013
January 2, 2014
October 28, 2014
February 18, 2015
November 4, 2015
June 15, 2016
August 9, 2017
February 6, 2018
July 26, 2018
File Reference
001-01839, Form 8-K dated August 2, 2010
Exhibit No.
4.1
001-01839, Form 8-K dated September 7,
2011
4.1
4.1
4.1
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
001-01839, Form 8-K dated February 20, 2018 4.1
001-01839, Form 8-K dated August 14, 2018
4.1
Exhibit No.
4-3-2
4-3-3
4-4
4-5
4-6
4-7
4-8
Description
Instrument of Registration, 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 dated as of September 1, 1987 between Commonwealth Edison Company and Citibank, N.A. (U.S. Bank National Association, as
current successor trustee), Trustee relating to Notes (Registration No. 33-20619, Form S-3, Exhibit 4-13). (a)
Indenture dated December 19, 2003 between Exelon Generation Company, LLC and U.S. Bank National Association (File No. 333-85496,
2003 Form 10-K, Exhibit 4-6).
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).
516
Table of Contents
Exhibit No.
Description
4-9
4-10
4-11
4-12
4-13
4-14
4-15
4-16
4-17
4-18
4-19
4-20
4-21
4-22
4-23
4-24
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 Secured 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).
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 5.20% Exelon Generation Company, LLC Senior Note due 2019 (File 333-85496, Form 8-K dated September 23, 2009, 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).
517
Table of Contents
Exhibit No.
4-25
4-26
4-27
4-28
4-29
4-30
4-31
4-32
4-33
4-34
4-35
Description
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 and Security Agreement dated as of July 9, 2009, between Baltimore Gas and Electric Company and Deutsche Bank Trust
Company Americas, as trustee (Designated as Exhibit No. 4(u) to Post-Effective Amendment No. 1 to the Registration Statement on Form
S-3 dated July 9, 2009, filed by Constellation Energy Group, Inc., File Nos. 333-157637 and 333-157637-01).
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).
Supplemental Indenture No. 1, dated as of October 1, 2009, to the Indenture and Security Agreement dated as of July 9, 2009, between
Baltimore Gas and Electric Company and Deutsche Bank Trust Company Americas, as trustee. (Designated as Exhibit No. 4(c) to the
Quarterly Report on Form 10-Q for the quarter ended September 30, 2009, filed by Constellation Energy Group, Inc., File Nos. 1-12869 and
1-1910).
Baltimore Gas and Electric Company Deed of Easement and Right-of-Way Grant dated as of July 9, 2009 (Designated as Exhibit No. 4(u)(2)
to Post-Effective Amendment No. 1 to the Registration Statement on Form S-3 dated July 9, 2009, filed by Constellation Energy Group, Inc.,
File Nos. 333-157637 and 333-157637-01).
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).
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).
518
Table of Contents
Exhibit No.
4-36
4-37
4-38
4-38-1
Description
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).
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).
4-38-2
Form of 2.50% Notes due 2024 (File No. 001-16169, Form 8-K dated June 23, 2014, Exhibit 4.2, Exhibit A).
4-38-3
4-38-4
4-38-5
4-38-6
4-39
4-39-1
4-39-2
4-39-3
4-40
4-41
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).
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).
Registration Rights Agreement, dated as of December 2, 2015, among Exelon Corporation, Barclays Capital Inc. and Goldman, Sachs & Co.
(incorporated herein by reference to Exhibit 1.1 to Exelon Corporation’s Current Report on Form 8-K, filed 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)
519
Table of Contents
Exhibit No.
4-42
Description
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)
4-42-1
Supplemental Indentures to Potomac Electric Power Company Mortgage.
Dated as of
File Reference
December 10, 1939
Form 8-K, 1/3/40 (a)
Exhibit No.
B
July 15, 1942
2-5032, Amendment No 2. To Registration
B-1
October 15, 1947
December 31, 1948
December 31, 1949
February 15, 1951
February 16, 1953
Statement, 8/24/42 (a)
Form 8-K , 12/8/47 (a)
Form 10-K, 4/13/49 (a)
Form 8-K, 2/8/50 (a)
Form 8-K, 3/9/51 (a)
Form 8-K, 3/5/53 (a)
March 15, 1954 and March 15, 1955
2-11627, Registration Statement, 5/2/55 (a)
March 15, 1956
Form 10-K, 4/4/56 (a)
A
A-2
(a)-1
(a)
(a)-1
4-B
C
4-B
2-B
April 1, 1957
May 1, 1958
May 1, 1959
May 2, 1960
April 3, 1961
May 1, 1962
May 1, 1963
April 23, 1964
May 3, 1965
June 1, 1966
April 28, 1967
2-13884, Registration Statement, 2/5/58 (a)
2-14518, Registration Statement, 11/10/58 (a)
2-15027, Amendment No. 1 to Registration
4-B
Statement, 5/13/59 (a)
2-17286, Registration Statement, 11/9/60 (a)
Form 10-K, 4/24/61 (a)
2-B
A-1
2-21037, Registration Statement, 1/25/63 (a)
2-B
2-21961, Registration Statement, 12/19/63 (a)
4-B
2-22344, Registration Statement, 4/24/64 (a)
2-B
2-24655, Registration Statement, 3/16/66 (a)
2-B
Form 10-K, 4/11/67 (a)
2-26356, Post-Effective Amendment No. 1 to
Registration Statement, 5/3/67 (a)
1
2-B
520
Table of Contents
Dated as of
July 3, 1967
May 1, 1968
June 16, 1969
May 15, 1970
September 1, 1971
June 17, 1981
November 1, 1985
September 16, 1987
May 1, 1989
May 21, 1991
May 7, 1992
September 1, 1992
November 1, 1992
July 1, 1993
February 10, 1994
February 11, 1994
October 2, 1997
File Reference
Exhibit No.
2-28080, Registration Statement, 1/25/68 (a)
2-B
2-31896, Registration Statement, 2/28/69 (a)
2-B
2-36094, Registration Statement, 1/27/70 (a)
2-B
2-38038, Registration Statement, 7/27/70 (a)
2-B
2-45591, Registration Statement, 9/1/72 (a)
2-C
Amendment No. 1 to Form 8-A, 6/18/81 (a)
2
Form 8-A, 11/1/85 (a)
33-18229, Registration Statement, 10/30/87
(a)
2B
4-B
33-29382, Registration Statement, 6/16/89 (a)
4-C
Form 10-K, 3/27/92 (a)
Form 10-K, 3/26/93 (a)
Form 10-K, 3/26/93 (a)
Form 10-K, 3/26/93 (a)
4
4
4
4
33-49973, Registration Statement, 8/11/93 (a)
4.4
001-01072, Form 10-K, 3/25/94
001-01072, Form 10-K, 3/25/94
001-01072, Form 10-K, 3/27/98
4
4
4
4.1
4.3
4.2
4
4.2
4.1
November 17, 2003
001-01072, Form 10-K, 3/12/04
March 16, 2004
May 24, 2005
April 1, 2006
001-01072, Form 8-K, 3/23/04
001-01072, Form 8-K, 5/26/05
001-01072, Form 8-K, 4/17/06
November 13, 2007
001-01072, Form 8-K, 11/15/07
March 24, 2008
001-01072, Form 8-K, 3/28/08
521
Table of Contents
Dated as of
December 3, 2008
March 28, 2012
March 11, 2013
File Reference
Exhibit No.
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, 6/21/2018
4.2
4.2
4.2
4.2
4.2
4.3
4.2
4.2
Exhibit No.
4-43
4-44
4-44-1
4-45
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 3, 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)
4-45-1
Supplemental Indentures to Delmarva Power & Light Company Mortgage.
Dated as of
January 1, 1986
June 1, 1986
January 1, 1987
September 1, 1987
October 1, 1987
January 1, 1988
File Reference
Exhibit No.
33-39756, Registration Statement, 4/03/91 (a)
4-B
33-24955, Registration Statement, 10/13/88
(a)
33-24955, Registration Statement, 10/13/88
(a)
33-24955, Registration Statement, 10/13/88
(a)
33-24955, Registration Statement, 10/13/88
(a)
33-24955, Registration Statement, 10/13/88
(a)
4-B
4-B
4-B
4-B
4-B
522
Table of Contents
Dated as of
December 1, 1988
January 1, 1989
March 1, 1990
January 1, 1991
July 1, 1991
February 1, 1992
May 1, 1992
October 1, 1992
January 1, 1993
June 1, 1993
July 1, 1993
October 1, 1993
January 1, 1994
October 1, 1994
January 1, 1995
June 1, 1995
January 1, 1996
January 1, 1997
January 1, 1998
January 1, 1999
January 1, 2000
File Reference
33-39756, Registration Statement, 4/03/91 (a)
Exhibit No.
4-D
33-39756, Registration Statement, 4/03/91 (a)
4-E
33-39756, Registration Statement, 4/03/91 (a)
4-F
33-46892, Registration Statement, 4/1/92 (a)
4-E
33-46892, Registration Statement, 4/1/92 (a)
4-F
33-49750, Registration Statement, 7/17/92 (a)
4
33-57652, Registration Statement, 1/29/93 (a)
4-G
33-63582, Registration Statement, 5/28/93 (a)
4-H
33-50453, Registration Statement, 10/1/93 (a)
99
33-53855, Registration Statement, 1/30/95 (a)
4-J
33-53855, Registration Statement, 1/30/95 (a)
4-K
33-53855, Registration Statement, 1/30/95 (a)
4-L
33-53855, Registration Statement, 1/30/95 (a)
4-M
33-53855, Registration Statement, 1/30/95 (a)
4-N
333-00505, Registration Statement, 1/29/96
(a)
333-00505, Registration Statement, 1/29/96
(a)
333-24059, Registration Statement, 3/27/97
(a)
001-01405, Form 10-K, 2/24/12
001-01405, Form 10-K, 2/24/12
001-01405, Form 10-K, 2/24/12
4-K
4-L
4-L
4.4
4.4
4.4
333-145691-02, Post Effective Amendment
No. 1 to Registration Statement, 11/18/08
4.24(k)
523
Table of Contents
Dated as of
January 1, 2001
January 1, 2002
January 1, 2003
January 1, 2004
January 1, 2005
January 1, 2006
January 1, 2007
January 1, 2008
January 1, 2009
File Reference
Exhibit No.
001-01405, Form 10-K, 2/24/12
001-01405, Form 10-K, 2/24/12
001-01405, Form 10-K, 2/24/12
001-01405, Form 10-K, 2/24/12
001-01405, Form 10-K, 2/24/12
001-01405, Form 10-K, 2/24/12
001-01405, Form 10-K, 2/24/12
001-01405, Form 10-K, 2/24/12
001-01405, Form 10-K, 2/24/12
September 22, 2009
001-01405, Form 8-K, 10/1/09
January 1, 2010
January 1, 2011
May 2, 2011
January 1, 2012
June 19, 2012
January 1, 2013
001-01405, Form 10-K, 2/25/11
001-01405, Form 10-Q, 8/3/11
001-01405, Form 8-K, 6/3/11
001-01405, Form 10-Q, 8/7/12
001-01405, Form 8-K, 6/20/12
001-01405, Form 10-Q, 8/7/13
November 7, 2013
001-01405, Form 8-K, 11/8/13
January 1, 2014
June 2, 2014
January 1, 2015
May 4, 2015
January 1, 2016
001-01405, Form 10-K, 2/27/15
001-01405, Form 8-K, 6/3/14
001-01405, Form 10-K, 2/19/16
001-01405, Form 8-K, 5/5/15
001-01405, Form 10-K, 2/13/17
December 5, 2016
001-01405, Form 8-K, 12/12/16
524
4.4
4.4
4.4
4.4
4.4
4.4
4.4
4.4
4.4
4.4
4.4
4.2
4.2
4.3
4.2
4.1
4.2
4.4
4.3
4.4
4.2
4.45.1
4.2
Table of Contents
Dated as of
April 5, 2017
April 3, 2018
June 1, 2018
Exhibit No.
Description
File Reference
001-01405, Form 10-Q, 5/3/17
000-01405, Form 10-Q, 5/2/18
000-01405, Form 8-K, 6/21/18
Exhibit No.
4.5
4.3
4.2
4-46
4-47
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)
4-47-1
Supplemental Indentures to Atlantic City Electric Company Mortgage.
Dated as of
June 1, 1949
July 1, 1950
November 1, 1950
March 1, 1952
January 1, 1953
March 1, 1954
March 1, 1955
January 1, 1957
April 1, 1958
April 1, 1959
March 1, 1961
July 1, 1962
March 1, 1963
File Reference
Exhibit No.
2-66280, Registration Statement, 12/21/79
(a)
2-66280, Registration Statement, 12/21/79
(a)
2-66280, Registration Statement, 12/21/79
(a)
2-66280, Registration Statement, 12/21/79
(a)
2-66280, Registration Statement, 12/21/79
(a)
2-66280, Registration Statement, 12/21/79
(a)
2-66280, Registration Statement, 12/21/79
(a)
2-66280, Registration Statement, 12/21/79
(a)
2-66280, Registration Statement, 12/21/79
(a)
2-66280, Registration Statement, 12/21/79
(a)
2-66280, Registration Statement, 12/21/79
(a)
2-66280, Registration Statement, 12/21/79
(a)
2-66280, Registration Statement, 12/21/79
(a)
2(b)
2(b)
2(b)
2(b)
2(b)
2(b)
2(b)
2(b)
2(b)
2(b)
2(b)
2(b)
2(b)
525
Table of Contents
Dated as of
February 1, 1966
April 1, 1970
September 1, 1970
May 1, 1971
April 1, 1972
June 1, 1973
January 1, 1975
May 1, 1975
December 1, 1976
January 1, 1980
May 1, 1981
November 1, 1983
April 15, 1984
July 15, 1984
October 1, 1985
May 1, 1986
July 15, 1987
October 1, 1989
March 1, 1991
May 1, 1992
January 1, 1993
August 1, 1993
September 1, 1993
November 1, 1993
June 1, 1994
October 1, 1994
File Reference
Exhibit No.
2-66280, Registration Statement, 12/21/79
(a)
2-66280, Registration Statement, 12/21/79
(a)
2-66280, Registration Statement, 12/21/79
(a)
2-66280, Registration Statement, 12/21/79
(a)
2-66280, Registration Statement, 12/21/79
(a)
2-66280, Registration Statement, 12/21/79
(a)
2-66280, Registration Statement, 12/21/79
(a)
2-66280, Registration Statement, 12/21/79
(a)
2-66280, Registration Statement, 12/21/79
(a)
Form 10-K, 3/25/81 (a)
Form 10-Q, 8/10/81 (a)
Form 10-K, 3/30/84 (a)
Form 10-Q, 5/14/84 (a)
Form 10-Q, 8/13/84 (a)
Form 10-Q, 11/12/85 (a)
Form 10-Q, 5/12/86 (a)
Form 10-K, 3/28/88 (a)
2(b)
2(b)
2(b)
2(b)
2(b)
2(b)
2(b)
2(b)
2(b)
4(e)
4(a)
4(d)
4(a)
4(a)
4
4
4(d)
Form 10-Q for quarter ended 9/30/89 (A)
4(a)
Form 10-K, 3/28/91 (a)
4(d)(1)
33-49279, Registration Statement, 1/6/93 (a) 4(b)
333-108861, Registration Statement,
9/17/03
4.05(hh)
Form 10-Q, 11/12/93 (a)
Form 10-Q, 11/12/93 (a)
Form 10-K, 3/29/94 (a)
Form 10-Q, 8/14/94 (a)
Form 10-Q, 11/14/94 (a)
526
4(a)
4(b)
4(c)(1)
4(a)
4(a)
Table of Contents
Dated as of
November 1, 1994
March 1, 1997
April 1, 2004
August 10, 2004
March 8, 2006
File Reference
Form 10-K, 3/21/95 (a)
Exhibit No.
4(c)(1)
001-03559, Form 8-K, 3/24/97
001-03559, Form 8-K, 4/6/04
001-03559, Form 10-Q, 11/9/04
001-03559, Form 8-K, 3/17/06
4(b)
4.3
4
4
4.2
4.2
4.2
4.2
4.1
November 6, 2008
001-03559, Form 8-K, 11/10/08
March 29, 2011
August 18, 2014
December 1, 2015
October 9, 2018
001-03559, Form 8-K, 4/1/11
001-03559, Form 8-K, 8/19/14
001-03559, Form 8-K, 12/2/15
001-03559, Form 8-K, 10/16/18
Exhibit No.
4-48
4-49
4-50
4-51
4-52
4-53
4-54
4-55
4-56
4-57
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)
Corporate Commercial Paper Master Note (File No. 001-31403, Form 10-K dated February 24, 2012, Exhibit 4.13)
Pepco Holdings, Inc. Certificate of Series A Non-Voting Non-Convertible Preferred Stock (File No. 001-31403, Form 8-k dated April 30,
2014, Exhibit 3.1)
Form of 2.400% notes due 2026 (File No. 001-01910, Form 8-K dated August 18, 2016, Exhibit 4.1)
Form of 3.500% notes due 2046 (File No. 001-01910, Form 8-K dated August 18, 2016, Exhibit 4.2)
527
Table of Contents
Exhibit No.
4-58
4-59
4-60
4-61
4-62
4-63
10-1
10-1-1
10-2
10-3
10-4
10-5
10-6
10-7
10-8
10-9
10-10
Description
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)
Facility Credit Agreement, dated as of February 6, 2014, among ExGen Renewables I Holding, LLC and Barclays Bank PLC (File No. 333-
85496, Form 8-K dated February 12, 2014, Exhibit 10.1).
Credit Agreement, dated as of September 18, 2014, among ExGen Texas Power, LLC, ExGen Texas Power Holdings, LLC, Wolf Hollow I
Power, LLC, Colorado Bend I Power, LLC, Laporte Power, LLC, Handley Power, LLC and Mountain Creek Power, LLC, the lenders party
thereto from time to time, Bank of America, N.A., as administrative agent and collateral agent, and Wilmington Trust, National Association,
as depositary agent. (File No. 1-16169, Form 8-K dated September 18, 2014, Exhibit 10.1).
Exelon Corporation Non-Employee Directors’ Deferred Stock Unit Plan (As Amended and Restated Effective January 1, 2011). * (File No.
001-16169, 2010 Form 10-K, Exhibit 10.1).
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)
Reserved.
Form of Restricted Stock Award Agreement under the Exelon Corporation Long-Term Incentive Plan* (File No. 1-16169, 2001 Form 10-K,
Exhibit 10-6-1).
Forms of Transferable Stock Option Award Agreement under the Exelon Corporation Long-Term Incentive Plan* (File No. 1-16169, 2001
Form 10-K, Exhibit 10-6-2).
Forms of Stock Option Award Agreement under the Exelon Corporation Long-Term Incentive Plan* (File No. 1-16169, 2001 Form 10-K,
Exhibit 10-6-3).
Unicom Corporation Deferred Compensation Unit Plan, as amended *(File Nos. 1-11375 and 1-1839, 1995 Form 10-K, Exhibit 10-12).
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).
Unicom Corporation Retirement Plan for Directors, as amended *(Registration Statement No. 333-49780, Form S-8, Exhibit 4-12).
528
Table of Contents
Exhibit No.
10-11
Description
Commonwealth Edison Company Retirement Plan for Directors, as amended *(Registration Statement No. 333-49780, Form S-8, Exhibit 4-
13).
10-12
10-13
10-14
10-15
10-16
10-17
10-18
10-19
10-20
10-21
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).
Form of change in control employment agreement for senior executives effective January 1, 2009 * (File No. 001-16169. 2008 Form 10-K,
Exhibit 10.23).
Form of change in control employment agreement (amended and restated as of January 1, 2009) * (File No. 001-16169, 2008 Form 10-K,
Exhibit 10.24).
Exelon Corporation Employee Stock Purchase Plan, as amended and restated effective July 1, 2013. (File No. 1-16169, Schedule 14A
dated March 14, 2013 Appendix A).
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 (Registration Statement No. 333-122704, Form S-4,
Joint Proxy Statement-Prospectus pursuant to Rule 424(b)(3) filed June 3, 2005, Annex I).
Exelon Corporation Senior Management Severance Plan (As Amended and Restated Effective April 1, 2013).* (File No. 001-16169, 2013
Form 10-K, Exhibit 10.21).
10-21-1
Exelon Corporation Senior Management Severance Plan (As Amended and Restated Effective November 1, 2015) * (File No. 1-16169, 2015
Form 10-K, Exhibit 10-21-1)
10-22
10-23
10-24
10-25
10-26
10-27
Form of Separation Agreement under Exelon Corporation Senior Management Severance Plan (As Amended and Restated Effective
November 1, 2015).
Facility Credit Agreement, dated as of November 4, 2010, among Exelon Generation Company, LLC and UBS AG, Stamford Branch (File
No. 333-85496, Form 8-K dated February 22, 2011, Exhibit No. 10-1).
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).
Amendment Number Two to the Exelon Corporation 2006 Long-Term Incentive Plan (As Amended and Restated Effective January 28,
2002), Effective December 4, 2006 (File No. 1-16169, 2006 Form 10-K, Exhibit 10-55).
529
Table of Contents
Exhibit No.
10-28
Description
Exelon Corporation Deferred Compensation Plan (As Amended and Restated Effective January 1, 2005) (File No. 1-16169, 2006 Form 10-
K, Exhibit 10-56).
10-29
10-30
10-31
10-32
10-33
10-34
10-34-1
10-34-2
10-34-3
10-35
10-36
10-37
10-38
10-39
10-40
10-41
Exelon Corporation Stock Deferral Plan (As Amended and Restated Effective January 1, 2005) (File No. 1-16169, 2006 Form 10-K, Exhibit
10-57).
Commonwealth Edison Company Long-Term Incentive Plan, Effective January 1, 2007 (File No. 1-16169, March 31, 2007 Form 10-Q,
Exhibit 10-1).
Amendment Number One to the Exelon Corporation Stock Deferral Plan (As Amended and Restated Effective January 1, 2005) (File No. 1-
16169, June 30, 2007 Form 10-Q, Exhibit 10-3).
Restricted stock unit award agreement (File 1-16169, Form 8-K dated August 31, 2007, Exhibit 99.1).
Reserved.
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)
Form of Exelon Corporation Long-Term Incentive Program, as amended and restated as of January 1, 2014. * (File No. 1-16169, 2015 Form
10-K, Exhibit 10-34-1)
Form of Exelon Corporation Long-Term Incentive Program, as amended and restated as of January 1, 2015. * (File No. 1-16169, 2015 Form
10-K, Exhibit 10-34-2)
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)
Form of Change in Control Employment Agreement Effective February 10, 2011. * (File 1-16169, 2010 Form 10-K, Exhibit 10-44).
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).
530
Table of Contents
Exhibit No.
10-42
Description
Amendment No. 1 to Credit Agreement, dated as of December 21, 2011, to the Credit Agreement dated as of March 23, 2011, among
Exelon Generation Company, LLC, the lenders party thereto and JPMorgan Chase Bank, N.A., as Administrative Agent (File No. 001-16169,
Form 8-K dated March 14, 2012, Exhibit No. 4-6).
10-43
10-44
10-45
10-46
10-47
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).
531
Table of Contents
Exhibit No.
10-48
Description
Executive Annual Incentive Plan of Constellation Energy Group, Inc., as amended and restated. * (Designated as Exhibit No. 10(d) to the
Quarterly Report on Form 10-Q for the quarter ended September 30, 2008, filed by Constellation Energy Group, Inc., File Nos. 1-12869 and
1-1910).
10-49
10-50
10-51
10-52
10-53
10-54
10-55
10-56
10-57
10-58
10-59
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).
Constellation Energy Group, Inc. 1995 Long-Term Incentive Plan, as amended and restated. * (Designated as Exhibit No. 10(b) to the
Constellation Quarterly Report on Form 10-Q for the quarter ended September 30, 2004, filed by Constellation Energy Group, Inc., File Nos.
1-12869 and 1-1910).
Constellation Energy Group, Inc. Executive Long-Term Incentive Plan, as amended and restated. * (Designated as Exhibit 10(b) to the
Constellation Quarterly Report on Form 10-Q for the quarter ended June 30, 2011, filed by Constellation Energy Group, Inc., File Nos. 1-
12869 and 1-1910).
Constellation Energy Group, Inc. 2002 Senior Management Long-Term Incentive Plan, as amended and restated. * (Designated as Exhibit
10(a) to the Constellation Quarterly Report on Form 10-Q for the quarter ended June 30, 2011, filed by Constellation Energy Group, Inc.,
File Nos. 1-12869 and 1-1910).
Constellation Energy Group, Inc. Management Long-Term Incentive Plan, as amended and restated. * (Designated as Exhibit 10(d) to the
Constellation Quarterly Report on Form 10-Q for the quarter ended September 30, 2006, filed by Constellation Energy Group, Inc., File Nos.
1-12869 and 1-1910).
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).
Form of Grant Agreement for Stock Units with Sales Restriction. * (Designated as Exhibit No. 10(x) 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).
Rate Stabilization Property Servicing Agreement dated as of June 29, 2007 by and between RSB BondCo LLC and Baltimore Gas and
Electric Company, as servicer (Designated as Exhibit 10.2 to the Current Report on Form 8-K dated July 5, 2007, filed by Baltimore Gas and
Electric Company, File No. 1-1910).
Administration Agreement dated as of June 29, 2007 by and between RSB BondCo LLC and Baltimore Gas and Electric Company, as
administrator (Designated as Exhibit 10.3 to the Current Report on Form 8-K dated July 5, 2007, filed by Baltimore Gas and Electric
Company, File No. 1-1910).
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).
532
Table of Contents
Exhibit No.
10-60
10-61
10-62
10-63
Description
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).
10-64 - 10-70
Reserved.
10-71
10-71-1
10-71-2
10-71-3
10-71-4
10-71-5
10-72-1
Commitment Letter for $7.221 Billion Senior Unsecured Bridge Facility, dated April 29, 2014 (File No. 001-16169, Form 8-K dated April 30,
2014, Exhibit No. 10.1).
364-Day Bridge Term Loan Agreement, dated as of May 30, 2014, among Exelon Corporation, as Borrower, the various financial institutions
named therein, as Lenders, and Barclays Bank PLC, as Administrative Agent (File No. 001-16169, Form 8-K dated April 30, 2014, Exhibit
No. 10.1).
Amendment No. 4 to Credit Agreement, dated May 30, 2014, among Exelon Corporation, as Borrower, the financial institutions signatory
therein, as Lenders and JPMorgan Chase Bank, N.A., as Administrative Agent. (File No. 001-16169, Form 8-K dated June 4, 2014, Exhibit
10.2).
Amendment No. 4 to Credit Agreement, dated May 30, 2014, among Exelon Generation Company, LLC, as Borrower, the financial
institutions signatory therein, as Lenders and JPMorgan Chase Bank, N.A., as Administrative Agent. (File No. 001-16169, Form 8-K dated
June 4, 2014, Exhibit 10.3).
Amendment No. 3 to Credit Agreement, dated May 30, 2014, among PECO Energy Company, as Borrower, the financial institutions
signatory therein, as Lenders and JPMorgan Chase Bank, N.A., as Administrative Agent. (File No. 001-16169, Form 8-K dated June 4,
2014, Exhibit 10.4).
Amendment No. 2 to Credit Agreement, dated as of May 30, 2014, among Baltimore Gas and Electric Company, as Borrower, the financial
institutions signatory therein, as Lenders and The Royal Bank of Scotland plc, as Administrative Agent. (File No. 001-16169, Form 8-K dated
June 4, 2014, Exhibit 10.5).
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).
533
Table of Contents
Exhibit No.
10-72-2
10-72-3
10-72-4
10-73
10-74
10-75
10-76
10-77
10-78
10-79
10-80
10-81
10-82
Description
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)
Bondable Transition Property Servicing Agreement, dated as of December 19, 2002, between ACE Funding and ACE (File No. 333-59558,
Form 8-K dated December 23, 2002, Exhibit 10.2)
Purchase Agreement, dated as of April 20, 2010, by and among Pepco Holdings, Inc., Conectiv, LLC, Conectiv Energy Holding Company,
LLC and New Development Holdings, LLC (File No. 001-31403, Form 8-K dated July 8, 2010, Exhibit 2.1)
Purchase Agreement, dated March 9, 2015, among Potomac Electric Power Company and BNY Mellon Capital Markets, LLC, Morgan
Stanley & Co. LLC, and RBS Securities Inc., as representatives of the several underwriters named therein (File No. 001-01072, Form 8-K
dated March 10, 2015, Exhibit 1.1)
Purchase Agreement, May 4, 2015, among Delmarva Power & Light Company and J.P. Morgan Securities LLC, Merrill Lynch, Pierce,
Fenner & Smith Incorporated, and Scotia Capital (USA) Inc., as representatives of the several underwriters named therein (File No. 001-
01405, Form 8-K dated May 5, 2015, Exhibit 1.1)
Bond Purchase Agreement, dated December 1, 2015, among Atlantic City Electric Company and the purchasers signatory thereto (File No.
001-03559, Form 8-K dated December 2, 2015, Exhibit 1.1)
$300,000,000 Term Loan Agreement by and among PHI, The Bank of Nova Scotia, as Administrative Agent, and the lenders party thereto,
dated July 30, 2015 (File No. 001-31403, Form 8-K dated July 30, 2015, Exhibit 10)
First Amendment to Term Loan Agreement, dated as of October 29, 2015, by and among PHI, The Bank of Nova Scotia, as Administrative
Agent, and the lenders party thereto (File No. 001-31403, Form 8-K dated October 29, 2015, Exhibit 10.2)
$500,000,000 Term Loan Agreement by and among PHI, The Bank of Nova Scotia, as Administrative Agent, and the lenders party thereto,
dated January 13, 2016 (File No. 001-31403, Form 8-K dated January 14, 2016, Exhibit 10)
Second Amended and Restated Credit Agreement, dated as of August 1, 2011, by and among Pepco Holdings, Inc., Potomac Electric
Power Company, Delmarva Power & Light Company and Atlantic City Electric Company, the lenders party thereto, Wells Fargo Bank,
National Association, as agent, issuer and swingline lender, Bank of America, N.A., as syndication agent and issuer, The Royal Bank of
Scotland plc and Citicorp USA, Inc., as co-documentation agents, Wells Fargo Securities, LLC and Merrill Lynch, Pierce, Fenner and Smith
Incorporated, as active joint lead arrangers and joint book runners, and Citigroup Global Markets Inc. and RBS Securities, Inc. as passive
joint lead arrangers and joint book runners (File No. 001-31403, Form 10-Q dated August 3, 2011, Exhibit 10.1)
10-82-1
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)
534
Table of Contents
Exhibit No.
Description
10-82-2
10-82-3
10-82-4
10-83
10-83-1
10-83-2
10-84
10-85
10-86
10-87
10-88
10-89
10-90
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)
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)
10-91
2016 Form of Exelon Corporation Change in Control Agreement (File No. 001-16169, Form 10-Q dated October 26, 2016, Exhibit 10.1)
535
Table of Contents
Exhibit No.
Description
10-92
10-93
10-94
10-95
10-96
10-97
10-98
10-99
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
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.)
Form of Separation Agreement under Exelon Corporation Senior Management Severance Plan (As Amended and Restated Effective
November 1, 2015) (File No. 001-16169, Form 10-Q dated May 3, 2018, Exhibit 10.1)
Purchase Agreement, dated June 8, 2018 among Delmarva Power & Light Company and the purchasers signatory thereto (File No. 001-
01405, Form 8-K dated June 21, 2018, Exhibit 1.1)
Purchase Agreement, dated June 8, 2018, among Potomac Electric Power Company and the purchasers signatory thereto (File No. 001-
01072, Form 8-K dated June 21, 2018, Exhibit 1.1)
Letter Agreement, dated May 7, 2018, between Exelon Corporation and Denis P. O’Brien (File No. 001-16169, Form 10-Q dated August 2,
2018, Exhibit 10.3)
Letter Agreement, dated May 7, 2018, between Exelon Corporation and Jonathan W. Thayer (File No. 001-16169, Form 10-Q dated August
2, 2018, Exhibit 10.4)
Exelon 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
536
Table of Contents
Exhibit No.
23-6
Description
Potomac Electric Power Company
23-7
23-8
24-1
24-2
24-3
24-4
24-5
24-6
24-7
24-8
24-9
24-10
24-11
24-12
24-13
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
Delmarva Power & Light Company
Atlantic City Electric Company
Power of Attorney (Exelon Corporation)
Anthony K. Anderson
Ann C. Berzin
Laurie Brlas
Christopher M. Crane
Yves C. de Balmann
Nicholas DeBenedictis
Linda P. Jojo
Paul Joskow
Robert J. Lawless
Richard W. Mies
John W. Rogers, Jr.
Mayo A. Shattuck III
Stephen D. Steinour
John F. Young
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
Anne R. Pramaggiore
Reserved.
Reserved.
Power of Attorney (PECO Energy Company)
Christopher M. Crane
M. Walter D’Alessio
Nicholas DeBenedictis
537
Table of Contents
Exhibit No.
24-28
24-29
24-30
24-31
24-32
24-33
24-34
24-35
24-36
24-37
24-38
24-39
24-40
24-41
24-42
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
Description
Nelson A. Diaz
John S. Grady
Rosemarie B. Greco
Michael A. Innocenzo
Charisse R. Lillie
Anne R. Pramaggiore
Power of Attorney (Baltimore Gas and Electric Company)
Ann C. Berzin
Calvin G. Butler, Jr.
Christopher M. Crane
Michael E. Cryor
James R. Curtiss
Joseph Haskins, Jr.
Anne R. Pramaggiore
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
Anne R. Pramaggiore
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
Anne R. Pramaggiore
David M. Velazquez
Power of Attorney (Delmarva Power & Light Company)
24-57
Anne R. Pramaggiore
538
Table of Contents
Exhibit No.
24-58
Description
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
31-5
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 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 Calvin G. Butler, Jr. 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:
Exhibit No.
32-1
Description
Filed by Christopher M. Crane for Exelon Corporation
32-2
32-3
32-4
32-5
32-6
32-7
32-8
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
539
Table of Contents
Exhibit No.
32-9
Description
Filed by Calvin G. Butler, Jr. for Baltimore Gas and Electric Company
32-10
32-11
32-12
32-13
32-14
32-15
32-16
32-17
32-18
Filed by David M. Vahos for Baltimore Gas and Electric Company
Filed by David M. Velazquez for Pepco Holdings LLC
Filed by Phillip S. Barnett for Pepco Holdings LLC
Filed by David M. Velazquez for Potomac Electric Power Company
Filed by Phillip S. Barnett for Potomac Electric Power Company
Filed by David M. Velazquez for Delmarva Power & Light Company
Filed by Phillip S. Barnett for Delmarva Power & Light Company
Filed by David M. Velazquez for Atlantic City Electric Company
Filed by Phillip S. Barnett for Atlantic City Electric Company
101.INS
XBRL Instance
101.SCH
XBRL Taxonomy Extension Schema
101.CAL
XBRL Taxonomy Extension Calculation
101.DEF
XBRL Taxonomy Extension Definition
101.LAB
XBRL Taxonomy Extension Labels
101.PRE
XBRL Taxonomy Extension Presentation
__________
*
Compensatory plan or arrangements in which directors or officers of the applicable registrant participate and which are not available to all employees.
(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.
540
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.
541
Table of Contents
SIGNATURES
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 8th day of February, 2019 .
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 8th day of February, 2019 .
Signature
Title
/s/ CHRISTOPHER M. CRANE
Christopher M. Crane
/s/ JOSEPH NIGRO
Joseph Nigro
/s/ FABIAN E. SOUZA
Fabian E. Souza
President and 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
Christopher M. Crane
Yves C. de Balmann
Nicholas DeBenedictis
Linda P. Jojo
By:
Name:
/s/ THOMAS S. O'NEILL
Thomas S. O'Neill
Paul L. Joskow
Robert J. Lawless
Richard W. Mies
John W. Rogers, Jr.
Mayo A. Shattuck III
Stephen D. Steinour
John F. Young
542
February 8, 2019
Table of Contents
SIGNATURES
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 8th day of February, 2019 .
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 8th day of February, 2019 .
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)
543
Table of Contents
SIGNATURES
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 8th day of February, 2019 .
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 8th day of February, 2019 .
Signature
Title
/s/ JOSEPH DOMINGUEZ
Joseph Dominguez
/s/ JEANNE M. JONES
Jeanne M. Jones
/s/ GERALD J. KOZEL
Gerald J. Kozel
/s/ CHRISTOPHER M. CRANE
Christopher M. Crane
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)
Chairman and Director
This annual report has also been signed below by Joseph Dominguez, Attorney-in-Fact, on behalf of the following Directors on the date indicated:
James W. Compton
Christopher M. Crane
A. Steven Crown
Nicholas DeBenedictis
Peter V. Fazio, Jr.
Michael H. Moskow
Anne R. Pramaggiore
By:
Name:
/s/ JOSEPH DOMINGUEZ
Joseph Dominguez
February 8, 2019
544
Table of Contents
SIGNATURES
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 8th day of February, 2019 .
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 8th day of February, 2019 .
Signature
Title
/s/ MICHAEL A. INNOCENZO
Michael A. Innocenzo
/s/ ROBERT J. STEFANI
Robert J. Stefani
/s/ SCOTT A. BAILEY
Scott A. Bailey
/s/ CHRISTOPHER M. CRANE
Christopher M. Crane
President and 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)
Chairman and Director
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:
Christopher M. Crane
M. Walter D’Alessio
Nicholas DeBenedictis
Nelson A. Diaz
By:
Name:
/s/ MICHAEL A. INNOCENZO
Michael A. Innocenzo
John S. Grady
Rosemarie B. Greco
Charisse R. Lillie
Anne R. Pramaggiore
545
February 8, 2019
Table of Contents
SIGNATURES
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 8th day of February, 2019 .
BALTIMORE GAS AND ELECTRIC COMPANY
By:
/s/ CALVIN G. BUTLER, JR.
Name:
Calvin G. Butler, Jr.
Title:
Chief Executive Officer
Pursuant to the requirements of the Securities Exchange Act of 1934, this report has been signed by the following persons on behalf of the Registrant and in the
capacities indicated on the 8th day of February, 2019 .
Signature
Title
/s/ CALVIN G. BUTLER, JR.
Calvin G. Butler, Jr.
/s/ DAVID M. VAHOS
David M. Vahos
/s/ ANDREW W. HOLMES
Andrew W. Holmes
/s/ CHRISTOPHER M. CRANE
Christopher M. Crane
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)
Chairman and Director
This annual report has also been signed below by Calvin G. Butler, Jr., Attorney-in-Fact, on behalf of the following Directors on the date indicated:
Ann C. Berzin
Christopher M. Crane
Michael E. Cryor
James R. Curtiss
By:
Name:
/s/ CALVIN G. BUTLER, JR.
Calvin G. Butler, Jr.
Joseph Haskins, Jr.
Anne R. Pramaggiore
Michael D. Sullivan
Maria Harris Tildon
546
February 8, 2019
Table of Contents
SIGNATURES
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 8th day of February, 2019 .
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 8th day of February, 2019 .
Signature
Title
/s/ DAVID M. VELAZQUEZ
David M. Velazquez
President and Chief Executive Officer (Principal Executive Officer)
/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
/s/ CHRISTOPHER M. CRANE
Christopher M. Crane
Vice President and Controller (Principal Accounting Officer)
Chairman and Director
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:
Christopher M. Crane
Linda W. Cropp
Michael E. Cryor
By:
Name:
/s/ DAVID M. VELAZQUEZ
David M. Velazquez
Ernest Dianastasis
Debra P. DiLorenzo
Anne R. Pramaggiore
547
February 8, 2019
Table of Contents
SIGNATURES
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 8th day of February, 2019 .
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 8th day of February, 2019 .
Signature
Title
/s/ DAVID M. VELAZQUEZ
David M. Velazquez
/s/ PHILLIP S. BARNETT
Phillip S. Barnett
/s/ ROBERT M. AIKEN
Robert M. Aiken
/s/ CHRISTOPHER M. CRANE
Christopher M. Crane
President and Chief Executive Officer (Principal Executive Officer)
Senior Vice President, Chief Financial Officer and Treasurer (Principal
Financial Officer)
Vice President and Controller (Principal Accounting Officer)
Chairman
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
Christopher M. Crane
By:
Name:
/s/ DAVID M. VELAZQUEZ
David M. Velazquez
Melissa A. Lavinson
Kevin M. McGowan
Anne R. Pramaggiore
548
February 8, 2019
Table of Contents
SIGNATURES
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 8th day of February, 2019 .
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 8th day of February, 2019 .
Signature
Title
/s/ DAVID M. VELAZQUEZ
David M. Velazquez
/s/ PHILLIP S. BARNETT
Phillip S. Barnett
/s/ ROBERT M. AIKEN
Robert M. Aiken
/s/ CHRISTOPHER M. CRANE
Christopher M. Crane
President and Chief Executive Officer (Principal Executive Officer)
Senior Vice President, Chief Financial Officer and Treasurer (Principal
Financial Officer)
Vice President and Controller (Principal Accounting Officer)
Chairman
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:
Anne R. Pramaggiore
By:
Name:
/s/ DAVID M. VELAZQUEZ
David M. Velazquez
February 8, 2019
549
Table of Contents
SIGNATURES
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 8th day of February, 2019 .
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 8th day of February, 2019 .
Signature
Title
/s/ DAVID M. VELAZQUEZ
David M. Velazquez
/s/ PHILLIP S. BARNETT
Phillip S. Barnett
/s/ ROBERT M. AIKEN
Robert M. Aiken
/s/ CHRISTOPHER M. CRANE
Christopher M. Crane
President and Chief Executive Officer (Principal Executive Officer)
Senior Vice President, Chief Financial Officer and Treasurer (Principal
Financial Officer)
Vice President and Controller (Principal Accounting Officer)
Chairman
550
Exhibit 21.1
Exelon Corporation (50% and Greater)
12/31/2018
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
Butter Creek Power, 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
Oregon
1
Exhibit 21.1
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
CNE Gas Supply, LLC
CNEG Holdings, LLC
CNEGH Holdings, LLC
CoLa Resources LLC
Colorado Bend II Power, LLC
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
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 ESCO, 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, LLC
3
Delaware
Delaware
Illinois
Indiana
Delaware
Delaware
Delaware
Delaware
Delaware
Delaware
Delaware
Delaware
Delaware
Ontario
Delaware
Delaware
Maryland
Delaware
Delaware
Delaware
Delaware
Maryland
Delaware
Delaware
Kentucky
Delaware
Delaware
Delaware
Maryland
Maryland
Delaware
Delaware
Delaware
Delaware
Delaware
Delaware
Delaware
Georgia
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
Delaware Operating Services Company, LLC
Delmarva Power & Light Company
Denver Airport Solar, LLC
Distributed Generation Partners, LLC
Distrigas of Massachusetts LLC
Eastern Landfill Gas, LLC
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
Exelon FitzPatrick, LLC
Exelon Framingham, 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 & Virginia
Delaware
Delaware
Delaware
Delaware
Delaware
Pennsylvania
New Brunswick
Delaware
Minnesota
Delaware
Delaware
Delaware
Delaware
Pennsylvania
Delaware
Delaware
4
Exhibit 21.1
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 10, LLC
Exelon Wind 11, LLC
Exelon Wind 2, LLC
Exelon Wind 3, LLC
Exelon Wind 4, LLC
Exelon Wind 5, LLC
Exelon Wind 6, LLC
Exelon Wind 7, LLC
Exelon Wind 8, LLC
Exelon Wind 9, 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
Delaware
Delaware
Pennsylvania
Nevada
Delaware
United Kingdom
Delaware
Delaware
Delaware
Delaware
Delaware
Delaware
Delaware
Delaware
Pennsylvania
Delaware
Delaware
Delaware
Delaware
Delaware
Texas
Texas
Texas
Texas
Texas
Texas
Texas
Texas
Texas
Texas
Texas
Canada
Delaware
Delaware
Delaware
New York
Delaware
Mexico
Delaware
Delaware
Delaware
5
Exhibit 21.1
ExGen Renewables I Holding, LLC
ExGen Renewables I, LLC
ExGen Renewables II, LLC
ExGen Renewables IV Holding, LLC
ExGen Renewables IV, LLC
ExGen Renewables Partners, LLC
ExGen Texas II Power Holdings, LLC
ExGen Texas II Power, LLC
ExGen Texas Power Services, LLC
ExGen Ventures International Holdings II Limited
ExGen Ventures International Holdings Limited
ExTel Corporation, LLC
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
Marshall Wind 1, LLC
Marshall Wind 2, LLC
Marshall Wind 3, LLC
Marshall Wind 4, LLC
Delaware
Delaware
Delaware
Delaware
Delaware
Delaware
Delaware
Delaware
Delaware
United Kingdom
United Kingdom
Delaware
Delaware
Delaware
Delaware
Delaware
Oregon
Oregon
Maryland
Virgin Islands, U.S.
Delaware
Alberta
Delaware
Maryland
Delaware
Michigan
Idaho
Texas
Delaware
Idaho
Delaware
Japan
Minnesota
Minnesota
Minnesota
Delaware
Missouri
Minnesota
Minnesota
Minnesota
Minnesota
6
Marshall Wind 5, LLC
Marshall Wind 6, 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
Minnesota
Minnesota
Delaware
Delaware
Delaware
Delaware
Wisconsin
Arizona
Maryland
Delaware
Delaware
Northwind Thermal Technologies Canada Inc.
New Brunswick
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.
PCI Engine Trading Ltd.
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 Contruction, 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
Oregon
Oregon
Oregon
Delaware
Delaware
Delaware
Nevada
Delaware
Bermuda
Pennsylvania
Delaware
Delaware
Delaware
Delaware
Pennsylvania
Delaware
California
Delaware
Delaware
Delaware
Delaware
Delaware
California
Delaware
Delaware
Delaware
Delaware
Delaware
Delaware
7
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
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
Vineland Cogeneration Limited Partnership
Exhibit 21.1
Delaware
Delaware
Colorado
Delaware
Delaware
Delaware
District of Columbia & Virginia
Delaware
Delaware
Minnesota
Maryland
Delaware
Delaware
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
8
Exhibit 21.1
Vineland General, Inc.
Vineland Ltd., Inc.
Volta SPV CMX, 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
Western Path Development, LLC
Whitetail Wind Energy, LLC
Wildcat Finance, LLC
Wildcat Wind LLC
Wind Capital Holdings, LLC
Wolf Hollow II Power, LLC
Wolf Hollow Services, LLC
Delaware
Delaware
Delaware
Delaware
Oregon
Delaware
Delaware
Oregon
Delaware
Delaware
Delaware
Delaware
New Mexico
Missouri
Delaware
Delaware
9
Exhibit 21.2
Exelon Generation Company, LLC (50% and Greater)
12/31/2018
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
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
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
Oregon
Delaware
Delaware
Delaware
Maryland
Idaho
Idaho
Maryland
Delaware
Exhibit 21.2
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
CNE Gas Supply, 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
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
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 ESCO, 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, 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
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
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
Delaware Operating Services Company, LLC
Denver Airport Solar, LLC
Distributed Generation Partners, LLC
Distrigas of Massachusetts LLC
Eastern Landfill Gas, 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 10, LLC
Exelon Wind 11, LLC
Exelon Wind 2, LLC
Exelon Wind 3, LLC
Exelon Wind 4, LLC
Exelon Wind 5, LLC
Exelon Wind 6, LLC
Exelon Wind 7, LLC
Maryland
Maryland
Missouri
Maryland
Minnesota
Missouri
Delaware
Delaware
Delaware
Delaware
Delaware
Delaware
Pennsylvania
Delaware
Minnesota
Delaware
Delaware
Delaware
Delaware
Delaware
Delaware
Nevada
Delaware
United Kingdom
Delaware
Delaware
Delaware
Delaware
Pennsylvania
Delaware
Delaware
Delaware
Texas
Texas
Texas
Texas
Texas
Texas
Texas
Texas
Texas
4
Exelon Wind 8, LLC
Exelon Wind 9, LLC
Exelon Wind Canada Inc.
Exelon Wind, LLC
Exelon Wyman, LLC
ExGen Energy, S. de R.L. de C.V.
ExGen Handley Power, LLC
ExGen Renewables Holdings II, LLC
ExGen Renewables Holdings, LLC
ExGen Renewables I Holding, LLC
ExGen Renewables I, LLC
ExGen Renewables II, LLC
ExGen Renewables IV Holding, LLC
ExGen Renewables IV, LLC
ExGen Renewables Partners, LLC
ExGen Texas II Power Holdings, LLC
ExGen Texas II Power, LLC
ExGen Texas Power Services, LLC
Exhibit 21.2
Texas
Texas
Canada
Delaware
Delaware
Mexico
Delaware
Delaware
Delaware
Delaware
Delaware
Delaware
Delaware
Delaware
Delaware
Delaware
Delaware
Delaware
ExGen Ventures International Holdings II Limited
ExGen Ventures International Holdings Limited
United Kingdom
United Kingdom
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
Delaware
Delaware
Oregon
Oregon
Maryland
Delaware
Alberta
Delaware
Maryland
Delaware
Michigan
Idaho
Texas
Delaware
Idaho
Delaware
Japan
Minnesota
Minnesota
Minnesota
Delaware
5
Exhibit 21.2
Loess Hills Wind Farm, LLC
Marshall Wind 1, LLC
Marshall Wind 2, LLC
Marshall Wind 3, LLC
Marshall Wind 4, LLC
Marshall Wind 5, LLC
Marshall Wind 6, 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
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
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
6
Missouri
Minnesota
Minnesota
Minnesota
Minnesota
Minnesota
Minnesota
Delaware
Delaware
Delaware
Wisconsin
Arizona
Maryland
Delaware
Delaware
Oregon
Oregon
Oregon
Delaware
Delaware
California
Delaware
Delaware
Delaware
Delaware
California
Delaware
Delaware
Delaware
Delaware
Delaware
Delaware
Colorado
Delaware
Minnesota
Maryland
Delaware
Delaware
Delaware
Delaware
Oregon
Exhibit 21.2
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
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
Delaware
Delaware
Delaware
Delaware
Delaware
Delaware
Delaware
Delaware
Delaware
Delaware
Delaware
Delaware
Oregon
Delaware
Idaho
Delaware
Delaware
Delaware
Delaware
Oregon
Oregon
Delaware
Delaware
Delaware
New Mexico
Missouri
Delaware
Delaware
7
Exhibit 21.3
Commonwealth Edison Company (50% and Greater)
12/31/2018
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)
12/31/2018
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)
12/31/2018
Subsidiary
None
Jurisdiction
Exhibit 21.5
Pepco Holdings LLC (50% and Greater)
12/31/2018
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)
12/31/2018
Subsidiary
POM Holdings, Inc.
Jurisdiction
Delaware
Exhibit 21.7
Delmarva Power & Light Company
12/31/2018
Subsidiary
N/A
Exhibit 21.8
Jurisdiction
Atlantic City Electric Company (50% and Greater)
12/31/2018
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. 333-213383 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 8, 2019 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 8, 2019
CONSENT OF INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM
We hereby consent to the incorporation by reference in the Registration Statements on Form S-3 (No. 333-213383-06) and Form S-4 (No. 333-
184712) of Exelon Generation Company, LLC of our report dated February 8, 2019 relating to the financial statements, financial statement schedule
and the effectiveness of internal control over financial reporting, which appears in this Form 10-K.
Exhibit 23.2
/s/ PricewaterhouseCoopers LLP
Baltimore, Maryland
February 8, 2019
CONSENT OF INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM
We hereby consent to the incorporation by reference in the Registration Statement on Form S-3 (No. 333-213383-05) of Commonwealth Edison
Company of our report dated February 8, 2019 relating to the financial statements, financial statement schedule and the effectiveness of internal
control over financial reporting, which appears in this Form 10-K.
Exhibit 23.3
/s/ PricewaterhouseCoopers LLP
Chicago, Illinois
February 8, 2019
CONSENT OF INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM
We hereby consent to the incorporation by reference in the Registration Statement on Form S-3 (No. 333-213383-04) of PECO Energy Company of
our report dated February 8, 2019 relating to the financial statements, financial statement schedule and the effectiveness of internal control over
financial reporting, which appears in this Form 10-K.
Exhibit 23.4
/s/ PricewaterhouseCoopers LLP
Philadelphia, Pennsylvania
February 8, 2019
CONSENT OF INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM
We hereby consent to the incorporation by reference in the Registration Statement on Form S-3 (No. 333-213383-03) of Baltimore Gas and Electric
Company of our report dated February 8, 2019 relating to the financial statements, financial statement schedule and the effectiveness of internal
control over financial reporting, which appears in this Form 10-K.
Exhibit 23.5
/s/ PricewaterhouseCoopers LLP
Baltimore, Maryland
February 8, 2019
CONSENT OF INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM
We hereby consent to the incorporation by reference in the Registration Statement on Form S-3 (No. 333-213383-02) of Potomac Electric Power
Company of our report dated February 8, 2019 , 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 8, 2019
CONSENT OF INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM
We hereby consent to the incorporation by reference in the Registration Statement on Form S-3 (No. 333-213383-01) of Delmarva Power & Light
Company of our report dated February 8, 2019 , 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 8, 2019
CONSENT OF INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM
We hereby consent to the incorporation by reference in the Registration Statement on Form S-3 (No. 333-213383-07) of Atlantic City Electric
Company of our report dated February 8, 2019 , 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 8, 2019
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 2018 of Exelon Corporation,
together with any amendments thereto, to be filed with the Securities and Exchange Commission, and generally to do and perform all things necessary to be
done in the premises as fully and effectually in all respects as I could do if personally present.
POWER OF ATTORNEY
Exhibit 24.1
/s/ ANTHONY K. ANDERSON
Anthony K. Anderson
DATE: February 5, 2019
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 2018 of Exelon Corporation, together
with any amendments thereto, to be filed with the Securities and Exchange Commission, and generally to do and perform all things necessary to be done in the
premises as fully and effectually in all respects as I could do if personally present.
/s/ ANN C. BERZIN
Ann C. Berzin
DATE: February 5, 2019
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 2018 of Exelon Corporation, together
with any amendments thereto, to be filed with the Securities and Exchange Commission, and generally to do and perform all things necessary to be done in the
premises as fully and effectually in all respects as I could do if personally present.
/s/ LAURIE BRLAS
Laurie Brlas
DATE: February 5, 2019
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 2018 of Exelon Corporation, together with any amendments thereto, to
be filed with the Securities and Exchange Commission, and generally to do and perform all things necessary to be done in the premises as fully and effectually
in all respects as I could do if personally present.
/s/ CHRISTOPHER M. CRANE
Christopher M. Crane
DATE: February 1, 2019
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 2018 of Exelon Corporation,
together with any amendments thereto, to be filed with the Securities and Exchange Commission, and generally to do and perform all things necessary to be
done in the premises as fully and effectually in all respects as I could do if personally present.
/s/ YVES C. DE BALMANN
Yves C. de Balmann
DATE: February 5, 2019
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 2018 of Exelon Corporation,
together with any amendments thereto, to be filed with the Securities and Exchange Commission, and generally to do and perform all things necessary to be
done in the premises as fully and effectually in all respects as I could do if personally present.
/s/ NICHOLAS DEBENEDICTIS
Nicholas DeBenedictis
DATE: February 5, 2019
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 2018 of Exelon Corporation, together
with any amendments thereto, to be filed with the Securities and Exchange Commission, and generally to do and perform all things necessary to be done in the
premises as fully and effectually in all respects as I could do if personally present.
/s/ LINDA P. JOJO
Linda P. Jojo
DATE: February 5, 2019
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 2018 of Exelon Corporation, together
with any amendments thereto, to be filed with the Securities and Exchange Commission, and generally to do and perform all things necessary to be done in the
premises as fully and effectually in all respects as I could do if personally present.
/s/ PAUL L. JOSKOW
Paul L. Joskow
DATE: February 5, 2019
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 2018 of Exelon Corporation,
together with any amendments thereto, to be filed with the Securities and Exchange Commission, and generally to do and perform all things necessary to be
done in the premises as fully and effectually in all respects as I could do if personally present.
/s/ ROBERT J. LAWLESS
Robert J. Lawless
DATE: February 5, 2019
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 2018 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: February 5, 2019
POWER OF ATTORNEY
Exhibit 24.11
KNOW ALL MEN BY THESE PRESENTS that I, John W. Rogers, Jr. , 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 2018 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 W. ROGERS, JR.
John W. Rogers, Jr.
DATE: February 5, 2019
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 2018 of Exelon Corporation,
together with any amendments thereto, to be filed with the Securities and Exchange Commission, and generally to do and perform all things necessary to be
done in the premises as fully and effectually in all respects as I could do if personally present.
/s/ MAYO A. SHATTUCK III
Mayo A. Shattuck III
DATE: February 5, 2019
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 2018 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: February 5, 2019
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 2018 of Exelon Corporation, together
with any amendments thereto, to be filed with the Securities and Exchange Commission, and generally to do and perform all things necessary to be done in the
premises as fully and effectually in all respects as I could do if personally present.
/s/ JOHN F. YOUNG
John F. Young
DATE: February 5, 2019
POWER OF ATTORNEY
Exhibit 24.15
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 2018 of Commonwealth Edison
Company, together with any amendments thereto, to be filed with the Securities and Exchange Commission, and generally to do and perform all things
necessary to be done in the premises as fully and effectually in all respects as I could do if personally present.
/s/ JAMES W. COMPTON
James W. Compton
DATE: February 1, 2019
POWER OF ATTORNEY
Exhibit 24.16
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 2018 of Commonwealth
Edison Company, together with any amendments thereto, to be filed with the Securities and Exchange Commission, and generally to do and perform all things
necessary to be done in the premises as fully and effectually in all respects as I could do if personally present.
/s/ CHRISTOPHER M. CRANE
Christopher M. Crane
DATE: February 5, 2019
POWER OF ATTORNEY
Exhibit 24.17
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 2018 of Commonwealth Edison
Company, together with any amendments thereto, to be filed with the Securities and Exchange Commission, and generally to do and perform all things
necessary to be done in the premises as fully and effectually in all respects as I could do if personally present.
/s/ A. STEVEN CROWN
A. Steven Crown
DATE: February 1, 2019
POWER OF ATTORNEY
Exhibit 24.18
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 2018 of Commonwealth
Edison Company, together with any amendments thereto, to be filed with the Securities and Exchange Commission, and generally to do and perform all things
necessary to be done in the premises as fully and effectually in all respects as I could do if personally present.
/s/ NICHOLAS DEBENEDICTIS
Nicholas DeBenedictis
DATE: February 5, 2019
POWER OF ATTORNEY
Exhibit 24.19
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 2018 of Commonwealth Edison Company, together with any
amendments thereto, to be filed with the Securities and Exchange Commission, and generally to do and perform all things necessary to be done in the
premises as fully and effectually in all respects as I could do if personally present.
/s/ JOSEPH DOMINGUEZ
Joseph Dominguez
DATE: February 1, 2019
POWER OF ATTORNEY
Exhibit 24.20
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 2018 of Commonwealth Edison
Company, together with any amendments thereto, to be filed with the Securities and Exchange Commission, and generally to do and perform all things
necessary to be done in the premises as fully and effectually in all respects as I could do if personally present.
/s/ PETER V. FAZIO, JR.
Peter V. Fazio, Jr.
DATE: February 7, 2019
POWER OF ATTORNEY
Exhibit 24.21
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 2018 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 1, 2019
POWER OF ATTORNEY
Exhibit 24.22
KNOW ALL MEN BY THESE PRESENTS that I, Anne R. Pramaggiore , 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 2018 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/ ANNE R. PRAMAGGIORE
Anne R. Pramaggiore
DATE: February 1, 2019
POWER OF ATTORNEY
Exhibit 24.25
KNOW ALL MEN BY THESE PRESENTS that I, Christopher M. Crane , do hereby appoint Michael A. Innocenzo and Romulo L. Diaz, Jr., or either of them,
attorney for me and in my name and on my behalf to sign the annual Securities and Exchange Commission report on Form 10-K for 2018 of PECO Energy
Company, together with any amendments thereto, to be filed with the Securities and Exchange Commission, and generally to do and perform all things
necessary to be done in the premises as fully and effectually in all respects as I could do if personally present.
/s/ CHRISTOPHER M. CRANE
Christopher M. Crane
DATE: February 1, 2019
POWER OF ATTORNEY
Exhibit 24.26
KNOW ALL MEN BY THESE PRESENTS that I, M. Walter D’Alessio , do hereby appoint Michael A. Innocenzo and Romulo L. Diaz, Jr., or either of them,
attorney for me and in my name and on my behalf to sign the annual Securities and Exchange Commission report on Form 10-K for 2018 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/ M. WALTER D’ALESSIO
M. Walter D’Alessio
DATE: February 4, 2019
POWER OF ATTORNEY
Exhibit 24.27
KNOW ALL MEN BY THESE PRESENTS that I, Nicholas DeBenedictis , do hereby appoint Michael A. Innocenzo and Romulo L. Diaz, Jr., or either of them,
attorney for me and in my name and on my behalf to sign the annual Securities and Exchange Commission report on Form 10-K for 2018 of PECO Energy
Company, together with any amendments thereto, to be filed with the Securities and Exchange Commission, and generally to do and perform all things
necessary to be done in the premises as fully and effectually in all respects as I could do if personally present.
/s/ NICHOLAS DEBENEDICTIS
Nicholas DeBenedictis
DATE: February 5, 2019
POWER OF ATTORNEY
Exhibit 24.28
KNOW ALL MEN BY THESE PRESENTS that I, Nelson A. Diaz , do hereby appoint Michael A. Innocenzo and Romulo L. Diaz, Jr., or either of them, attorney
for me and in my name and on my behalf to sign the annual Securities and Exchange Commission report on Form 10-K for 2018 of PECO Energy Company,
together with any amendments thereto, to be filed with the Securities and Exchange Commission, and generally to do and perform all things necessary to be
done in the premises as fully and effectually in all respects as I could do if personally present.
/s/ NELSON A. DIAZ
Nelson A. Diaz
DATE: February 4, 2019
POWER OF ATTORNEY
Exhibit 24.29
KNOW ALL MEN BY THESE PRESENTS that I, John S. Grady , do hereby appoint Michael A. Innocenzo and Romulo L. Diaz, Jr., or either of them, attorney
for me and in my name and on my behalf to sign the annual Securities and Exchange Commission report on Form 10-K for 2018 of PECO Energy Company,
together with any amendments thereto, to be filed with the Securities and Exchange Commission, and generally to do and perform all things necessary to be
done in the premises as fully and effectually in all respects as I could do if personally present.
/s/ JOHN S. GRADY
John S. Grady
DATE: February 4, 2019
POWER OF ATTORNEY
Exhibit 24.30
KNOW ALL MEN BY THESE PRESENTS that I, Rosemarie B. Greco , do hereby appoint Michael A. Innocenzo and Romulo L. Diaz, Jr., or either of them,
attorney for me and in my name and on my behalf to sign the annual Securities and Exchange Commission report on Form 10-K for 2018 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 1, 2019
KNOW ALL MEN BY THESE PRESENTS that I, Michael A. Innocenzo , do hereby appoint Romulo L. Diaz, Jr. 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 2018 of PECO Energy Company, together with any amendments
thereto, to be filed with the Securities and Exchange Commission, and generally to do and perform all things necessary to be done in the premises as fully and
effectually in all respects as I could do if personally present.
POWER OF ATTORNEY
Exhibit 24.31
/s/ MICHAEL A. INNOCENZO
Michael A. Innocenzo
DATE: February 5, 2019
POWER OF ATTORNEY
Exhibit 24.32
KNOW ALL MEN BY THESE PRESENTS that I, Charisse R. Lillie , do hereby appoint Michael A. Innocenzo and Romulo L. Diaz, Jr., or either of them,
attorney for me and in my name and on my behalf to sign the annual Securities and Exchange Commission report on Form 10-K for 2018 of PECO Energy
Company, together with any amendments thereto, to be filed with the Securities and Exchange Commission, and generally to do and perform all things
necessary to be done in the premises as fully and effectually in all respects as I could do if personally present.
/s/ CHARISSE R. LILLIE
Charisse R. Lillie
DATE: February 1, 2019
POWER OF ATTORNEY
Exhibit 24.33
KNOW ALL MEN BY THESE PRESENTS that I, Anne R. Pramaggiore , do hereby appoint Michael A. Innocenzo and Romulo L. Diaz, Jr., or either of them,
attorney for me and in my name and on my behalf to sign the annual Securities and Exchange Commission report on Form 10-K for 2018 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/ ANNE R. PRAMAGGIORE
Anne. R. Pramaggiore
DATE: February 1, 2019
POWER OF ATTORNEY
Exhibit 24.34
KNOW ALL MEN BY THESE PRESENTS that I, Ann C. Berzin , do hereby appoint Calvin G. Butler, Jr. 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 2018 of Baltimore Gas & Electric Company,
together with any amendments thereto, to be filed with the Securities and Exchange Commission, and generally to do and perform all things necessary to be
done in the premises as fully and effectually in all respects as I could do if personally present.
/s/ ANN C. BERZIN
Ann C. Berzin
DATE: February 7, 2019
POWER OF ATTORNEY
Exhibit 24.35
KNOW ALL MEN BY THESE PRESENTS that I, Calvin G. Butler, Jr., 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 2018 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, JR.
Calvin G. Butler, Jr.
DATE: February 5, 2019
POWER OF ATTORNEY
Exhibit 24.36
KNOW ALL MEN BY THESE PRESENTS that I, Christopher M. Crane , do hereby appoint Calvin G. Butler, Jr. 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 2018 of Baltimore Gas & Electric
Company, together with any amendments thereto, to be filed with the Securities and Exchange Commission, and generally to do and perform all things
necessary to be done in the premises as fully and effectually in all respects as I could do if personally present.
/s/ CHRISTOPHER M. CRANE
Christopher M. Crane
DATE: February 1, 2019
POWER OF ATTORNEY
Exhibit 24.37
KNOW ALL MEN BY THESE PRESENTS that I, Michael E. Cryor , do hereby appoint Calvin G. Butler, Jr. 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 2018 of Baltimore Gas & Electric
Company, together with any amendments thereto, to be filed with the Securities and Exchange Commission, and generally to do and perform all things
necessary to be done in the premises as fully and effectually in all respects as I could do if personally present.
/s/ MICHAEL E. CRYOR
Michael E. Cryor
DATE: February 1, 2019
POWER OF ATTORNEY
Exhibit 24.38
KNOW ALL MEN BY THESE PRESENTS that I, James R. Curtiss , do hereby appoint Calvin G. Butler, Jr. 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 2018 of Baltimore Gas & Electric Company,
together with any amendments thereto, to be filed with the Securities and Exchange Commission, and generally to do and perform all things necessary to be
done in the premises as fully and effectually in all respects as I could do if personally present.
/s/ JAMES R. CURTISS
James R. Curtiss
DATE: February 1, 2019
POWER OF ATTORNEY
Exhibit 24.39
KNOW ALL MEN BY THESE PRESENTS that I, Joseph Haskins, Jr. , do hereby appoint Calvin G. Butler, Jr. 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 2018 of Baltimore Gas & Electric
Company, together with any amendments thereto, to be filed with the Securities and Exchange Commission, and generally to do and perform all things
necessary to be done in the premises as fully and effectually in all respects as I could do if personally present.
/s/ JOSEPH HASKINS, JR.
Joseph Haskins, Jr.
DATE: February 6, 2019
POWER OF ATTORNEY
Exhibit 24.40
KNOW ALL MEN BY THESE PRESENTS that I, Anne R. Pramaggiore , do hereby appoint Calvin G. Butler, Jr. 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 2018 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/ ANNE R. PRAMAGGIORE
Anne R. Pramaggiore
DATE: February 1, 2019
POWER OF ATTORNEY
Exhibit 24.41
KNOW ALL MEN BY THESE PRESENTS that I, Michael D. Sullivan , do hereby appoint Calvin G. Butler, Jr. 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 2018 of Baltimore Gas & Electric
Company, together with any amendments thereto, to be filed with the Securities and Exchange Commission, and generally to do and perform all things
necessary to be done in the premises as fully and effectually in all respects as I could do if personally present.
/s/ MICHAEL D. SULLIVAN
Michael D. Sullivan
DATE: February 8, 2019
POWER OF ATTORNEY
Exhibit 24.42
KNOW ALL MEN BY THESE PRESENTS that I, Maria Harris Tildon , do hereby appoint Calvin G. Butler, Jr. 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 2018 of Baltimore Gas & Electric
Company, together with any amendments thereto, to be filed with the Securities and Exchange Commission, and generally to do and perform all things
necessary to be done in the premises as fully and effectually in all respects as I could do if personally present.
/s/ MARIA HARRIS TILDON
Maria Harris Tildon
DATE: February 4, 2019
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 2018 of Pepco Holdings
LLC, together with any amendments thereto, to be filed with the Securities and Exchange Commission, and generally to do and perform all things necessary to
be done in the premises as fully and effectually in all respects as I could do if personally present.
/s/ CHRISTOPHER M. CRANE
Christopher M. Crane
Date: February 1, 2019
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 2018 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 7, 2018
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 2018 of Pepco Holdings LLC, together
with any amendments thereto, to be filed with the Securities and Exchange Commission, and generally to do and perform all things necessary to be done in the
premises as fully and effectually in all respects as I could do if personally present.
/s/ MICHAEL CRYOR
Michael Cryor
Date: February 1, 2019
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 2018 of Pepco Holdings LLC,
together with any amendments thereto, to be filed with the Securities and Exchange Commission, and generally to do and perform all things necessary to be
done in the premises as fully and effectually in all respects as I could do if personally present.
/s/ ERNEST DIANASTASIS
Ernest Dianastasis
Date: February 1, 2019
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 2018 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 4, 2019
POWER OF ATTORNEY
Exhibit 24.48
KNOW ALL MEN BY THESE PRESENTS that I, Anne R. Pramaggiore , 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 2018 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/ ANNE R. PRAMAGGIORE
Anne R. Pramaggiore
Date: February 1, 2019
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 2018 of Pepco Holdings LLC, together with any amendments thereto, to
be filed with the Securities and Exchange Commission, and generally to do and perform all things necessary to be done in the premises as fully and effectually
in all respects as I could do if personally present.
/s/ DAVID M. VELAZQUEZ
David M. Velazquez
DATE: February 5, 2019
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 2018 of Potomac Electric Power
Company, together with any amendments thereto, to be filed with the Securities and Exchange Commission, and generally to do and perform all things
necessary to be done in the premises as fully and effectually in all respects as I could do if personally present.
/s/ J. TYLER ANTHONY
J. Tyler Anthony
DATE: February 1, 2019
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 2018 of Potomac Electric Power
Company, together with any amendments thereto, to be filed with the Securities and Exchange Commission, and generally to do and perform all things
necessary to be done in the premises as fully and effectually in all respects as I could do if personally present.
/s/ PHILLIP S. BARNETT
Phillip S. Barnett
DATE: February 4, 2019
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 2018 of Potomac Electric
Power Company, together with any amendments thereto, to be filed with the Securities and Exchange Commission, and generally to do and perform all things
necessary to be done in the premises as fully and effectually in all respects as I could do if personally present.
/s/ CHRISTOPHER M. CRANE
Christopher M. Crane
DATE: February 1, 2019
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 2018 of Potomac
Electric Power Company, together with any amendments thereto, to be filed with the Securities and Exchange Commission, and generally to do and
perform all things necessary to be done in the premises as fully and effectually in all respects as I could do if personally present.
/s/ MELISSA A. LAVINSON
Melissa A. Lavinson
DATE: February 4, 2019
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 2018 of Potomac Electric Power
Company, together with any amendments thereto, to be filed with the Securities and Exchange Commission, and generally to do and perform all things
necessary to be done in the premises as fully and effectually in all respects as I could do if personally present.
/s/ KEVIN M. MCGOWAN
Kevin M. McGowan
DATE: February 4, 2019
POWER OF ATTORNEY
Exhibit 24.55
KNOW ALL MEN BY THESE PRESENTS that I, Anne R. Pramaggiore , 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 2018 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/ ANNE R. PRAMAGGIORE
Anne R. Pramaggiore
DATE: February 1, 2019
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 2018 of Potomac Electric Power Company, together with any amendments
thereto, to be filed with the Securities and Exchange Commission, and generally to do and perform all things necessary to be done in the premises as fully and
effectually in all respects as I could do if personally present.
/s/ DAVID M. VELAZQUEZ
David M. Velazquez
DATE: February 5, 2019
POWER OF ATTORNEY
Exhibit 24.57
KNOW ALL MEN BY THESE PRESENTS that I, Anne R. Pramaggiore , 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 2018 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/ ANNE R. PRAMAGGIORE
Anne R. Pramaggiore
DATE: February 1, 2019
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 2018 of Delmarva Power & Light Company, together with any
amendments thereto, to be filed with the Securities and Exchange Commission, and generally to do and perform all things necessary to be done in the premises
as fully and effectually in all respects as I could do if personally present.
/s/ DAVID M. VELAZQUEZ
David M. Velazquez
DATE: February 5, 2019
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 2018 of Atlantic City Electric Company, together with any amendments
thereto, to be filed with the Securities and Exchange Commission, and generally to do and perform all things necessary to be done in the premises as fully and
effectually in all respects as I could do if personally present.
/s/ DAVID M. VELAZQUEZ
David M. Velazquez
DATE: February 5, 2019
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 8, 2019
/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 8, 2019
/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 8, 2019
/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 8, 2019
/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 8, 2019
/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 8, 2019
/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 8, 2019
/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 8, 2019
/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, Calvin G. Butler, Jr., 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 8, 2019
/s/ CALVIN G. BUTLER, JR.
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 8, 2019
/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 8, 2019
/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 8, 2019
/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 8, 2019
/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 8, 2019
/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 8, 2019
/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 8, 2019
/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 8, 2019
/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 8, 2019
/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, 2018 , 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 8, 2019
/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, 2018 , 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 8, 2019
/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, 2018 , 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 8, 2019
/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, 2018 , 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 8, 2019
/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, 2018 , 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 8, 2019
/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, 2018 , 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 8, 2019
/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, 2018 , 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 8, 2019
/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, 2018 , 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 8, 2019
/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, 2018 ,
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 8, 2019
/s/ CALVIN G. BUTLER, JR.
Calvin G. Butler, Jr.
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, 2018 ,
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 8, 2019
/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, 2018 , 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 8, 2019
/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, 2018 , 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 8, 2019
/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, 2018 , 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 8, 2019
/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, 2018 , 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 8, 2019
/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, 2018 , 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 8, 2019
/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, 2018 , 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 8, 2019
/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, 2018 , 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 8, 2019
/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, 2018 , 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 8, 2019
/s/ PHILLIP S. BARNETT
Phillip S. Barnett
Senior Vice President, Chief Financial Officer and Treasurer