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UNITED STATES
SECURITIES AND EXCHANGE COMMISSION
WASHINGTON, D.C. 20549
FORM 10-K
☒ ANNUAL REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934
For the Fiscal Year Ended December 31, 2016
or
☐ TRANSITION REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934
Commission File
Number
1-16169
333-85496
1-1839
000-16844
1-1910
001-31403
001-01072
001-01405
001-03559
Name of Registrant; State or Other Jurisdiction of
Incorporation; Address of Principal Executive
Offices; and Telephone Number
EXELON CORPORATION
(a Pennsylvania corporation)
10 South Dearborn Street
P.O. Box 805379
Chicago, Illinois 60680-5379
(800) 483-3220
EXELON GENERATION COMPANY, LLC
(a Pennsylvania limited liability company)
300 Exelon Way
Kennett Square, Pennsylvania 19348-2473
(610) 765-5959
COMMONWEALTH EDISON COMPANY
(an Illinois corporation)
440 South LaSalle Street
Chicago, Illinois 60605-1028
(312) 394-4321
PECO ENERGY COMPANY
(a Pennsylvania corporation)
P.O. Box 8699
2301 Market Street
Philadelphia, Pennsylvania 19101-8699
(215) 841-4000
BALTIMORE GAS AND ELECTRIC COMPANY
(a Maryland corporation)
2 Center Plaza
110 West Fayette Street
Baltimore, Maryland 21201-3708
(410) 234-5000
PEPCO HOLDINGS LLC
(a Delaware limited liability company)
701 Ninth Street, N.W.
Washington, District of Columbia 20068
(202) 872-2000
POTOMAC ELECTRIC POWER COMPANY
(a District of Columbia and Virginia corporation)
701 Ninth Street, N.W.
Washington, District of Columbia 20068
(202) 872-2000
DELMARVA POWER & LIGHT COMPANY
(a Delaware and Virginia corporation)
500 North Wakefield Drive
Newark, Delaware 19702
(202) 872-2000
ATLANTIC CITY ELECTRIC COMPANY
(a New Jersey corporation)
500 North Wakefield Drive
Newark, Delaware 19702
(202) 872-2000
IRS Employer
Identification Number
23-2990190
23-3064219
36-0938600
23-0970240
52-0280210
52-2297449
53-0127880
51-0084283
21-0398280
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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
BALTIMORE GAS AND ELECTRIC COMPANY:
6.20% Trust Preferred Securities ($25 liquidation amount per preferred security) issued by BGE Capital Trust II, fully and
unconditionally guaranteed, by Baltimore Gas and Electric 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
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, $.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 ☒ No ☐
Yes ☒ No ☐
Yes ☒ No ☐
Yes ☒ No ☐
Yes ☒ No ☐
Yes ☒ No ☐
Yes ☐ No ☒
Yes ☐ No ☒
Yes ☐ No ☒
Yes ☐
Yes ☐
Yes ☐
Yes ☐
Yes ☐
Yes ☐
Yes ☐
Yes ☐
Yes ☐
No
☒
No
☒
No
☒
No
☒
No
☒
No
☒
No
☒
No
☒
No
☒
Indicate by check mark whether the registrants (1) have 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) have been subject to such filing
requirements for the past 90 days. Yes ☒ 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 ☒ 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. ☒
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Indicate by check mark whether the registrant is a large accelerated filer, an accelerated filer, non-accelerated filer, or a smaller reporting company. See
definition of “large accelerated filer,” “accelerated filer” and “smaller reporting 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
☒
Accelerated
Filer
Non-accelerated
Filer
Smaller Reporting
Company
☒
☒
☒
☒
☒
☒
☒
☒
Indicate by check mark whether the registrant is a shell company (as defined in Rule 12b-2 of the Act). Yes ☐ No ☒
The estimated aggregate market value of the voting and non-voting common equity held by nonaffiliates of each registrant as of June 30, 2016 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, 2017 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 Common Stock, $.01 par value
Delmarva Power & Light Company Common Stock, $2.25 par value
Atlantic City Electric Company Common Stock, $3.00 par value
$33,527,039,724
Not applicable
No established market
None
None
Not applicable
None
None
None
926,589,614
not applicable
127,017,157
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 2017 Annual Meeting of
Shareholders and the Commonwealth Edison Company 2017 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
TABLE OF CONTENTS
GLOSSARY OF TERMS AND ABBREVIATIONS
FILING FORMAT
FORWARD-LOOKING STATEMENTS
WHERE TO FIND MORE INFORMATION
PART I
ITEM 1.
ITEM 1A.
ITEM 1B.
ITEM 2.
ITEM 3.
ITEM 4.
PART II
ITEM 5.
BUSINESS
General
Exelon Generation Company, LLC
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
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
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
MINE SAFETY DISCLOSURES
MARKET FOR REGISTRANT’S COMMON EQUITY, RELATED STOCKHOLDER MATTERS AND ISSUER
ITEM 6.
SELECTED FINANCIAL DATA
PURCHASES OF EQUITY SECURITIES
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
Page No.
1
6
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ITEM 7.
MANAGEMENT’S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS
Atlantic City Electric Company
Exelon Corporation
Executive Overview
Financial Results of Operations
Significant 2016 Transactions and Developments
Exelon’s Strategy and Outlook for 2017 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
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
ITEM 7A.
QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK
Exelon Corporation
Exelon Generation Company, LLC
Commonwealth Edison Company
PECO Energy Company
Baltimore Gas and Electric Company
Pepco Holdings LLC
Potomac Electric Power Company
Delmarva Power & Light Company
Atlantic City Electric Company
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. Regulatory Matters
Page No.
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4. Mergers, Acquisitions, and Dispositions
5. Investment in Constellation Energy Nuclear Group, LLC
6. Accounts Receivable
7. Property, Plant and Equipment
8. Impairment of Long-Lived Assets
9. Early Nuclear Plant Retirements
10. Jointly Owned Electric Utility Plant
11. Intangible Assets
12. Fair Value of Financial Assets and Liabilities
13. Derivative Financial Instruments
14. Debt and Credit Agreements
15. Income Taxes
16. Asset Retirement Obligations
17. Retirement Benefits
18. Severance
19. Mezzanine Equity
20. Shareholders’ Equity
21. Stock-Based Compensation Plans
22. Earnings Per Share
23. Changes in Accumulated Other Comprehensive Income
24. Commitments and Contingencies
25. Supplemental Financial Information
26. Segment Information
27. Related Party Transactions
28. Quarterly Data
ITEM 9.
ITEM 9A.
CHANGES IN AND DISAGREEMENTS WITH ACCOUNTANTS ON ACCOUNTING AND FINANCIAL DISCLOSURE
CONTROLS AND PROCEDURES
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
OTHER INFORMATION
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
DIRECTORS, EXECUTIVE OFFICERS AND CORPORATE GOVERNANCE
EXECUTIVE COMPENSATION
SECURITY OWNERSHIP OF CERTAIN BENEFICIAL OWNERS AND MANAGEMENT AND RELATED
STOCKHOLDER MATTERS
ITEM 9B.
PART III
ITEM 10.
ITEM 11.
ITEM 12.
Page No.
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ITEM 13.
ITEM 14.
PART IV
ITEM 15.
ITEM 16.
SIGNATURES
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.
584
585
586
640
641
641
642
643
644
645
646
647
648
649
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Exelon Corporation and Related Entities
Exelon
Generation
ComEd
PECO
BGE
Pepco Holdings or PHI
Pepco
Pepco Energy Services or PES
PCI
DPL
ACE
BSC
PHISCO
Exelon Corporate
PHI Corporate
CENG
Constellation
Antelope Valley
Exelon Transmission Company
Exelon Wind
Ventures
EGTP
EGR
AmerGen
RPG
SolGen
BondCo
PEC L.P.
PECO Trust III
PECO Trust IV
PETT
ACE Funding or ATF
Registrants
Utility Registrants
Legacy PHI
ConEdison Solutions
GLOSSARY OF TERMS AND ABBREVIATIONS
Exelon Corporation
Exelon Generation Company, LLC
Commonwealth Edison Company
PECO Energy Company
Baltimore Gas and Electric Company
Pepco Holdings LLC (formerly Pepco Holdings, Inc.)
Potomac Electric Power Company
Pepco Energy Services, Inc. and its subsidiaries
Potomac Capital Investment Corporation and its subsidiaries
Delmarva Power & Light Company
Atlantic City Electric Company
Exelon Business Services Company, LLC
PHI Service Company
Exelon in its corporate capacity as a holding company
PHI in its corporate capacity as a holding company
Constellation Energy Nuclear Group, LLC
Constellation Energy Group, Inc.
Antelope Valley Solar Ranch One
Exelon Transmission Company, LLC
Exelon Wind, LLC and Exelon Generation Acquisition Company, LLC
Exelon Ventures Company, LLC
ExGen Texas Power, LLC
ExGen Renewables I, LLC
AmerGen Energy Company, LLC
Renewable Power Generation
SolGen, LLC
RSB BondCo LLC
PECO Energy Capital, L.P.
PECO Capital Trust III
PECO Energy Capital Trust IV
PECO Energy Transition Trust
Atlantic City Electric Transition Funding LLC
Exelon, Generation, ComEd, PECO, BGE, PHI, Pepco, DPL and ACE, collectively
ComEd, PECO, BGE, Pepco, DPL and ACE, collectively
PHI, Pepco, DPL and ACE, collectively
The competitive retail electricity and natural gas business of Consolidated Edison Solutions,
Inc., a subsidiary of Consolidated Edison, Inc
UII
Unicom Investments, Inc.
Other Terms and Abbreviations
1998 restructuring settlement
Act 11
Act 129
AEC
PECO’s 1998 settlement of its restructuring case mandated by the Competition Act
Pennsylvania Act 11 of 2012
Pennsylvania Act 129 of 2008
Alternative Energy Credit that is issued for each megawatt hour of generation from a qualified
alternative energy source
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Other Terms and Abbreviations
AEPS
AEPS Act
AESO
AFUDC
ALJ
AMI
AMP
AOCI
ARC
ARO
ARP
ARRA of 2009
ASC
BGS
Block contracts
CAIR
CAISO
CAMR
CERCLA
CES
CFL
Clean Air Act
Clean Water Act
Competition Act
Conectiv
Conectiv Energy
Contract EDCs
CPI
CPUC
CSAPR
CTA
CTC
D.C. Circuit Court
DCPSC
DC PLUG
Default Electricity Supply
Pennsylvania Alternative Energy Portfolio Standards
Pennsylvania Alternative Energy Portfolio Standards Act of 2004, as amended
Alberta Electric Systems Operator
Allowance for Funds Used During Construction
Administrative Law Judge
Advanced Metering Infrastructure
Advanced Metering Program
Accumulated Other Comprehensive Income
Asset Retirement Cost
Asset Retirement Obligation
Title IV Acid Rain Program
American Recovery and Reinvestment Act of 2009
Accounting Standards Codification
Basic Generation Service
Forward Purchase Energy Block Contracts
Clean Air Interstate Rule
California ISO
Federal Clean Air Mercury Rule
Comprehensive Environmental Response, Compensation and Liability Act of 1980, as amended
Clean Energy Standard
Compact Fluorescent Light
Clean Air Act of 1963, as amended
Federal Water Pollution Control Amendments of 1972, as amended
Pennsylvania Electricity Generation Customer Choice and Competition Act of 1996
Conectiv, LLC, a wholly owned subsidiary of PHI and the parent of DPL and ACE
Conectiv Energy Holdings, Inc. and substantially all of its subsidiaries, which were sold to
Calpine in July 2010
Pepco, DPL and BGE, the Maryland utilities required by the MDPSC to enter into a contract for
new generation
Consumer Price Index
California Public Utilities Commission
Cross-State Air Pollution Rule
Consolidated tax adjustment
Competitive Transition Charge
United States Court of Appeals for the District of Columbia Circuit
District of Columbia Public Service Commission
District of Columbia Power Line Undergrounding
The supply of electricity by PHI’s electric utility subsidiaries at regulated rates to retail customers
who do not elect to purchase electricity from a competitive supplier, and which, depending on
the jurisdiction, is also known as Standard Offer Service or BGS
Default Electricity Supply Revenue
DOE
DOJ
Revenue primarily from Default Electricity Supply
United States Department of Energy
United States Department of Justice
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Other Terms and Abbreviations
DPSC
DRP
DSP
DSP Program
EDCs
EDF
EE&C
EGS
EIMA
EmPower Maryland
EPA
ERCOT
ERISA
EROA
ESPP
FASB
FEJA
FERC
FRCC
FTC
GAAP
GCR
GHG
GRT
GSA
GWh
HAP
Health Care Reform Acts
HSR Act
IBEW
ICC
ICE
Illinois Act
Illinois EPA
Illinois Settlement Legislation
Integrys
IPA
IRC
IRS
ISO
ISO-NE
ISO-NY
kV
kW
kWh
LIBOR
LILO
Delaware Public Service Commission
Direct Stock Purchase and Dividend Reinvestment Plan
Default Service Provider
Default Service Provider Program
Electric distribution companies
Electricite de France SA and its subsidiaries
Energy Efficiency and Conservation/Demand Response
Electric Generation Supplier
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
Electric Reliability Council of Texas
Employee Retirement Income Security Act of 1974, as amended
Expected Rate of Return on Assets
Employee Stock Purchase Plan
Financial Accounting Standards Board
Illinois Public Act 99-0906 or Future Energy Jobs Act
Federal Energy Regulatory Commission
Florida Reliability Coordinating Council
Federal Trade Commission
Generally Accepted Accounting Principles in the United States
Gas Cost Rate
Greenhouse Gas
Gross Receipts Tax
Generation Supply Adjustment
Gigawatt hour
Hazardous air pollutants
Patient Protection and Affordable Care Act and Health Care and Education Reconciliation Act of
2010
The Hart-Scott-Rodino Antitrust Improvements Act of 1976
International Brotherhood of Electrical Workers
Illinois Commerce Commission
Intercontinental Exchange
Illinois Electric Service Customer Choice and Rate Relief Law of 1997
Illinois Environmental Protection Agency
Legislation enacted in 2007 affecting electric utilities in Illinois
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
Lease-In, Lease-Out
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Other Terms and Abbreviations
LLRW
LT Plan
LTIP
MAPP
MATS
MBR
MDE
MDPSC
MGP
MISO
mmcf
Moody’s
MOPR
MRV
MW
MWh
NAAQS
n.m.
NAV
NDT
NEIL
NERC
NGS
NJBPU
NJDEP
Non-Regulatory Agreements Units
NOSA
NOV
NPDES
NRC
NSPS
NUGs
NWPA
NYMEX
OCI
OIESO
OPC
OPEB
PA DEP
PAPUC
PGC
PHI Retirement Plan
PJM
POLR
POR
PPA
Price-Anderson Act
Preferred Stock
Low-Level Radioactive Waste
Long-term renewable resources procurement plan
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
Minimum Offer Price Rule
Market-Related Value
Megawatt
Megawatt hour
National Ambient Air Quality Standards
not meaningful
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
Nuclear generating units or portions thereof whose decommissioning-related activities are not
subject to contractual elimination under regulatory accounting
Nuclear Operating Services Agreement
Notice of Violation
National Pollutant Discharge Elimination System
Nuclear Regulatory Commission
New Source Performance Standards
Non-utility generators
Nuclear Waste Policy Act of 1982
New York Mercantile Exchange
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
Purchased Gas Cost Clause
PHI’s noncontributory retirement plan
PJM Interconnection, LLC
Provider of Last Resort
Purchase of Receivables
Power Purchase Agreement
Price-Anderson Nuclear Industries Indemnity Act of 1957
Originally issued shares of non-voting, non-convertible and non-transferable Series A preferred
stock, par value $0.01 per share
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Table of Contents
Other Terms and Abbreviations
PRP
PSEG
PURTA
PV
RCRA
REC
Regulatory Agreement Units
RES
RFP
Rider
RGGI
RMC
ROE
RPM
RPS
RSSA
RTEP
RTO
S&P
SEC
Senate Bill 1
SERC
SERP
SGIG
SGIP
SILO
SMPIP
SNF
SOCAs
SOS
SPP
Tax Relief Act of 2010
Transition Bond Charge
Transition Bonds
Upstream
VIE
WECC
ZEC
ZES
Potentially Responsible Parties
Public Service Enterprise Group Incorporated
Pennsylvania Public Realty Tax Act
Photovoltaic
Resource Conservation and Recovery Act of 1976, as amended
Renewable Energy Credit which is issued for each megawatt hour of generation from a qualified
renewable energy source
Nuclear generating units or portions thereof whose decommissioning-related activities are
subject to contractual elimination under regulatory accounting
Retail Electric Suppliers
Request for Proposal
Reconcilable Surcharge Recovery Mechanism
Regional Greenhouse Gas Initiative
Risk Management Committee
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
Maryland Senate Bill 1
SERC Reliability Corporation (formerly Southeast Electric Reliability Council)
Supplemental Employee Retirement Plan
Smart Grid Investment Grant from DOE
Smart Grid Initiative Program
Sale-In, Lease-Out
Smart Meter Procurement and Installation Plan
Spent Nuclear Fuel
Standard Offer Capacity Agreements required to be entered into by ACE pursuant to a New
Jersey law enacted to promote the construction of qualified electric generation facilities in New
Jersey
Standard Offer Service
Southwest Power Pool
Tax Relief, Unemployment Insurance Reauthorization and Job Creation Act of 2010
Revenue ACE receives, and pays to ACE Funding, to fund the principal and interest payments
on Transition Bonds and related taxes, expenses and fees
Transition Bonds 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
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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.
FORWARD-LOOKING STATEMENTS
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 a
Registrants include those factors discussed herein, including those factors discussed with respect to such Registrant 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 24; 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 public may read and copy any reports or other information that the Registrants file with the SEC at the SEC’s public reference room at 100
F Street, N.E., Washington, D.C. 20549. The public may obtain information on the operation of the Public Reference Room by calling the SEC at
1-800-SEC-0330. These documents are also available to the public from commercial document retrieval services, the website maintained by the
SEC at www.sec.gov and the Registrants’ websites at www.exeloncorp.com. Information contained on the Registrants’ websites shall not be
deemed incorporated into, or to be a part of, this Report.
ITEM 1.
BUSINESS
General
Corporate Structure and Business and Other Information
PART I
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, and its telephone number is 800-483-3220.
Generation
Generation’s integrated business consists of the generation, physical delivery and marketing of power across multiple geographical regions
through its customer-facing business, Constellation. Generation has six reportable segments consisting of the Mid-Atlantic, Midwest, New England,
New York, ERCOT and Other Power Regions.
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Generation was formed in 2000 as a Pennsylvania limited liability company. Generation began operations as a result of a corporate
restructuring, effective January 1, 2001, in which Exelon separated its generation and other competitive businesses from its regulated energy
delivery businesses at ComEd and PECO.
Generation’s principal executive offices are located at 300 Exelon Way, Kennett Square, Pennsylvania 19348, and its telephone number is
610-765-5959.
ComEd
ComEd’s energy delivery business consists of the purchase and regulated retail sale of electricity and the provision of electricity transmission
and distribution services to retail customers in northern Illinois, including the City of Chicago.
ComEd was organized in the State of Illinois in 1913 as a result of the merger of Cosmopolitan Electric Company into the original corporation
named Commonwealth Edison Company, which was incorporated in 1907. ComEd’s principal executive offices are located at 440 South LaSalle
Street, Chicago, Illinois 60605, and its telephone number is 312-394-4321.
PECO
PECO’s energy delivery business consists of the purchase and regulated retail sale of electricity and the provision of electricity transmission
and distribution services to retail customers in southeastern Pennsylvania, including the City of Philadelphia, as well as the purchase and regulated
retail sale of natural gas and the provision of natural gas distribution services to retail customers in the Pennsylvania counties surrounding the City of
Philadelphia.
PECO was incorporated in Pennsylvania in 1929. PECO’s principal executive offices are located at 2301 Market Street, Philadelphia,
Pennsylvania 19103, and its telephone number is 215-841-4000.
BGE
BGE’s energy delivery business consists of the purchase and regulated retail sale of electricity and the provision of electricity transmission and
distribution services to retail customers in central Maryland, including the City of Baltimore, as well as the purchase and regulated retail sale of
natural gas and the provision of natural gas distribution services to retail customers in central Maryland, including the City of Baltimore.
BGE was incorporated in Maryland in 1906. BGE’s principal executive offices are located at 110 West Fayette Street, Baltimore, Maryland
21201, and its telephone number is 410-234-5000.
PHI
PHI is a utility services holding company engaged, through its reportable segments Pepco, DPL and ACE, in the energy delivery businesses
discussed below. On March 23, 2016, Pepco Holdings, Inc., converted from a Delaware corporation to a Delaware limited liability company, Pepco
Holdings LLC. PHI’s principal executive offices are located at 701 Ninth Street, N.W., Washington, D.C. 20068, and its telephone number is
202-872-2000.
Pepco
Pepco’s energy delivery business consists of the purchase and regulated retail sale of electricity and the provision of electricity transmission
and distribution services to retail customers in the District of Columbia and major portions of Montgomery County and Prince George’s County in
Maryland.
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Pepco was incorporated in the District of Columbia in 1896 and Virginia in 1949. Pepco’s principal executive offices are located at 701 Ninth
Street, N.W., Washington, D.C. 20068, and its telephone number is 202-872-2000.
DPL
DPL’s energy delivery business consists of the purchase and regulated retail sale of electricity and the provision of electricity transmission and
distribution services to retail customers in portions of Delaware and Maryland, as well as the purchase and regulated retail sale of natural gas and
the provision of natural gas distribution services to retail customers in portions of New Castle County in Delaware.
DPL was incorporated in Delaware in 1909 and Virginia in 1979. DPL’s principal executive offices are located at 500 North Wakefield Drive,
Newark, Delaware 19702, and its telephone number is 202-872-2000.
ACE
ACE’s energy delivery business consists of the purchase and regulated retail sale of electricity and the provision of electricity transmission and
distribution services to retail customers in portions of southern New Jersey.
ACE was incorporated in New Jersey in 1924. ACE’s principal executive offices are located at 500 North Wakefield Drive, Newark, Delaware
19702, and its telephone number is 202-872-2000.
Business Services
Through its business services subsidiary BSC, Exelon provides its operating subsidiaries with a variety of support services at cost. The costs
of these services are directly charged or allocated to the applicable operating segments. Additionally, the results of Exelon’s corporate operations
include costs for corporate governance and interest costs and income from various investment and financing activities.
PHI Service Company, a wholly owned subsidiary of PHI, provides a variety of support services at cost, including legal, accounting,
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 PHI Service Company and the participating
operating subsidiaries.
Operating Segments
See Note 26—Segment Information of the Combined Notes to Consolidated Financial Statements for additional information on Exelon’s
operating segments.
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 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). Following the
completion of the
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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 4—Mergers, Acquisitions, and Dispositions of the Combined Notes to Consolidated Financial Statements for additional information on the
PHI transaction.
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. The retail sales
include commercial, industrial and residential 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 also 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. Additionally, 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 mandatory reliability standards promulgated by the NERC, with the
approval of FERC.
RTOs and ISOs exist in a number of regions to provide transmission service across multiple transmission systems. PJM, MISO, ISO-NE and
SPP, have been approved by FERC as RTOs, and CAISO and ISO-NY have been approved 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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Constellation Energy Nuclear Group, Inc.
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 and Nine
Mile Point. CENG’s ownership share in the total capacity of these units is 4,007 MW. See ITEM 2. PROPERTIES for additional information on these
sites.
Generation and EDF also 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. In addition, under limited circumstances, the period for exercise of
the put option may be extended for 18 months.
Prior to April 1, 2014, Exelon and Generation accounted for their investment in CENG under the equity method of accounting. The transfer of
the nuclear operating licenses and the execution of the NOSA on April 1, 2014, resulted in the derecognition of the equity method investment in
CENG and the recording of all assets, liabilities and EDF’s noncontrolling interests in CENG at fair value on a fully consolidated basis in Exelon’s
and Generation’s Consolidated Balance Sheets. Refer to Note 5—Investment in Constellation Energy Nuclear Group, LLC of the Combined Notes to
Consolidated Financial Statements for further information regarding the integration transaction.
Acquisitions
ConEdison Solutions. On September 1, 2016, Generation acquired the competitive retail electric and natural gas business activities of
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 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.
Merger with Constellation Energy Group, Inc. On March 12, 2012, Constellation merged into Exelon with Exelon continuing as the surviving
corporation pursuant to the transactions contemplated by the Agreement and Plan of Merger. Since the merger transaction, Generation includes the
former Constellation generation and customer supply operations.
Dispositions
Upstream Disposition. On June 16, 2016, Generation initiated the sales process of its Upstream business. See Note 14—Debt and Credit
Agreements for more 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 on Exelon’s and Generation’s Consolidated Statements of
Operations and Comprehensive Income for the year ended December 31, 2016.
Asset Divestitures. During 2014 and 2015, 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.
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Maryland Clean Coal Stations. On November 30, 2012, a subsidiary of Generation sold the Brandon Shores generating station and H.A.
Wagner generating station in Anne Arundel County, Maryland, and the C.P. Crane generating station in Baltimore County, Maryland to Raven Power
Holdings LLC, a subsidiary of Riverstone Holdings LLC to comply with certain of the regulatory approvals required by the merger with Constellation
Energy Group, Inc. for net proceeds of approximately $371 million, which resulted in a pre-tax impairment charge of $272 million.
See Note 4—Mergers, Acquisitions, and Dispositions and Note 8—Impairment of Long-Lived Assets of the Combined Notes to Consolidated
Financial Statements for additional information.
Generating Resources
At December 31, 2016, 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
19,457
9,548
3,715
32,720
6,879
39,599
(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, and solar generating assets.
Generation has six reportable segments, the Mid-Atlantic, Midwest, New England, New York, ERCOT and Other Power Regions, representing
the different geographical areas in which Generation’s customer-facing activities are conducted and where Generation’s generating resources are
located.
•
•
•
•
•
•
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 36% of capacity).
Midwest represents operations in the western half of PJM, which includes portions of Illinois, Indiana, Ohio, Michigan, Kentucky and
Tennessee; and the United States footprint of MISO (excluding MISO’s Southern Region), which covers all or most of North Dakota, South
Dakota, Nebraska, Minnesota, Iowa, Wisconsin, and the remaining parts of Illinois, Indiana, Michigan and Ohio not covered by PJM; and
parts of Montana, Missouri and Kentucky (approximately 37% of capacity).
New England represents the operations within ISO-NE covering the states of Connecticut, Maine, Massachusetts, New Hampshire, Rhode
Island and Vermont (approximately 7% of capacity).
New York represents the operations within ISO-NY, which covers the state of New York in its entirety (approximately 3% of capacity).
ERCOT represents operations within Electric Reliability Council of Texas, covering most of the state of Texas (approximately 11% of
capacity).
Other Power Regions is an aggregate of regions not considered individually significant (approximately 6% of capacity).
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See Note 26—Segment Information of the Combined Notes to Consolidated Financial Statements for additional information on revenues from
external customers and revenues net of purchased power and fuel expense for each of Generation’s reportable segments.
Nuclear Facilities
Generation has ownership interests in fourteen nuclear generating stations currently in service, consisting of 24 units with an aggregate of
19,457 MW of capacity. Generation wholly owns all of its nuclear generating stations, except for Quad Cities Generating Station (75% ownership),
Peach Bottom Generating Station (50% ownership), and Salem Generating Station (Salem) (42.59% ownership), which are consolidated on Exelon’s
and Generation’s financial statements relative to its proportionate ownership interest in each unit. In addition, Generation owns a 50.01% interest,
collectively, in the CENG generating stations (Calvert Cliffs, Nine Mile Point [excluding LIPA’s 18% ownership interest in Nine Mile Point Unit 2] and
R.E. Ginna) which are 100% consolidated on Exelon and Generation’s financial statements as of April 1, 2014. See Note 5—Investment in
Constellation Energy Nuclear Group, LLC of the Combined Notes to Consolidated Financial Statements for additional information. See Note 3—
Regulatory Matters of the Combined Notes to Consolidated Financial Statements for additional information on the impact of the Future Energy Jobs
Bill and New York CES on certain nuclear plants.
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 2016, 2015 and 2014 electric supply (in GWh) generated
from the nuclear generating facilities was 67%, 68% and 67%, respectively, of Generation’s total electric supply, which also includes fossil,
hydroelectric and renewable generation and electric supply purchased for resale. The majority of this output was dispatched to support Generation’s
wholesale and retail power marketing activities. See ITEM 7. MANAGEMENT’S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND
RESULTS OF OPERATIONS for further discussion of Generation’s electric supply sources.
On August 8, 2016, Generation executed a series of agreements with Entergy Nuclear FitzPatrick LLC (Entergy) to acquire the 838MW single-
unit James A. FitzPatrick (FitzPatrick) nuclear generating station located in Scriba, New York. Closing of the transaction is currently anticipated to
occur in the first half of 2017 and requires regulatory approval by FERC, NRC and the New York Public Service Commission (NYPSC). The
transaction is also subject to the notification and reporting requirements of the HSR Act (which has been completed) and other customary closing
conditions. See Note 4—Mergers, Acquisitions, and Dispositions of the Combined Notes to Consolidated Financial Statements for additional detail
on the proposed acquisition of the FitzPatrick nuclear generating station.
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. As the largest generator of nuclear power in the United States, Generation can
negotiate favorable terms for the materials and services that its business requires. Generation’s operations from its nuclear plants have historically
had minimal environmental impact and the plants have a safe operating history.
During 2016, 2015 and 2014, the nuclear generating facilities operated by Generation achieved capacity factors of 94.6%, 93.7% and 94.3%,
respectively. The capacity factors reflect ownership percentage of stations operated by Generation and include CENG as of April 1, 2014.
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
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marketing and trading 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 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. As of January 30, 2017, the NRC categorized Ginna in the Regulatory Response Column,
which is the second highest of five performance bands. All other units operated by Generation are categorized in the Licensee Response Column,
which is the highest performance band. 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 terms of the operating licenses. Changes in regulations by the NRC may require a
substantial increase in capital expenditures for nuclear generating facilities and/or increased operating costs of nuclear generating units.
For information on the NRC actions related to the Japan Earthquake and Tsunami and the industry’s response, see ITEM 7. MANAGEMENT’S
DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS—Executive Overview.
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. On December 8, 2010, Exelon announced that Generation will permanently cease generation operations at Oyster Creek by
December 31, 2019.
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The following table summarizes the current operating license expiration dates for Generation’s nuclear facilities in service:
Station
Braidwood
Byron
Calvert Cliffs
Clinton (b)
Dresden
LaSalle
Limerick
Nine Mile Point
Oyster Creek (c)
Peach Bottom (d)
Quad Cities
R.E. Ginna
Salem
Three Mile Island
Unit
1
2
1
2
1
2
1
2
3
1
2
1
2
1
2
1
2
3
1
2
1
1
2
1
In-Service
Date (a)
Current License
Expiration
1988
1988
1985
1987
1975
1977
1987
1970
1971
1984
1984
1986
1990
1969
1988
1969
1974
1974
1973
1973
1970
1977
1981
1974
2046
2047
2044
2046
2034
2036
2026
2029
2031
2042
2043
2044
2049
2029
2046
2029
2033
2034
2032
2032
2029
2036
2040
2034
(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
(c)
be filed until the first quarter of 2021.
In December 2010, Exelon announced that Generation will permanently cease generation operations at Oyster Creek by December 31, 2019. In 2016, Exelon notified the
NRC that it will cease operations at Oyster Creek on November 30, 2019.
(d) On June 7, 2016, Generation announced that it will submit a second 20 year license renewal application to NRC for Peach Bottom Units 2 and 3 in 2018.
The operating license renewal process takes approximately four to five years from the commencement of the renewal process until completion
of the NRC’s review. The NRC review process takes approximately two years from the docketing of an application. To date, each granted license
renewal has been for 20 years beyond the original operating license expiration. Depreciation provisions are based on the estimated useful lives of
the stations, which reflect the actual renewal of operating licenses for all of Generation’s operating nuclear generating stations except for Oyster
Creek and Clinton. Oyster Creek depreciation provisions are based on the 2019 expected shutdown date. Clinton depreciation provisions are based
on 2027 which is the last year of the Illinois Zero Emissions Standard. See Note 3—Regulatory Matters of the Combined Notes to Consolidated
Financial Statements for additional detail on the new Illinois legislation and Note 9—Early Nuclear Plant Retirements of the Combined Notes to
Consolidated Financial Statements for additional detail on the reversal of the decision to early retire Clinton.
In August 2012, Generation entered into an operating services agreement with the Omaha Public Power District (OPPD) to provide operational
and managerial support services for the Fort Calhoun Station and a licensing agreement for use of the Exelon Nuclear Management Model. On
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December 16, 2016, Generation was notified by OPPD of the termination of the operating services agreement for Fort Calhoun Station effective
June 14, 2017. OPPD has the option to continue to use the Exelon Nuclear Management Model for payment of a fee.
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, 2016, Generation had approximately 77,900 SNF assemblies (19,200 tons) stored on site in SNF pools or dry cask
storage (this 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; see Note 16—Asset Retirement Obligations of the Combined Notes to Consolidated Financial
Statements for additional information regarding Zion Station Decommissioning). All currently operating Generation-owned nuclear sites have on-site
dry cask storage, except for Three Mile Island, where such storage is projected to be in operation in 2023. 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 24—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.
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 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 cost impacts and on-site storage.
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
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reduced its financial exposure to these risks through insurance and other industry risk-sharing provisions. See “Nuclear Insurance” within Note 24—
Commitments and Contingencies of the Combined Notes to Consolidated Financial Statements for details.
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 conditions and results of operations and cash flows.
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. See ITEM 7. MANAGEMENT’S
DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS—Exelon Corporation, Executive Overview; ITEM 7.
MANAGEMENT’S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS, Critical Accounting Policies and
Estimates, Nuclear Decommissioning, Asset Retirement Obligations and Nuclear Decommissioning Trust Fund Investments; and Note 3—
Regulatory Matters, Note 12—Fair Value of Financial Assets and Liabilities and Note 16—Asset Retirement Obligations of the Combined Notes to
Consolidated Financial Statements for additional information regarding Generation’s NDT funds and its decommissioning obligations. The ultimate
decommissioning obligation will be funded by the NDTs. The NDTs are recorded on Exelon’s and Generation’s Consolidated Balance Sheets at
December 31, 2016 at fair value of approximately $11.1 billion and have an estimated targeted annual pre-tax return of 5.3% to 5.9%.
Zion Station Decommissioning. On December 11, 2007, Generation entered into an Asset Sale Agreement (ASA) with EnergySolutions, Inc.
and its wholly owned subsidiaries, EnergySolutions, LLC (EnergySolutions) and ZionSolutions, LLC (ZionSolutions) under which ZionSolutions
assumed responsibility for decommissioning Zion Station, which is located in Zion, Illinois and ceased operation in 1998.
On September 1, 2010, Generation and EnergySolutions completed the transactions contemplated by the ASA. Specifically, 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 shall be deferred until such milestones are met. See Note 16—Asset Retirement Obligations of the Combined Notes to
Consolidated Financial Statements for additional information regarding Zion Station Decommissioning and see 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, 2016, Generation had ownership interests in 13,263 MW of capacity in generating facilities currently in service, consisting of
9,522 MW of natural gas and oil, 3,715 MW of renewables (wind, hydroelectric, and solar) and 26 MW of waste coal. Generation wholly owns all of
its fossil and renewable generating stations, with the exception of: (1) jointly owned facilities that include Wyman; (2) certain wind project entities with
minority interest owners; and (3) an ownership interest in the Albany Green Energy, LLC project entity, 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 LaPorte
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and Wyman, which are operated by third parties. In 2016, 2015 and 2014, electric supply (in GWh) generated from owned fossil and renewable
generating facilities was 10%, 8% and 13%, 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.
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. On August 29, 2012 and August 30, 2012, Generation submitted
hydroelectric license applications to the FERC for 46-year licenses for the Conowingo Hydroelectric Project (Conowingo) and the Muddy Run
Pumped Storage Facility Project (Muddy Run), respectively. On December 22, 2015, FERC issued a new 40-year license for Muddy Run. The
license term expires on December 1, 2055. Based on the FERC procedural schedule, the FERC licensing process was not completed prior to the
expiration of Conowingo’s license on September 1, 2014. FERC is required to issue an annual license for the facility until the new license is issued.
On September 10, 2014, FERC issued an annual license for Conowingo, effective as of the expiration of the previous license. If FERC does not
issue a new license prior to the expiration of annual license, the annual license will renew automatically. The stations are currently being depreciated
over their estimated useful lives, which includes actual and anticipated license renewal periods. Refer to Note 3—Regulatory Matters of the
Combined Notes to Consolidated Financial Statements for additional information.
Insurance. Generation maintains business interruption insurance for its renewable and fossil projects, and delay in start-up insurance for its
renewable and fossil projects currently under construction. Generation does not purchase business interruption insurance for its wholly owned fossil
and hydroelectric operations, unless required by financing agreements; see Note 14—Debt and Credit Agreements of the Combined Notes to
Consolidated Financial Statements for additional information on financing agreements. Generation maintains both property damage and liability
insurance. For property damage and liability claims for these operations, Generation is self-insured to the extent that losses are within the policy
deductible or exceed the amount of insurance maintained. Such losses could have a material adverse effect on Exelon’s and Generation’s future
financial conditions and their results of operations and cash flows. For information regarding property insurance, see ITEM 2. PROPERTIES—
Exelon Generation Company, LLC.
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Long-Term Power Purchase Contracts
In addition to energy produced by owned generation assets, Generation sources electricity and other related output 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, 2016:
Region
Mid-Atlantic
Midwest
New England
ERCOT
Other Power Regions
Total
Capacity Expiring (MW)
Fuel
Number of
Agreements
16
6
8
5
11
46
Expiration
Dates
2017 - 2032
2017 - 2026
2017
2020 - 2031
2017 - 2030
Capacity (MW)
800
1,236
650
1,501
2,692
6,879
2017 2018 2019 2020 2021
815
1,790
980
644
101
The following table shows sources of electric supply in GWh for 2016 and 2015:
Nuclear (a)
Purchases—non-trading portfolio
Fossil (primarily natural gas and oil)
Renewable (b)
Total supply
Source of Electric Supply
2016
176,799
59,987
19,830
6,324
262,940
2015
175,474
63,637
14,936
5,982
260,029
(a)
(b)
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 2016 and 2015 includes physical volumes of 33,444 GWh and 33,415 GWh, respectively, for CENG.
Includes wind, hydroelectric, and solar generating assets.
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
uranium concentrate inventory and supply contracts sufficient to meet all of its uranium concentrate requirements through 2018. Generation’s
contracted conversion services are sufficient to meet all of its uranium conversion requirements through 2017. All of Generation’s enrichment
requirements have been contracted through 2020. Contracts for fuel fabrication have been obtained through 2022. Generation 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
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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. Generation also hedges
forward price risk, 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 13—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 the physical delivery and marketing of power obtained through its generation capacity and
through long-term, intermediate-term and short-term contracts. Generation maintains an effective supply strategy through ownership of generation
assets and power purchase and lease agreements. Generation has also contracted for access to additional generation through bilateral long-term
PPAs. PPAs, including tolling agreements, are commitments related to power generation of specific generation plants and/or are dispatchable in
nature similar to asset ownership depending on the type of underlying asset. Generation secures contracted generation as part of its overall strategic
plan, with objectives such as obtaining low-cost energy supply sources to meet its physical delivery obligations to both wholesale and retail
customers and assisting customers to meet renewable portfolio standards. 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. Generation’s customer facing operations combine a unified sales force with a customer-centric
model that leverages technology to broaden the range of products and solutions offered, which Generation believes promotes stronger customer
relationships. This model focuses on efficiency and cost reduction, which provides a platform that is scalable and able to capitalize on opportunities
for future growth.
Generation may purchase more than the energy demanded by its customers. Generation then sells this open position, along with capacity not
used to meet customer demand, in the wholesale electricity markets. Where necessary, Generation also purchases transmission service to ensure
that it has reliable transmission capacity to physically move its power supplies to meet customer delivery needs in markets without an organized
RTO. Generation also incorporates contingencies into its planning for extreme weather conditions, including potentially reserving capacity to meet
summer loads at levels representative of warmer-than-normal weather conditions.
Price 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 also enters into
transactions that are outside of this ratable sales plan. Generation is exposed to commodity price risk in 2017 and beyond for portions of its
electricity portfolio that are unhedged. Generation has been and will continue to be proactive in using hedging strategies to mitigate this risk in
subsequent years. As of December 31, 2016, the percentage of expected generation hedged for the major reportable segments was 91%-94%,
56%-59% and 28%-31% for 2017, 2018, and 2019, 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
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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, which routinely change in the market. The corporate 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, including volume, stop-loss and
value-at-risk limits, to manage exposure to market risk. 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 in nuclear fuel and energy generation assets and in other
internal infrastructure projects. Generation’s estimated capital expenditures for 2017 are as follows:
(in millions)
Nuclear fuel (a)
Growth
Production plant
Total
$ 925
600
1,125
$2,650
(a)
Includes Generation’s share of the investment in nuclear fuel for the co-owned Salem plant.
ComEd
ComEd is engaged principally in the purchase and regulated retail sale of electricity and the provision of electricity distribution and
transmission services to retail customers in northern Illinois. ComEd is a public utility under the Illinois Public Utilities Act subject to regulation by the
ICC related to distribution rates and service, the issuance of securities and certain other aspects of ComEd’s business. ComEd is a public utility
under the Federal Power Act subject to regulation by FERC related to transmission rates and certain other aspects of ComEd’s business. Specific
operations of ComEd are also subject to the jurisdiction of various other Federal, state, regional and local agencies. Additionally, ComEd is subject
to NERC mandatory reliability standards.
ComEd’s franchises are sufficient to permit it to engage in the business it now conducts. ComEd’s franchise rights are generally nonexclusive
rights documented in agreements and, in some cases, certificates of public convenience issued by the ICC. With few exceptions, the franchise rights
have stated expiration dates ranging from 2017 to 2066. ComEd anticipates working with the appropriate governmental bodies to extend or replace
the franchise agreements prior to expiration.
PECO
PECO is engaged principally in the purchase and regulated retail sale of electricity and the provision of electricity distribution and transmission
services to retail customers in southeastern Pennsylvania, including the City of Philadelphia, as well as the purchase and regulated retail sale of
natural gas and the provision of gas distribution services to retail customers in the Pennsylvania counties surrounding the City of Philadelphia. PECO
is a public utility under the Pennsylvania Public
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Utility Code subject to regulation by the PAPUC related to electric and gas distribution rates and service, the issuances of certain securities and
certain other aspects of PECO’s business. PECO is a public utility under the Federal Power Act subject to regulation by FERC related to
transmission rates and certain other aspects of PECO’s business and by the U.S. Department of Transportation related to pipeline safety and other
areas of gas operations. Specific operations of PECO are subject to the jurisdiction of various other Federal, state, regional and local agencies.
Additionally, PECO is also subject to NERC mandatory reliability standards.
PECO has the necessary authorizations to provide regulated electric and natural gas distribution services in the various municipalities or
territories in which it now supplies such services. PECO’s authorizations consist of charter rights and certificates of public convenience issued by the
PAPUC and/or “grandfathered rights,” with all of such rights generally unlimited as to time and generally exclusive from competition from other
electric and natural gas utilities. In a few defined municipalities, PECO’s natural gas service territory authorizations overlap with that of another
natural gas utility; however, PECO does not consider those situations as posing a material competitive or financial threat.
BGE
BGE is engaged principally in the purchase and regulated retail sale of electricity and the provision of electricity distribution and transmission
services to retail customers in central Maryland, including the City of Baltimore, as well as the purchase and regulated retail sale of natural gas and
the provision of gas distribution services to retail customers in central Maryland, including the City of Baltimore. BGE is a public utility under the
Public Utilities Article of the Maryland Annotated Code subject to regulation by the MDPSC related to electric and gas distribution rates and service,
the issuances of certain securities and certain other aspects of BGE’s business. BGE is a public utility under the Federal Power Act subject to
regulation by FERC related to transmission rates and certain other aspects of BGE’s business and by the U.S. Department of Transportation related
to pipeline safety and other areas of gas operations. Specific operations of BGE are subject to the jurisdiction of various other Federal, state,
regional and local agencies. Additionally, BGE is also subject to NERC mandatory reliability standards.
BGE has the necessary authorizations to provide regulated electric and natural gas distribution services in the various municipalities and
territories in which it now supplies such services. With respect to electric distribution service, BGE’s authorizations consist of charter rights, a state-
wide franchise grant and a franchise grant from the City of Baltimore. The franchise rights are nonexclusive and are perpetual. Pursuant to statute,
public service companies in Maryland may exercise a franchise to the extent authorized by the MDPSC. The service territory for BGE, as well as for
other electric utilities in the state, was precisely delineated in 1966 by the MDPSC and has been modified in minor ways over the years. With respect
to natural gas distribution service, BGE’s authorizations consist of charter rights, a perpetual state-wide franchise grant and franchises granted by all
the municipalities and/or governmental bodies in which BGE now supplies services. The franchise grants are not exclusive; some are perpetual and
some are for a limited duration, which BGE anticipates being able to extend or replace prior to expiration.
PHI
PHI was incorporated in Delaware in 2001. Through its reportable segments Pepco, DPL and ACE, PHI is engaged primarily in the
transmission, distribution and default supply of electricity, and, to a lesser extent, the distribution and supply of natural gas. On March 23, 2016,
Pepco Holdings, Inc., converted from a Delaware corporation to a Delaware limited liability company, Pepco Holdings LLC. PHI Service Company, a
wholly owned subsidiary of PHI, provides a variety of support services at cost, including legal, accounting, engineering, distribution and transmission
planning, asset management, system operations, and power procurement, to PHI and its operating subsidiaries.
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Pepco
Pepco is engaged principally in the purchase and regulated retail sale of electricity and the provision of electricity distribution and transmission
services in the District of Columbia and major portions of Prince George’s County and Montgomery County in Maryland. Pepco is a public utility
under the Code of the District of Columbia and subject to regulation by the DCPSC related to distribution rates and service, the issuance of
securities and certain other aspects of Pepco’s business in the District of Columbia. Pepco is also an electric company under the Maryland Public
Utilities Article of the Maryland Annotated Code subject to regulation by the MDPSC related to distribution rates and service, the issuance of
securities and certain other aspects of Pepco’s business in Maryland. Pepco is a public utility under the Federal Power Act subject to regulation by
FERC related to transmission rates and certain other aspects of Pepco’s business. Additionally, Pepco is subject to NERC mandatory reliability
standards.
Pepco’s right to occupy public space for utility purposes is by permit from the District of Columbia and the federal government. Pepco is the
only public utility that distributes electricity for sale to the public in the District of Columbia. In Maryland, Pepco operates pursuant to state-wide
franchises granted by Maryland’s General Assembly that are unlimited in duration. Pursuant to statute, public service companies in Maryland may
exercise a franchise to the extent authorized by the MDPSC. The service territories for Pepco, as well as for other electric utilities in the state, were
precisely delineated in 1966 by the MDPSC and have been modified in minor ways over the years.
DPL
DPL is engaged principally in the purchase and regulated retail sale of electricity and the provision of electricity distribution and transmission
services to retail customers in portions of Maryland and Delaware, as well as the purchase and regulated retail sale of natural gas and the provision
of natural gas distribution services to retail customers in New Castle County, Delaware. DPL is a public utility under the Delaware Code and subject
to regulation by the DPSC related to electric and gas distribution rates and service, the issuance of certain securities and certain other aspects of
DPL’s business in Delaware. In Maryland, DPL is an electric company under the Public Utilities Article of the Maryland Annotated Code subject to
regulation by the MDPSC related to electric rates and service, the issuances of certain securities and certain other aspects of DPL’s business in
Maryland. DPL is a public utility under the Federal Power Act and is subject to regulation by FERC related to transmission rates and certain other
aspects of DPL’s business and by the U.S. Department of Transportation related to pipeline safety and other areas of gas operations. Additionally,
DPL is also subject to NERC mandatory reliability standards.
DPL has the necessary authorizations to provide regulated electric and natural gas distribution services in the various municipalities and
territories in which it now supplies such services. In Maryland, DPL operates pursuant to state-wide franchises that are substantially similar in nature
to those described above with respect to Pepco’s Maryland operations. DPL’s exclusive and continuing authority to distribute electricity and natural
gas in its non-municipal service territories in Delaware is derived from legislation, through which the DPSC has established exclusive service
territories. With respect to municipalities that it serves, DPL provides service under various franchises granted to DPL and predecessor companies,
which franchises are generally either unlimited as to time or renew automatically.
ACE
ACE is engaged principally in the purchase and regulated retail sale of electricity and the provision of electricity distribution and transmission
services to retail customers in portions of southern New
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Jersey. ACE is a public utility under the New Jersey Public Utilities Act subject to regulation by the NJBPU related to distribution rates and service,
the issuance of securities and certain other aspects of ACE’s business. ACE is a public utility under the Federal Power Act subject to regulation by
FERC related to transmission rates and certain other aspects of ACE’s business. Additionally, ACE is subject to NERC mandatory reliability
standards.
ACE’s franchises are sufficient to permit it to engage in the business it now conducts. ACE operates under non-exclusive franchises that have
been granted by the NJBPU and under certain non-exclusive consents from municipalities in which ACE provides service. While most of the
municipal consents were granted in perpetuity, two of the municipal consents require renewal on a periodic basis in accordance with their terms with
respect to ACE’s continued right to erect and maintain wires and poles in, upon, over and under the public streets, streets and alleys, and are
subject to the ultimate review and approval of the NJBPU. All of the franchises and consents are currently in full force and effect.
ComEd, PECO, BGE, Pepco, DPL and ACE
Utility Operations
Service Territories. The following table presents the size of retail service territories, populations of each retail service territory and the number
of retail customers within each retail service territory for the Utility Registrants as of December 31, 2016:
ComEd
PECO
BGE
Pepco
DPL
ACE
Total
Retail Service Territories
(in square miles)
Electric
11,400
1,900
2,300
640
5,400
2,800
Natural gas
n/a
1,900
800
n/a
275
n/a
11,400
2,100
2,300
640
5,675
2,800
Retail Service Territory Population
(in millions)
Electric
9.4
4.0
3.0
2.4
1.4
1.1
Natural gas
n/a
3.1
2.9
n/a
0.6
n/a
Total
9.4(a)
4.6(b)
3.0(c)
2.4(d)
2.0(e)
1.1(f)
Number of Retail Customers
(in millions)
Electric
4.0
1.6
1.3
0.9
0.5
0.5
Natural gas
n/a
0.5
0.7
n/a
0.1
n/a
Total
4.0
2.1
1.3
0.9
0.6
0.5
(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.
Peak Deliveries. The Utility Registrants electric sales and peak load 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 sales are generally higher
during the winter months when cold temperatures create demand for winter heating.
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The following table summarizes historic peak deliveries for the Utility Registrants for electric and gas deliveries during peak demand months
through December 31, 2016:
ComEd
PECO
BGE
Pepco
DPL
ACE
Summer
peak date
7/20/2011
7/22/2011
7/21/2011
7/22/2011
7/22/2011
7/22/2011
Electric Peak Deliveries
(in GW)
Summer
deliveries
23.75
8.98
7.23
7.02
4.14
2.96
Winter peak
date
1/6/2014
1/7/2014
2/20/2015
2/20/2015
2/20/2015
1/7/2014
Natural Gas Peak Deliveries
(in mmcfs)
Winter
deliveries
16.51
7.17
6.71
6.07
4.11
1.8
Winter peak
date
n/a
2/15/2015
2/19/2015
n/a
2/15/2015
n/a
Winter
deliveries
n/a
777
777
n/a
186
n/a
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, pursuant to EIMA. 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 those customers that choose a
competitive electric generation or natural gas supplier, the Utility Registrants may act as the billing agent but do not record revenues or purchased
power and fuel expense related to the electricity and/or natural gas. For those customers that choose one of the Utility Registrants as their electric
generation or natural gas supplier, the Utility Registrants are permitted to recover electric and natural gas procurement costs from retail customers.
Therefore, fluctuations in electric and natural gas procurement costs have no impact on electric and natural gas revenues net of purchased power
and fuel expense.
The following table outlines the state regulatory agencies and default service obligations for each of the Utility Registrants:
ComEd
PECO
BGE
Pepco
DPL
ACE
Regulatory Agency
Default Service
Obligation-Electricity
Default Service
Obligation-Natural Gas
ICC
PAPUC
MDPSC
DCPSC/MDPSC
DPSC/MDPSC
NJBPU
24
POLR
DSP
SOS
SOS
SOS
BGS
n/a
PGC
MBR
n/a
n/a
n/a
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Retail customers participating in customer choice programs, and retail deliveries purchased from competitive electric generation and natural
gas suppliers (as a percentage of GWh and mmcf sales, respectively) for the Utility Registrants consisted of the following at December 31, 2016,
2015 and 2014:
Number of retail customers in
customer choice programs
Electric
1,502,900
587,200
337,000
176,372
78,994
94,562
Natural gas
n/a
81,300
151,000
n/a
156
n/a
December 31, 2016
% of total retail customers
Electric
38%
36%
27%
21%
15%
17%
Natural gas
n/a
16%
23%
n/a
0.1%
n/a
December 31, 2015
Customer choice program
deliveries as a % of retail sales
(for the year ended)
Electric
72%
70%
59%
65%
51%
47%
Natural gas
n/a
26%
57%
n/a
28%
n/a
Number of retail customers in
customer choice programs
% of total retail customers
Electric
1,655,400
563,400
343,000
173,222
77,603
78,299
Natural gas
n/a
81,100
154,000
n/a
159
n/a
Electric
42%
35%
27%
21%
15%
14%
Natural gas
n/a
16%
23%
n/a
0.1%
n/a
December 31, 2014
Number of retail customers in
customer choice programs
% of total retail customers
Electric
2,426,900
546,900
364,000
179,524
78,153
86,780
Natural gas
n/a
78,400
161,000
n/a
157
n/a
Electric
63%
34%
29%
22%
15%
16%
Natural gas
n/a
16%
25%
n/a
0.1%
n/a
Customer choice program
deliveries as a % of retail sales
(for the year ended)
Electric
76%
70%
61%
65%
51%
45%
Natural gas
n/a
25%
56%
n/a
31%
n/a
Customer choice program
deliveries as a % of retail sales
(for the year ended)
Electric
80%
70%
60%
65%
53%
51%
Natural gas
n/a
22%
53%
n/a
31%
n/a
ComEd
PECO
BGE
Pepco
DPL
ACE
ComEd (a)
PECO
BGE
Pepco
DPL
ACE
ComEd
PECO
BGE
Pepco
DPL
ACE
(a)
In September 2015, the City of Chicago discontinued its participation in the customer choice program and began purchasing its electricity from ComEd. Approximately
670,000 customers were impacted by the City of Chicago’s decision which resulted in the reduction in the number of customers participating in customer choice programs
in 2015.
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. Charges incurred for electric supply procured through contracts with Generation are included in Purchased power from affiliates on the
Utility Registrants’ Statements of Operations and Comprehensive Income.
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PECO’s, BGE’s and DPL’s natural gas supplies are purchased from a number of suppliers for terms of up to three years. PECO, BGE and
DPL have annual firm supply and transportation contracts of 132,000 mmcf, 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
DPL
Peak Natural Gas Sources (in mmcf)
Liquefied Natural
Gas Facility
1,200
1,056
257
Propane-Air Plant
150
550
n/a
Underground Storage
Service Agreements
(a)
18,000
22,000
3,800
(a) Natural gas from underground storage represents approximately 28%, 46% and 34% of PECO’s, BGE’s and DPL’s 2016-2017 heating season planned supplies,
respectively.
PECO, BGE and DPL have long-term interstate pipeline contracts and also participate in the interstate markets by releasing pipeline capacity
or bundling pipeline capacity with gas for off-system sales. Off-system gas sales are low-margin direct sales of gas to wholesale suppliers of natural
gas. Earnings from these activities are shared between the utilities and customers. PECO, BGE and DPL make these sales as part of a program to
balance its supply and cost of natural gas.
Energy Efficiency Programs. The Utility Registrants are also 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.
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 2017 are $2,200 million, $775 million, $925 million, $625 million, $375 million and $300 million, respectively.
ComEd, PECO, BGE, Pepco and DPL have AMI smart meter and smart grid deployment programs within their respective service territories to
enhance their distribution systems. PECO, BGE, Pepco and DPL have completed the installation and activation of smart meters in their respective
service territories. ACE has yet to receive approval from the NJBPU to proceed with the installation of AMI smart meters.
Transmission Services. The Utility Registrants provide unbundled transmission service under rates approved by FERC. Under FERC’s open
access transmission policy promulgated in Order No. 888, 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. 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 PJM region. The Utility Registrants
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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 network service transmission rates and the process for updating the formula rate calculation
on an annual basis.
PECO’s customers are charged for PECO’s PJM retail transmission services on a full and current basis through a Transmission Service
Charge (applicable to default service only) and through a Non-Bypassable Transmission Charge (applicable to all distribution customers) in
accordance with PECO’s approved distribution rates.
See Note 3 — Regulatory Matters, Note 26—Segment Information of the Combined Notes to Consolidated Financial Statements and ITEM 7.
MANAGEMENT’S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS, Liquidity and Capital Resources
for additional information regarding transmission services.
Employees
As of December 31, 2016, Exelon and its subsidiaries had 34,396 employees in the following companies, of which 11,984 or 35% were
covered by collective bargaining agreements (CBAs):
Generation (c)
ComEd
PECO
BGE (d)
PHI (e)
Pepco (e)
DPL (e)
ACE (e)
Other (f)
Total
IBEW Local 15
(a)
IBEW Local 614
(b)
1,640
3,777
—
—
—
—
—
—
65
5,482
99
—
1,310
—
—
—
—
—
—
1,409
Other CBAs
2,635
—
—
—
331
1,056
631
399
41
5,093
Total Employees
Covered by CBAs
4,374
3,777
1,310
—
331
1,056
631
399
106
11,984
Total
Employees
14,717
6,574
2,651
3,097
1,670
1,466
871
595
2,755
34,396
(a) A separate CBA between ComEd and IBEW Local 15 covers approximately 62 employees in ComEd’s System Services Group and was renewed in 2016. Generation’s
and ComEd’s separate CBAs with IBEW Local 15 will expire in 2022.
(b) 1,310 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 99 employees, which was renewed in 2016 and expiring in 2019.
(c) 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, Pepco Energy Services was allocated to Generation with a total of 358 employees broken down as follows: 229 employees covered by CBAs and 129
non-represented employees. 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 four Security Officer unions at Braidwood, Byron, Clinton and TMI, all expiring between 2018 and 2021, respectively. During 2014,
Generation finalized CBAs with TMI Local 777 and Oyster Creek Local 1289, expiring in 2019 and 2021, respectively and CENG finalized its CBA with Nine Mile Point
which will expire in 2020. Additionally, during 2014, Generation finalized CBAs with the Security Officer unions at Dresden, LaSalle, Limerick and Quad Cities, which
expire between 2017 and 2018. Lastly, during 2014, an agreement was negotiated with Las Vegas District Energy and IUOE Local 501, which will expire in 2018. During
2013, Generation finalized two 3-year agreements: New England ENEH, UWUA Local 369, which will expire in 2017.
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(d)
In January 2017, an election was held at BGE which resulted in union representation for approximately 1,400 employees. BGE and IBEW Local 410 will begin negotiations
for 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.
(e) PHI’s utility subsidiaries are parties to five collective bargaining agreements with four local unions. Collective bargaining agreements are generally renegotiated every
three to five years. All of these collective bargaining agreements were renegotiated in 2014 and were extended through various dates ranging from October 2018 through
June 2020
(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 regulations administered by the EPA and various
state and local environmental protection agencies. Federal, state and local regulation includes the authority to regulate air, water, and solid and
hazardous waste disposal.
The Exelon Board of Directors is responsible for overseeing the management of environmental matters. Exelon has a management team to
address environmental compliance and strategy, including the CEO; the Senior Vice President, Corporate Strategy and Chief Sustainability Officer;
the Corporate Environmental Strategy Director and the Environmental Regulatory Strategy Director, as well as senior management of Generation,
ComEd, PECO, BGE, 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
Corporate Governance Committee the authority to oversee Exelon’s compliance with laws and regulations and its strategies and efforts to protect
and improve the quality of the environment, including Exelon’s climate change and sustainability policies and programs, as discussed in further detail
below. The Exelon Board of Directors has also delegated to its Generation Oversight Committee the authority to oversee environmental, health and
safety issues relating to Generation. 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 in Illinois, Maryland, Massachusetts,
New York, Pennsylvania and Texas in accordance with the Federal Clean Air Act impose restrictions on emission of particulates, sulfur dioxide
(SO2), nitrogen oxides (NOx), mercury and other pollutants and require permits for operation of emissions sources. Such permits have been
obtained by Exelon’s subsidiaries and must be renewed periodically. The Clean Air Act establishes a comprehensive and complex national program
to substantially reduce air pollution from power plants.
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 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 Generation’s power generation
facilities
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discharge 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 certain
other state and regional agencies and compacts, including the Delaware River Basin Commission and the Susquehanna River Basin Commission.
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 any changes to the existing regulations. For Generation, those facilities are Calvert
Cliffs, Clinton, Dresden, Eddystone, Fairless Hills, Ginna, Gould Street, Handley, Mountain Creek, Mystic 7, Nine Mile Point Unit 1, Peach Bottom,
Quad Cities, Riverside and Salem.
On October 14, 2014, the EPA’s final 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.
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 by December 31, 2019, ten years before the expiration of its operating license in 2029.
The agreement only applies to Oyster Creek based on its unique circumstances and does not set any precedent for the ultimate compliance
requirements for Section 316(b) at Exelon’s other plants.
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. The Ginna and Nine Mile Point Unit 1 power generation facilities received renewals of their state water discharge permits in
2014.
Salem. In June 2001, the NJDEP issued a renewed NPDES permit for Salem, expiring in July 2006, allowing for the continued operation of
Salem with its existing cooling water system. In February 2006, PSEG filed a renewal application with the NJDEP allowing Salem to continue
operating under its existing NPDES permit until a new permit is issued. On June 30, 2015, NJDEP issued a draft NPDES permit for Salem. The draft
permit does not require installation of cooling towers and allows Salem to
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continue to operate utilizing the existing once-through cooling water system with certain required system modifications. On July 28, 2016, the NJDEP
issued a final permit for Salem that did not require the installation of cooling towers. However, the permit is being challenged by an environmental
organization, and if successful, could result in additional costs for Clean Water Act compliance.
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 into the environment 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, District
of Colombia, Illinois, Maryland, New Jersey and Pennsylvania, 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 are likely to become, 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 24—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, PECO’s and BGE’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. While BGE does not have a rider for MGP clean-up costs, BGE has
historically received recovery of actual clean-up costs on a site-specific basis in distribution rates. The amount to be expended in 2017 at Exelon for
compliance with environmental remediation related to contamination at former MGP sites and other gas purification sites is expected to total
$41 million, consisting of $35 million and $6 million respectively, at ComEd and PECO.
Generation’s environmental liabilities primarily arise from contamination at current and former generation and waste storage facilities. As of
December 31, 2016, Generation has established appropriate contingent liabilities for potential environmental remediation requirements including
contamination attributable to low level radioactive residues at a storage and reprocessing facility named Latty Avenue, and at a disposal facility
named West Lake Landfill, both near St. Louis, Missouri related to operations conducted by Cotter Corporation, a former ComEd subsidiary.
The Utility Registrants also have environmental liabilities for remediation considerations. As of December 31, 2016, Generation has
established appropriate contingent liabilities for potential environmental remediation requirements.
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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 Notes 3—Regulatory Matters and 24—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’ results of operations, cash
flows and financial positions.
Global Climate Change
Exelon has utility and generation assets, and customers, that are subject to the effects of climate change as described in the
Intergovernmental Panel on Climate Change (IPCC) 5th Assessment Report, published in 2014, Accordingly the company is engaged in a variety of
initiatives to better understand and develop responses to these issues, including investments in resiliency, partnering with federal, state and local
governments and advocating for science-based public policy. Exelon, as a producer of electricity from predominantly low-carbon generating facilities
(such as nuclear, hydroelectric, wind and solar photovoltaic), has a relatively small greenhouse gas (GHG) emission profile, or carbon footprint,
compared to other domestic generators of electricity. By virtue of its significant investment in low-carbon intensity assets, Generation’s emission
intensity, or rate of carbon dioxide equivalent (CO2e) emitted per unit of electricity generated, is among the lowest in the industry. Exelon does
produce GHG emissions, primarily at its fossil fuel-fired generating plants (primarily natural gas); CO2, methane and nitrous oxide are all emitted in
this process, with CO2 representing the largest portion of these GHG emissions. GHG emissions from combustion of fossil fuels represented the
majority of Exelon’s direct GHG emissions in 2016, although less than 30 percent of its owned generating capacity utilizes fossil fuels with less than
10 percent of owned generation MWh actually produced by fossil fuels as Exelon’s fossil-fired generation is primarily intermediate and peaking in
nature. Other GHG emission sources at Exelon include natural gas (methane) leakage on the natural gas systems, sulfur hexafluoride (SF6) leakage
in its electric transmission and distribution operations and refrigerant leakage from its chilling and cooling equipment as well as fossil fuel combustion
in its motor vehicles and fossil fuel generation of electricity used to power its facilities. Despite its focus on low-carbon generation, Exelon believes its
operations could be significantly affected by the possible physical risks of climate change and by mandatory programs to reduce GHG emissions.
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 climate change regulation or legislation at the Federal, regional and state
levels.
International Climate Change Regulation. 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. The Paris Agreement defines the UNFCCC’s objective of limiting the global temperature increase to 1.5°C
above pre-industrial levels. All Parties are required to develop their own national emission reductions and to update those reductions at least every
five years. The Developed Country Parties, including the United States, are required to take the lead by undertaking economy-wide absolute
emission reduction targets. The United States had previously submitted its national emission reductions to achieve a 2020 target of reducing net
emissions to 17% below the 2005 level and to achieve net greenhouse gas emission reductions of 26%—28% below the 2005 level by 2025. The
United States has indicated that it intends to achieve these reductions through a variety of mechanisms, including regulations to cut carbon pollution
from new and existing power plants. The Paris Agreement entered into force on November 4, 2016 the thirtieth day after the date on which at
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least 55 Parties accounting for at least an estimated 55% of total global greenhouse gas emissions ratified the Agreement. The Agreement has not
been ratified by the US Senate and it is uncertain whether or not or to what extent the new Trump Administration will pursue the established target.
Federal Climate Change Legislation and Regulation. It is highly uncertain that Federal legislation to reduce GHG emissions will be enacted. If
such legislation is adopted, Exelon may incur costs either to further limit or offset the GHG emissions from its operations or to procure emission
allowances or credits.
Under the Obama Administration, the EPA proposed and finalized regulations for new and modified fossil-fuel power plants under Section
111(b) of the Clean Air Act and Section 111(d) for existing fossil-fuel power plants. These regulations are currently being litigated. The 111(d)
regulations, referred to as the Clean Power Plan, are currently subject to a stay by the Supreme Court, pending conclusion of all litigation at both the
D.C. Circuit and Supreme Court levels. The D.C. Circuit heard en banc oral argument in late September 2016, but has not yet issued its decision.
Prior to the stay, the Clean Power Plan had established GHG emission reduction targets for each state, with emission reductions slated to begin in
2022. State requirements to submit plans to EPA in September 2016 (or within two years if an extension was requested) were placed in abeyance
pending results of litigation.
President Trump’s election platform called for eliminating a number of EPA regulations, including the Clean Power Plan. Due to the need to
appoint and confirm key EPA officials as the Trump Administration begins to govern, the specific details of the Trump Administration’s plans to
address the Clean Power Plan are not known. In the interim, the D.C. Circuit continues its review of the regulation under existing litigation and is
expected to issue its decision in the first half of 2017.
Due to current litigation and the need for the new Administration to develop its approach to dealing with the Clean Power plan, Exelon and
Generation cannot at this time predict the future of the Clean Power Plan or individual state responses to Clean Power Plan developments or how
developments will impact their future financial positions, results of operations and cash flows.
Regional and State Climate Change Legislation and Regulation. After a two-year program review, the nine northeast and mid-Atlantic states
currently participating in the Regional Greenhouse Gas Reduction Initiative (RGGI) released an updated RGGI Model Rule and Program Review
Recommendations Summary on February 7, 2013. Under the updated RGGI program the regional RGGI CO 2 budget was reduced, starting in 2014,
from its previous 165 million ton level to 91 million tons, with a 25 percent reduction in the cap level each year from 2015 through 2020. Included in
the program are provisions for cost containment reserve (CCR) allowances, which will become available if the total demand for allowances, above
the CCR trigger price, exceeds the number of CO 2 allowances available for purchase at auction. (CCR trigger prices are $6 in 2015, $8 in 2016 and
$10 in 2017; after 2017 the CCR price increases by 2.5 percent each year). Allowance prices in 2016 remained below the applicable CCR trigger
price, indicating program costs remained within the boundaries of costs acceptable to participating states. During 2016, RGGI began its quadrennial
review process to determine what, if any, program design amendments should be pursued for the regional program. A series of stakeholder calls
occurred in 2016, which included discussion around potential linkage issues with the federal Clean Power Plan, linkages to state GHG emission
reduction goals/programs, functioning of cost containment mechanisms, and consideration of whether future cap levels should be adjusted for the
post-2020 period. RGGI intends to complete its program review in early 2017.
On December 18, 2009, Pennsylvania issued the state’s final Climate Change Action Plan. The plan sets as a target a 30 percent reduction in
GHG emissions by 2020. The Climate Change Advisory Committee continues to meet quarterly to review Climate Action Work Plans for the
residential, commercial and industrial sectors. The Climate Change Action Plan does not impose any requirements on Generation or PECO at this
time.
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The Maryland Commission on Climate Change was chartered in 2007 and released a greenhouse gas reduction strategy with 42
recommendations on August 27, 2008. The plan’s primary policy recommendation to formally adopt science-based regulatory goals to reduce
Maryland’s green house gas emissions (GHG) was realized with the passage of the Greenhouse Gas Emissions Reduction Act of 2009 (GGRA)
which required Maryland to reduce its GHG emissions by 25 percent below 2006 levels by 2020. It also directed the Maryland Department of
Environment to prepare and implement an action plan which listed Maryland’s electricity consumption reduction goals, required under the
“EmPOWER Maryland” program, and mandatory State participation in RGGI Program, as the energy sector’s contribution to the plan. In April 2016,
the Governor of Maryland signed the GGRA of 2016 into law, which updated the state’s Climate Commission charter. It expanded membership to
include more non-governmental members and established an enhanced statewide GHG emissions reduction target of 40 percent from 2006 levels
by 2030, maintaining the caveats from the 2007 legislation that the implementation have a net positive impact on both jobs and the economy. MDE is
currently working on plans to meet the 2016 GGRA requirements. In February of this year (2017) , the Maryland General Assembly overrode
Maryland Governor Hogan’s veto of legislation that requires the current Renewable Portfolio Standard (RPS) to be accelerated and enhanced. The
law requires the RPS, previously set at 20% renewables by 2022, with a 2% solar carve out, to move to 25% renewables by 2020 with a 2.5% solar
carve out.
Exelon’s Voluntary Climate Change Efforts . In a world increasingly concerned about global climate change and regulatory action to reduce
GHG, Exelon’s low-carbon generating fleet is seen by management as a competitive advantage. Exelon remains one of the largest, lowest carbon
electric generators in the United States: nuclear for base load, natural gas for marginal and peak demand, hydro and pumped storage, and
supplemental wind and solar renewables. As further legislation and regulation imposing requirements on emissions of GHG and air pollutants are
promulgated, Exelon’s low-carbon, low-emission generation fleet will position the company to benefit from its comparative advantage over other
generation fleets.
Renewable and Alternative Energy Portfolio Standards
Thirty-nine states and the District of Columbia have adopted some form of RPS requirement. Illinois, Pennsylvania, Maryland, the District of
Columbia, Delaware and New Jersey have laws specifically addressing energy efficiency and renewable energy initiatives. In addition to state level
activity, RPS legislation has been considered and may be considered again in the future by the United States Congress. Also, states that currently
do not have RPS requirements may adopt such legislation in the future.
In Illinois, in accordance with legislation in effect on December 31, 2016, the IPA’s Procurement Plans include the procurement of cost-
effective renewable energy resources in amounts that equal or exceed a minimum target percentage of the total electricity that each electric utility
supplies to its eligible retail customers. The June 1, 2016 target renewable energy resources obligation for the utilities was at least 11.5%. This
obligation increases by at least 1.5% each year thereafter to an ultimate target of at least 25% by June 1, 2025. All goals are subject to rate impact
criteria set forth by Illinois legislation. As of December 31, 2016, ComEd had purchased renewable energy resources or equivalents, such as RECs,
in accordance with the IPA Procurement Plan. ComEd currently retires all RECs upon transfer and acceptance. ComEd is permitted to recover
procurement costs of RECs from retail customers without mark-up through rates.
In accordance with FEJA that takes effect on June 1, 2017, beginning with the plan or plans to be implemented in the 2017 delivery year, the
IPA shall develop a long term renewable resources procurement plan (LT Plan). The RPS target percentages for the overall service territory have
not changed through June 1, 2025 (11.5% of retail load by June 1 2016 growing to 25% by June 1 2025) although FEJA extended the 25% RPS
target to delivery years after 2025. Currently, each Retail
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Electric Supplier and each utility is responsible for the renewable resource obligation for the customers to which it supplies power. Over time, this will
change and the utility will procure renewable resources based on the retail load of substantially all customers in its service territory. For the delivery
year beginning June 1, 2017, the LT Plan shall include cost effective renewable energy resources procured by the utility for the retail load the utility
supplies and for 50% of the retail customer load supplied by Retail Electric Suppliers in the utility service territory on February 28, 2017. Utility
procurement for RES supplied retail customer load will increase to 75% June 1, 2018 and to 100% beginning June 1, 2019.
Originally passed November 30, 2004 the AEPS Act became effective for PECO on January 1, 2011. During 2016, PECO was required to
supply approximately 5.5% of electric energy generated from Tier I alternative energy resources (including solar, wind power, low-impact
hydropower, geothermal energy, biologically derived methane gas, fuel cells, biomass energy, coal mine methane and black liquor generated within
Pennsylvania), as measured in AECs, through May 31, 2016 and subsequently 6.0% beginning June 1, 2016 and continuing through May 31, 2017.
PECO is also required to supply 8.2% of electric energy generated from Tier II alternative energy resources (including waste coal, demand-side
management, large-scale hydropower, municipal solid waste, generation of electricity utilizing wood and by-products of the pulping process and
wood, distributed generation systems and integrated combined coal gasification technology), as measured in AECs, effective June 1, 2015 and
continuing through May 31, 2020. The compliance requirements will incrementally escalate to 8.0% for Tier I and 10.0% for Tier II by 2021. In order
to comply with these requirements, PECO purchases its AECs through its DSP Program full requirement contracts with various counterparties,
including Generation. PECO also obtains AECs of Solar Tier I annually from long term agreements with various counterparties, including Generation,
and balancing amounts of Tier 1 non-solar and Tier II through broker purchases.
Section 7-703 of the Public Utilities Article in Maryland sets forth the RPS requirement, which applies to all retail electricity sales in Maryland
by electricity suppliers. The RPS requirement requires that suppliers obtain a specified percentage of the electricity it sells from Tier 1 sources (solar,
wind, biomass, methane, geothermal, ocean, fuel cell, small hydroelectric, and poultry litter) and Tier 2 sources (hydroelectric, other than pump
storage generation, and waste-to-energy). The RPS requirement began in 2006, requiring that suppliers procure 1.0% and 2.5% from Tier 1 and
Tier 2 sources, respectively, escalating in 2022 to 22.0% from Tier 1 sources, including at least 2.0% from solar energy, and a phase out of Tier 2
resource options by 2022. In 2015, 10.5% was required from Tier 1 renewable sources, including at least 0.5% derived from solar energy and 2.5%
from Tier 2 renewable sources. BGE, Pepco and DPL are subject to requirements established by the Public Utilities Article in Maryland related to the
use of alternative energy resources. In addition, the wholesale suppliers that supply power to BGE, Pepco and DPL through SOS procurement
auctions have the obligation, by contract with BGE, Pepco and DPL, to meet the RPS requirements.
Section 34-1432 of the D.C. Code sets forth the RPS requirement, which applies to all retail electricity sales in the District of Columbia by
electricity suppliers. The RPS requirement requires that suppliers obtain a specified percentage of the electricity it sells from Tier 1 sources (solar,
wind, certain qualifying biomass, methane from anaerobia decomposition of organic materials in landfill or wastewater treatment plant, geothermal,
ocean, and fuel cell) and Tier 2 sources (hydroelectric (other than pumped storage generation), certain qualifying biomass and waste-to-energy).
The RPS requirement began in 2007, with standards increasing annually. For 2017, the RPS requires that suppliers procure 13.1% and 2.5% from
Tier 1 and Tier 2 sources, respectively, with not less than 0.95% solar, and escalating in 2023 to 20.0% from Tier 1 sources, including at least 2.5%
from solar energy, and a phase out of Tier 2 resource options. In 2015 the law was amended to extend the RPS requirements to 2032, at which time
not less than 50% is required from Tier 1 renewable sources, including at least 5.0% derived from solar energy. Tier 2 renewable sources remain
phased out. The wholesale suppliers that supply power to Pepco through SOS procurement auctions have the obligation, by contract with Pepco, to
meet the RPS requirements.
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Title 26 of the Delaware Code sets forth the RPS requirement, which applies to retail electricity sales in Delaware by electricity suppliers. The
RPS requirement requires that DPL obtain a specified percentage of the electricity it delivers to its eligible customers from eligible energy resources
(solar electric, wind, ocean tidal, ocean thermal, fuel cells powered by renewable fuels, hydroelectric facilities with a maximum capacity of 30 MW,
sustainable biomass, anaerobic digestion and landfill gas). The RPS requirement, beginning in 2007, required that suppliers procure 2.0% from
eligible energy resources, with not less than 0.011% from solar, and escalating annually through 2025, at which time suppliers must procure 25.0%
from eligible energy resources, including at least 3.5% from solar. As of December 31, 2016, DPL is a party to three land-based wind power
purchase agreements in the aggregate amount of 128 MWs (nameplate capacity). DPL has contracted for approximately 48 MW of Solar Renewable
Energy Credits (SRECs) through a combination of long term SREC purchase agreements with solar facilities, SREC Purchase agreements with the
Delaware Sustainable Energy Utility and the DE SREC Procurement Program. On October 18, 2011, the DPSC approved a tariff submitted by DPL
in accordance with the requirements of the RPS specific to a fuel cell facility totaling 30 MWs to be constructed by a qualified fuel cell provider. The
tariff and the RPS establish that DPL acts solely as an agent to collect payments in advance from its distribution customers and remit them to the
qualified fuel cell provider for each MWh of energy produced by the fuel cell facilities through 2033. The qualified fuel cell provider output reduces the
non-solar and/or solar requirements needed to satisfy the Delaware RPS obligations.
The Electric Discount and Energy Competition Act, (“EDECA”), was signed into law in 1999, and includes the requirement for compliance with
New Jersey’s RPS by electric power suppliers and providers of BGS. The RPS requires that electric power suppliers obtain a specified percentage
of the electricity they sell from Class I sources (solar, wind, wave/tidal action, geothermal, methane captured from landfills, fuel cells with certain
types of power sources, and biomass) and Class II sources (hydroelectric facilities with a combined design capacity of less than 30 MW, and certain
resource recovery facilities). In 2010, the Solar Energy Advancement and Fair Competition Act, (“SEAFCA”), was signed into law. SEAFCA
amended several provisions of EDECA, among them the manner in which suppliers were to comply with the solar portion of the RPS. SEAFCA,
beginning in energy year 2011, set out a specific requirement for solar energy generation. The Solar Act of 2012 made further changes effective for
energy year 2014 and beyond. The RPS requirement has changed over time. For energy year 2005, suppliers were required to procure 0.74% and
2.5% from Class I and Class II sources, respectively. For the most recently completed energy year 2016, 9.649% was required from Class I
renewable sources, 2.5% from Class II renewable sources, and 2.75% from solar energy. As noted above, the RPS applies to each supplier or
provider that sells electricity to retail customers in New Jersey. Pursuant to Section 14:4-1.2 of the New Jersey Administrative Code, electric public
utilities, such as ACE, that provide electric generation services only for the purpose of providing BGS are not electric power suppliers and so are not
subject to the RPS procurement requirements.
Similar to ComEd, PECO, BGE, Pepco, DPL and ACE, Generation’s retail electric business must source a portion of the electric load it serves
in many of the states in which it does business from renewable resources or approved equivalents such as RECs. Potential regulation and legislation
regarding renewable and alternative energy resources could increase the pace of development of wind and other renewable/alternative energy
resources, which could put downward pressure on wholesale market prices for electricity in some markets where Exelon operates generation assets.
At the same time, such developments may present some opportunities for sales of Generation’s renewable power, including from wind, solar,
hydroelectric and landfill gas.
See Note 3—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 13, 2017
Exelon
Name
Crane, Christopher M.
Age Position
58 Chief Executive Officer, Exelon
Chairman, ComEd, PECO & BGE
Chairman, PHI
President, Exelon
President, Generation
Chief Operating Officer, Exelon
Cornew, Kenneth W.
51 Senior Executive Vice President and Chief Commercial Officer, Exelon;
O’Brien, Denis P.
President and CEO, Generation
Executive Vice President and Chief Commercial Officer, Exelon
President and Chief Executive Officer, Constellation
Senior Vice President, Exelon; President, Power Team
56
Senior Executive Vice President, Exelon; Chief Executive Officer, Exelon
Utilities
Vice Chairman, ComEd, PECO, BGE
Vice Chairman, PHI
Chief Executive Officer, PECO; Executive Vice President, Exelon
President and Director, PECO
Pramaggiore, Anne R.
58 Chief Executive Officer, ComEd
Adams, Craig L.
Butler, Calvin G.
President, ComEd
Chief Operating Officer, ComEd
64 President and Chief Executive Officer, PECO
Senior Vice President and Chief Operating Officer, PECO
47 Chief Executive Officer, BGE
Senior Vice President, Regulatory and External Affairs, BGE
Senior Vice President, Corporate Affairs, Exelon
Velazquez, David M.
57 President and Chief Executive Officer, PHI
Von Hoene Jr., William A.
63 Senior Executive Vice President and Chief Strategy Officer, Exelon
Executive Vice President, Finance and Legal, Exelon
Thayer, Jonathan W.
45 Senior Executive Vice President and Chief Financial Officer, Exelon
President and Chief Executive Officer, Pepco, DPL and ACE
Executive Vice President, Pepco Holdings, Inc.
Aliabadi, Paymon
54 Executive Vice President and Chief Enterprise Risk Officer, Exelon
DesParte, Duane M.
Managing Director, Gleam Capital Management
53 Senior Vice President and Corporate Controller, Exelon
Senior Vice President and Chief Financial Officer, Constellation Energy;
Treasurer, Constellation Energy
36
Period
2012 - Present
2012 - Present
2016 - Present
2008 - Present
2008 - 2013
2008 - 2012
2013 - Present
2013 - Present
2012 - 2013
2012 - 2013
2008 - 2012
2012 - Present
2012 - Present
2016 - Present
2007 - 2012
2003 - 2012
2012 - Present
2009 - Present
2009 - 2012
2012 - Present
2007 - 2012
2014 - Present
2013 - 2014
2011 - 2013
2016 - Present
2009 - Present
2009 - 2016
2012 - Present
2009 - 2012
2012 - Present
2008 - 2012
2013 - Present
2012 - 2013
2008 - Present
Table of Contents
Generation
Name
Cornew, Kenneth W.
Age Position
51 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
Senior Vice President, Exelon; President, Power Team
Period
2013 - Present
2013 - Present
2012 - 2013
2012 - 2013
2008 - 2012
Pacilio, Michael J.
56 Executive Vice President and Chief Operating Officer, Exelon Generation 2015 - Present
Hanson, Bryan C.
President, Exelon Nuclear; Senior Vice President and Chief Nuclear
Officer, Generation
2010 - 2015
Chief Operating Officer, Exelon Nuclear
51
President and Chief Nuclear Officer, Exelon Nuclear; Senior Vice
President, Exelon Generation
2015 - Present
Nigro, Joseph
52 Executive Vice President, Exelon; Chief Executive Officer, Constellation 2013 - Present
Senior Vice President, Portfolio Management and Strategy
Vice President, Structuring and Portfolio Management, Exelon Power
Team
DeGregorio, Ronald
54 Senior Vice President, Generation; President, Exelon Power
Chief Integration Officer, Exelon
Wright, Bryan P.
50 Senior Vice President and Chief Financial Officer, Generation
Bauer, Matthew N.
Senior Vice President, Corporate Finance, Exelon
Chief Accounting Officer, Constellation Energy
Vice President and Controller, Constellation Energy
40 Vice President and Controller, Generation
Vice President and Controller, BGE
Vice President of Power Finance, Exelon Power
Director, FP&A and Retail, Constellation
Executive Director, Corporate Development, Constellation
37
2012 - 2013
2010 - 2012
2012 - Present
2011 - 2012
2013 - Present
2012 - 2013
2009 - 2012
2008 - 2012
2016 - Present
2014 - 2016
2012 - 2014
2012 - 2012
2009 - 2012
Table of Contents
ComEd
Name
Pramaggiore, Anne R.
Age Position
58 Chief Executive Officer, ComEd
President, ComEd
Chief Operating Officer, ComEd
Donnelly, Terence R.
56 Executive Vice President and Chief Operating Officer, ComEd
Trpik Jr., Joseph R.
Jensen, Val
Gomez, Veronica
Executive Vice President, Operations, ComEd
47 Senior Vice President, Chief Financial Officer and Treasurer, ComEd
61 Senior Vice President, Customer Operations, ComEd
Vice President, Marketing and Environmental Programs, ComEd
47
Senior Vice President, Regulatory and Energy Policy and General
Counsel, ComEd
Vice President and Deputy General Counsel, Litigation, Exelon
Marquez Jr., Fidel
55 Senior Vice President, Governmental and External Affairs, ComEd
Brookins, Kevin B.
55 Senior Vice President, Strategy & Administration, ComEd
Senior Vice President, Customer Operations, ComEd
Period
2012 - Present
2009 - Present
2009 - 2012
2012 - Present
2009 - 2012
2009 - Present
2012 - Present
2008 - 2012
2017 - Present
2012 - 2017
2012 - Present
2009 - 2012
2012 - Present
Vice President, Operational Strategy and Business Intelligence, ComEd 2010 - 2012
McGuire, Timothy M.
58 Senior Vice President, Distribution Operations, ComEd
Vice President, Transmission and Substations, ComEd
Kozel, Gerald J.
44 Vice President, Controller, ComEd
Assistant Corporate Controller, Exelon
Director of Financial Reporting and Analysis, Exelon
38
2016 - Present
2010 - 2016
2013 - Present
2012 - 2013
2009 - 2012
Table of Contents
PECO
Name
Adams, Craig L.
Barnett, Phillip S.
Age Position
64 President and Chief Executive Officer, PECO
Senior Vice President and Chief Operating Officer, PECO
53 Senior Vice President and Chief Financial Officer, PECO
Treasurer, PECO
Innocenzo, Michael A.
51 Senior Vice President and Chief Operations Officer, PECO
Vice President, Distribution System Operations and Smart Grid/Smart
Meter, PECO
Webster Jr., Richard G.
55 Vice President, Regulatory Policy and Strategy, PECO
Murphy, Elizabeth A.
Jiruska, Frank J.
Diaz Jr., Romulo L.
Bailey, Scott A.
Director of Rates and Regulatory Affairs
57 Senior Vice President, Governmental and External Affairs, PECO
Vice President, Governmental and External Affairs, PECO
Director, Governmental & External Affairs, PECO
56 Vice President, Customer Operations, PECO
70 Vice President and General Counsel, PECO
Vice President, Governmental and External Affairs, PECO
40 Vice President and Controller, PECO
Assistant Controller, Generation
39
Period
2012 - Present
2007 - 2012
2007 - Present
2012 - Present
2012 - Present
2010 - 2012
2012 - Present
2007 - 2012
2016 - Present
2012 - 2016
2007 - 2012
2013 - Present
2012 - Present
2009 - 2012
2012 - Present
2011 - 2012
Table of Contents
BGE
Name
Butler, Calvin G.
Age Position
47 Chief Executive Officer, BGE
Senior Vice President, Regulatory and External Affairs, BGE
Senior Vice President, Corporate Affairs, Exelon
Woerner, Stephen J.
49 President, BGE
Case, Mark D.
55 Vice President, Strategy and Regulatory Affairs, BGE
Senior Vice President, Strategy and Regulatory Affairs, BGE
Chief Operating Officer, BGE
Senior Vice President, BGE
Vice President and Chief Integration Officer, Constellation Energy
Period
2014 - Present
2013 - 2014
2011 - 2013
2014 - Present
2012 - Present
2009 - 2014
2011 - 2012
2012 - Present
2007 - 2012
Biagiotti, Robert D.
47 Vice President, Customer Operations and Chief Customer Officer, BGE 2015 - Present
Gahagan, Daniel P.
Vahos, David M.
Vice President, Gas Distribution, BGE
63 Vice President and General Counsel, BGE
44 Senior Vice President, Chief Financial Officer and Treasurer, BGE
Vice President, Chief Financial Officer and Treasurer, BGE
Vice President and Controller, BGE
Executive Director, Audit, Constellation
Holmes, Andrew W.
48 Vice President and Controller, BGE
Núñez, Alexander G.
Director, Generation Accounting, Exelon
Director, Derivatives and Technical Accounting, Exelon
45 Senior Vice President, Regulatory and External Affairs, BGE
Vice President, Governmental and External Affairs, BGE
Director, State Affairs, BGE
40
2011 - 2015
2007 - Present
2016 - Present
2014 - 2016
2012 - 2014
2010 - 2012
2016 - Present
2013 - 2016
2008 - 2013
2016 - Present
2013 - 2016
2012 - 2013
Table of Contents
PHI, Pepco, DPL and ACE
Name
Velazquez, David M.
Age Position
57 President and Chief Executive Officer, PHI
Anthony, J. Tyler
Kinzel, Donna J.
Bonney, Paul R.
Parker, Kenneth J.
52
49
58
54
Executive Vice President, Pepco Holdings, Inc.
President and Chief Executive Officer, Pepco, DPL and ACE
Senior Vice President and Chief Operating Officer, PHI, Pepco, DPL and
ACE
Senior Vice President, Distribution Operations, ComEd
Senior Vice President and Chief Financial Officer, PHI, Pepco, DPL and
ACE
Vice President, Treasurer and Chief Risk Officer, Pepco Holdings
Senior Vice President, Legal and Regulatory Strategy, PHI, Pepco, DPL
and ACE
Senior Vice President and General Counsel, Constellation Energy
2012 - 2016
Senior Vice President, Governmental and External Affairs, PHI, Pepco,
DPL and ACE
Senior Vice President, Government Affairs and Corporate Citizenship,
Pepco Holdings, Inc.
Stark, Wendy E.
44 Vice President and General Counsel, PHI, Pepco DPL and ACE
McGowan, Kevin M.
Aiken, Robert M.
ITEM 1A.
RISK FACTORS
Deputy General Counsel, Pepco Holdings, Inc.
55 Vice President, Regulatory Policy and Strategy
Vice President, Regulatory Affairs, Pepco Holdings, Inc.
50 Vice President and Controller, PHI, Pepco, DPL and ACE
Vice President and Controller, Generation
Executive Director and Assistant Controller, Constellation
Period
2016 - Present
2009 - 2016
2009 - Present
2016 - Present
2010 - 2016
2016 - Present
2012 - Present
2016 - Present
2016 - Present
2012 - 2016
2016 - Present
2012 - Present
2016 - Present
2012 - 2016
2016 - Present
2012 - 2016
2011 - 2012
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 Enterprise Risk Officer and the RMC, which comprises officers
of the Registrants, to identify and evaluate the most significant risks of the Registrants’ businesses and the appropriate steps to manage and
mitigate those risks. The Chief Enterprise 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’ results of operations or cash flows 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.
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Exelon’s financial condition and results of operations 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, 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
financial condition and results of operations 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, and (4) the impacts of on-going competition in the retail channel.
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 cost recovery 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, 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 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 and
safety of its energy delivery systems are fundamental to Exelon’s ability to protect and grow shareholder value. Additionally, the operating
costs of the Utility Registrants and the opinions of their customers and regulators, are affected by those companies’ ability to maintain the
reliability and safety of their energy delivery systems.
•
Risks Related to the PHI Merger. Exelon is subject to additional risks related to the merger with PHI that closed on March 23, 2016.
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 results of
operations or cash flows. (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 subject to variability of spot and forward market prices in the markets in which it operates rise and fall.
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. Often, the next unit of electricity will be supplied from generating stations fueled by fossil fuels. Consequently, changes in the market
price of fossil fuels often result in comparable changes to the market price of power. For example, the use of new technologies to recover natural gas
from shale deposits has increased natural gas supply and reserves, placing downward pressure on natural gas
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prices and, therefore, on power prices. The continued addition of supply from new alternative generation resources, such as wind and solar, whether
mandated through RPS or otherwise subsidized or encouraged through climate legislation or regulation, could displace a higher marginal cost plant,
further reducing power prices. In addition, further delay or elimination of EPA air quality regulations could prolong the duration for which the cost of
pollution from fossil fuel generation is not factored into market prices.
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. The result is that higher-cost generating resources do not run as frequently, putting downward pressure on electricity market
prices. The tepid economic environment in recent years and growing energy efficiency and demand response initiatives have limited the demand for
electricity in Generation’s markets. In addition, in some markets, the supply of electricity through wind or solar generation, when combined with other
base-load generation such as nuclear, could often exceed demand during some hours of the day, resulting in loss of revenue for base-load
generating plants. Increased supply in excess of demand is furthered by the continuation of RPS mandates and subsidies for renewable energy.
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 results of operations or
cash flows, 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
other discretionary uses of cash such as growth projects or to pay dividends. 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. A slow recovery in market conditions could result in a prolonged depression of or further decline in commodity prices,
including low forward natural gas and power prices and low market volatility, which could also adversely affect Exelon’s and Generation’s results of
operations, cash flows or financial position. See Note 9—Early Nuclear 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
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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 shale gas development or sources, cost-effective renewable energy
technologies, broad consumer adoption of electric vehicles, distributed generation and energy storage devices. Such developments could affect the
price of energy, could affect energy deliveries as customer-owned generation becomes more cost-effective, could require further improvements to
our distribution systems to address changing load demands and could 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’ results of operations, cash flows or financial position
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
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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 results of
operations and financial position 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, their results of operations,
cash flows or financial position 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’ results of operations, cash flows or financial position. (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. Disruptions in the European markets could reduce
or restrict the Registrants’ ability to secure sufficient liquidity or secure liquidity at reasonable terms. As of December 31, 2016, approximately 23%,
or $2.2 billion of the Registrants’ available credit facilities were with European banks. The credit facilities include $9.5 billion in aggregate total
commitments of which $7.9 billion was available as of December 31, 2016. As of December 31, 2016, there was $75 million of borrowings under
Generation’s bilateral credit facilities. See Note 14—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 results of operations or cash flows.
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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 rights to foreclose against the project assets and related collateral.
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 liquidity. 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.
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-
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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 Liquidity and Capital Resources—Recent Market Conditions and Security Ratings for further 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 results of operations or cash flows 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 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, operating results, cash flows or financial position.
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.
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 and 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 negatively impact the Registrants’ results of operations or cash flows. (All Registrants)
Potential Corporate Tax Reform. The results of the November 2016 U.S. elections have introduced greater uncertainty with respect to
federal tax policies. President Trump has stated that one of his top priorities is comprehensive tax reform and House Republicans plan to advance
their tax reform “blueprint”. Tax reform proposals call for a reduction in the corporate federal income tax rate from the current 35% to as low as
15%. Other proposals provide, among other items, for the immediate deduction of capital investment expenditures and full or partial elimination of
debt interest expense deductions. It is uncertain whether, to what extent or when these or any other changes in federal tax policies will be enacted or
the transition time frame for such changes. Further, for the Utility Registrants, regulators may impose rate reductions to provide the benefit of any
income tax expense reductions to customers and refund “excess” deferred income taxes previously collected through rates. The amounts and timing
of any such rate changes would be subject to the discretion of the rate regulator in each specific jurisdiction. For these reasons, the Registrants
cannot predict the impact any potential changes may have on their future results of operations, cash flows or financial position, and such changes
could be material.
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 appeals 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 Notes 1—Significant Accounting Policies and Note 15—Income Taxes of the Combined Notes to Consolidated
Financial Statements for additional information.
Increases in customer rates 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 or cash flows. (All Registrants)
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, 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. For DPL, purchased natural gas costs are charged to customers using a GCR mechanism that compares the actual
cost of gas to a forecasted amount. The difference between the actual cost and the forecast is fully recoverable and carried forward as a recovery
balance in the next GCR filing. 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 effect on the Registrants’ results of operations or cash flows. Also, the Utility Registrants’ cash flows could be affected by
differences between the time period when electricity and natural gas are purchased and the ultimate recovery from customers.
Further, 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
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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 impact the Utility Registrants’ results of operations or cash flows. 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 results of operations or cash flows. See ITEM 7A. QUANTITATIVE AND
QUALITATIVE DISCLOSURES ABOUT MARKET RISK for further discussion of the Registrants’ credit risk.
The effects of weather could impact the Registrants’ results of operations or cash flows. (All Registrants)
Weather conditions directly influence the demand for electricity and natural gas and affect the price of energy commodities. Temperatures
above normal levels in the summer tend to increase summer cooling electricity demand and revenues, and temperatures below normal levels in the
winter tend to increase winter heating electricity and gas demand and revenues. Moderate temperatures adversely affect the usage of energy and
resulting revenues at ComEd, PECO, DPL and ACE. Due to revenue decoupling, BGE, Pepco and DPL 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 Illinois FEJA signed into law on December 2016 and effective in 2017, ComEd can eliminate the
favorable or unfavorable impacts of weather or load on its electric distribution revenues by either (1) revising its electric distribution formula rate to
eliminate the ROE collar beginning with the reconciliation performed for the 2017 calendar year or (2) implementing a decoupling tariff if the electric
distribution formula rate were to be terminated at anytime.
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 on the Utility Registrants’ results of operations or cash flows. 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. Specifically, long-lived assets
account for 62%, 54%, 68%, 70%, 81%, 76%, 79% and 73% of total assets for Exelon, Generation, ComEd, PECO, BGE, Pepco, DPL and ACE,
respectively, as of December 31, 2016. In addition, Exelon and Generation have significant balances related to unamortized energy contracts, as
further disclosed in Note 11—Intangible Assets of the Combined Notes to Consolidated Financial Statements. The Registrants evaluate the
recoverability of
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the carrying value of long-lived assets to be held and used whenever events or circumstances indicating a potential impairment exist. Factors such
as 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 on the Registrants’ results of operations.
As of December 31, 2016, 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 and Note 7—Property, Plant and Equipment, Note 8—Impairment of Long Lived Assets and Note 11—Intangible
Assets of the Combined Notes to the Consolidated Financial Statements for additional discussion on long-lived asset and goodwill impairments.
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 on the operating results, financial condition,
or cash flows 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 asset and a Registrant could incur substantial costs to fulfill its obligations under these indemnities.
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
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Registrant could be held responsible for the obligations, which could impact that Registrant’s results of operations, cash flows or financial position. In
connection with Exelon’s 2001 corporate restructuring, Generation assumed certain of ComEd’s and PECO’s rights and obligations with respect to
their former generation businesses. Further, ComEd and PECO may have entered into agreements with third parties under which the third-party
agreed to indemnify ComEd or PECO 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 or Generation experienced events that reduced its creditworthiness or the indemnity
arrangement became unenforceable, ComEd or PECO could be liable for any existing or future claims, which could impact ComEd’s or PECO’s
results of operations, cash flows or financial position.
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 operations or financial results. 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 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 operating results and cash flows are significantly affected by Generation’s sale of power at market-based rates, as
opposed to cost-based or other similarly regulated rates, and Exelon’s and the Utility Registrants’ operating results and cash flows are heavily
dependent on the ability of the Utility Registrants to recover their costs for the retail purchase and distribution of power 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 results of
operations, cash flows or financial position.
Regulatory and legislative developments related to climate change and RPS could also significantly affect Exelon’s and Generation’s results of
operations, cash flows or financial position. Various legislative and regulatory proposals to address climate change through GHG emission
reductions, if enacted, could result in increased costs to entities that generate electricity through carbon-emitting fossil fuels, which could increase
the market price at which all generators in a region, including Generation, could sell their output, thereby increasing the revenue Generation could
realize from its low-carbon nuclear assets. However, national regulation or legislation addressing climate change through an RPS could also
increase the pace of development of wind energy facilities in the Midwest, which could put downward pressure on wholesale market prices for
electricity from Generation’s Midwest nuclear assets, partially offsetting any additional value Exelon and Generation might derive from Generation’s
nuclear assets under a carbon constrained regulatory regime that might exist in the future. Similarly, final regulations under Section 111(d) of the
Clean Air Act may not provide sufficient incentives for states to utilize carbon-free nuclear power as a means of meeting greenhouse gas emission
reduction requirements, while continuing a policy of favoring renewable energy sources. Current state level climate change and renewable regulation
is already providing incentives for regional wind development. The Registrants cannot predict when or whether any of these various legislative and
regulatory proposals could become law or what their effect will be on the Registrants.
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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)
Federal and state legislative and regulatory bodies are facing pressures to address consumer concerns, or are themselves raising concerns,
that energy prices in wholesale markets are too high or insufficient generation is being built because the competitive model is not working and,
therefore, are considering some form of re-regulation or some other means of reducing wholesale market prices or subsidizing new generation.
Generation is dependent on robust and competitive wholesale energy markets to achieve its business objectives.
Approximately 65% 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, such as PJM’s, and (2) the absence of material
changes to market structures that would limit or otherwise negatively affect market competitiveness. Generation could also be adversely affected by
state laws, regulations or initiatives designed to reduce wholesale prices artificially below competitive levels or to subsidize new generation, such as
the subsequently dismissed New Jersey Capacity Legislation and the MDPSC’s RFP for new gas-fired generation in Maryland. See Note 3—
Regulatory Matters of the Combined Notes to Consolidated Financial Statements for further details related to the New Jersey Capacity Legislation
and the Maryland new electric generation requirements.
In addition, FERC’s application of its Order 697 and its subsequent revisions could pose a risk that Generation will have difficulty satisfying
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 applies to
Exelon is Title VII, which is known as the Dodd-Frank Wall Street Transparency and Accountability Act (Dodd-Frank). Dodd-Frank requires the
creation of 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. For non security-
based swaps including commodity swaps, Dodd-Frank empowers the Commodity Futures Trading Commission (CFTC) to promulgate regulations
implementing the law’s objectives. The primary aim of Dodd-Frank is to regulate the key intermediaries in the swaps market, which entities are either
swap dealers (SDs), major swap participants (MSPs), and certain other financial entities, but the law also applies to a lesser degree to end-users of
swaps. On January 12, 2015, President Obama signed into law a bill that exempts from margin requirements swaps used by end-users to hedge or
mitigate commercial risk. Moreover, the CFTC’s Dodd-Frank regulations preserve the ability of end users in the energy industry to hedge their risks
using swaps without being subject to mandatory clearing, and accepts or exempts end-users from many of the other substantive regulations.
Accordingly, as an end-user, Generation is conducting its commercial business in a manner that does not require registration with the CFTC as an
SD or MSP. Generation does not anticipate transacting in the future in a manner in which it would become a SD or MSP.
There are, however, some rulemaking proceedings that have not yet been finalized, including the capital and margin rules for (non-cleared)
swaps. Generation does not expect these rules to directly impact its collateral requirements. However, depending on the substance of these final
rules in addition to certain international regulatory requirements still under development and that are similar to Dodd-Frank, Generation’s swap
counterparties could be subject to additional and potentially significant
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capitalization requirements. These regulations could motivate the SDs and MSPs to increase collateral requirements or cash postings from their
counterparties, including Generation.
Generation continues to monitor the rulemaking proceedings with respect to the capital and margin rules, but cannot predict to what extent, if
any, further refinements to Dodd-Frank requirements could impact its cash flows or financial position, but such impacts could be material.
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 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. The
prospect of such 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
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retrofitting of cooling water intake structures at Salem or other Exelon power plants, this development could result in material costs of compliance.
Pursuant to discussions with the NJDEP regarding the application of Section 316(b) to Oyster Creek, Generation agreed to permanently cease
generation operations at Oyster Creek by December 31, 2019, ten years before the expiration of its operating license in 2029. On July 28, 2016, the
NJDEP issued a final permit for Salem that did not require the installation of cooling towers. However, the permit is being challenged by an
environmental organization, and if successful, could result in additional costs for Clean Water Act compliance.
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 24—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,
including recovery mechanisms for costs associated with the procurement of electricity or gas, bad debt, MGP remediation, smart grid infrastructure,
and energy efficiency and demand response programs.
In certain instances, the Utility Registrants could agree to negotiated settlements related to various rate matters, customer initiatives or
franchise agreements. These settlements are subject to regulatory approval.
The 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
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rate proceedings have a significant effect on the ability of the Utility Registrants, as applicable, to recover their costs and could have a material
adverse effect on the Utility Registrants’ results of operations, cash flows and financial position. See Note 3—Regulatory Matters of the Combined
Notes to the Consolidated Financial Statements for information regarding rate proceedings.
Federal or additional state RPS and/or energy conservation legislation, along with energy conservation by customers, could negatively
affect the results of operations or cash flows of Generation and the Utility Registrants. (All Registrants)
Changes to current state legislation or the development of Federal legislation that requires the use of renewable and alternate fuel sources,
such as wind, solar, biomass and geothermal, 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 for RECs and purchased power 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, 2016, 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. At December 31, 2016, the gain (loss) could have been as much as $2.5 billion, $(1.1) billion, $(552) million, $(821)
million, $(208) million and $(476) million (before taxes) as a result of the elimination of regulatory assets and liabilities of ComEd, PECO, BGE,
Pepco, DPL and ACE, respectively. Further, Exelon would record a charge against OCI (before taxes) of up to $2.6 billion, $614 million, $424 million,
$243 million, and $84 million for ComEd, BGE, Pepco, DPL and ACE respectively, related to Exelon’s net regulatory assets associated with its
defined benefit postretirement plans. Exelon also has a net regulatory liability of $47 million (before taxes) associated with PECO’s defined benefit
postretirement plans that would result in an increase in OCI if reversed. 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 Notes 1—Significant Accounting Policies, 3—
Regulatory Matters and 11—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.
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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. In 2009, select Northeast
and Mid-Atlantic states implemented a model rule, developed via the RGGI, to regulate CO2 emissions from fossil-fired generation. RGGI states are
working on updated programs to further limit emissions, and the EPA has introduced regulation to address greenhouse gases from new fossil plants
that could potentially impact existing plants. 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 allowance credits. For example, more stringent permitting
requirements could preclude the construction of lower-carbon nuclear and gas-fired power plants. Similarly, a Federal RPS could increase the cost
of compliance by mandating the purchase or construction of more expensive supply alternatives. For more information regarding climate change,
see ITEM 1. BUSINESS “Global Climate Change” and Note 24—Commitments and Contingencies of the Combined Notes to Consolidated Financial
Statements.
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 3—Regulatory Matters and Note 24—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
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subsidiaries to be susceptible to less favorable legislative and regulatory outcomes, as well as increased regulatory oversight and more stringent
regulatory requirements. Unfavorable regulatory outcomes can include the enactment of more stringent laws and regulations governing Exelon’s
operations, as well as fines, penalties or other sanctions or requirements. The imposition of any of the foregoing could have a material negative
impact on the Registrants’ business, results of operations, cash flows and financial positions.
The Registrants cannot predict the outcome of the legal proceedings relating to their business activities. An adverse determination could
negatively impact their results of operations, cash flows or financial position. (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 24—Commitments and Contingencies of the Combined Notes to Consolidated Financial Statements. Adverse outcomes in
these proceedings could require significant expenditures that could have a material adverse effect on the Registrants’ results of operations.
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 results of operations or financial
position. Events at nuclear plants owned by others, as well as those owned by Generation, could cause the NRC to initiate such actions.
Spent nuclear fuel storage. The approval of a national repository for the storage of SNF, 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 currently estimates 2030 to be
the earliest date when the DOE will begin accepting SNF, which could be delayed by further regulatory action. See Note 24—Commitments and
Contingencies of the Combined Notes to Consolidated Financial Statements for additional information on the SNF obligation. 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 results of
operations or cash flows.
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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, 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’
operations and their ability to raise capital.
The impact that potential terrorist attacks could have on the industry in general and on Exelon in particular 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, which could adversely
affect the Registrants’ results of operations and its 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.
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.
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In addition, Exelon maintains a level of insurance coverage consistent with industry practices against property and casualty 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.
Nuclear fuel quality . The quality of nuclear fuel utilized by Generation could affect the efficiency and costs of Generation’s operations.
Certain of Generation’s nuclear units have previously had a limited number of fuel performance issues. 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 shut down
the plant or operate at less than full capacity. If this were to happen, identifying and correcting the causes could require significant time and expense.
Generation could choose to close a plant rather than incur the expense of restarting it or returning the plant to full capacity. In either event,
Generation could lose revenue and incur increased fuel and purchased power expense to meet supply commitments. For plants operated but not
wholly owned by Generation, Generation could also incur liability to the co-owners. For 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 results of operations or financial position. 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
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nuclear industry, could be borne by Generation and could have a material adverse effect on Generation’s results of operations or financial position.
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 affect Generation’s results of operations or
financial position.
Nuclear insurance. As required by the Price-Anderson Act, Generation carries the maximum available amount of nuclear liability insurance.
The required amount of nuclear liability insurance is $450 million for each operating site. Claims exceeding that amount are covered through
mandatory participation in a financial protection pool. In addition, the U.S. Congress could impose revenue-raising measures on the nuclear industry
to pay claims exceeding the $13.4 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 24—Commitments and Contingencies of the Combined Notes to Consolidated Financial Statements
for additional discussion of nuclear insurance.
Decommissioning. 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 decommissioning trust 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.
Forecasting trust fund investment earnings and costs to decommission nuclear generating stations requires significant judgment, and actual
results could differ significantly from current estimates. The performance of capital markets also 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 results of operations or financial position could be
significantly affected. See Note 3—Regulatory Matters of the Combined Notes to Consolidated Financial Statements for additional information.
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 cash flows or financial position 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 16—Asset
Retirement Obligations of the Combined Notes to Consolidated Financial Statements for additional information.
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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 Statement of Operations and Comprehensive Income results in an equal adjustment to the noncurrent payables to
affiliates at Generation and an adjustment to the regulatory liabilities at Exelon. Likewise, ComEd and PECO have recorded an equal noncurrent
affiliate receivable from Generation and a corresponding regulatory liability.
In the case of the nuclear units subject to the regulatory agreements with the ICC, if the funds held in the NDT funds for any former ComEd
unit are expected to not exceed the total 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
results of operations and financial position could be material. Additionally, any remaining balances in noncurrent payables to affiliates at Generation
and ComEd’s noncurrent affiliate receivable from Generation and corresponding regulatory liability may need to be reversed and could have a
material impact on Generation’s Consolidated Statement of Operations and Comprehensive Income.
In the case of 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 results of operations and financial position could be material. Additionally, any
remaining balances in noncurrent payables to affiliates at Generation and PECO’s noncurrent affiliate receivable from Generation and corresponding
regulatory liability may need to be reversed and could have a material impact on 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 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 will renew 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 or could result in increased operating
costs and significantly affect Generation’s results of operations or financial position. 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.
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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 results of operations,
financial condition, or cash flows 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 or infrastructure could result in potential liability if such failure results in damage to
property or injury to individuals. See ITEM 1. BUSINESS for further 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 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’ results of operations, cash flows or
financial condition could be negatively impacted. Furthermore, if any of the financial, accounting, or other data processing systems fail or have other
significant shortcomings, the Utility Registrants’ financial results could be negatively impacted. If an employee 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 employee 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 results of operations or cash flows. See Note 24—Commitments
and Contingencies of the Combined Notes to Consolidated Financial Statements for additional information regarding proceedings related to storm-
related outages in ComEd’s service territory.
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. (All 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
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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 Registrant’s
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 on their and Exelon’s results of operations, cash flows
and financial position.
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 increase the potentially unfavorable impacts of such attacks. A security breach of the physical assets or information systems of the
Registrants, their competitors, 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 subject the Registrants to financial harm associated with 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 we have been, and will likely continue
to be, subjected to physical and cyber-attacks, to date we have not experienced a material breach or disruption to our 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 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, any of which could contribute to the loss of customers and have a negative impact on the business and/or results of
operations. Moreover, the amount and scope of insurance maintained against losses resulting from any such events or security breaches may not be
sufficient to cover losses or otherwise adequately compensate for any disruptions to business that could result. The Utility Registrants’ deployment of
smart meters throughout their service territories could increase the risk of damage from an intentional disruption of the system by third parties. In
addition, new or updated security regulations or unforeseen threat sources could require changes in current measures taken by the Registrants or
their business operations and could adversely affect their results of operations, cash flows and financial position.
Failure to attract and retain an appropriately qualified workforce could negatively impact the Registrants’ results of operations. (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
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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
results of operations 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, 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 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 on the Utility Registrants’ financial results.
Risks Related to the PHI Merger
The merger may not achieve its anticipated results, and Exelon could be unable to integrate the operations of PHI in the manner expected.
(Exelon)
Exelon and PHI entered into the merger agreement with the expectation that the merger will result in various benefits, including, among other
things, cost savings and operating efficiencies. Achieving the anticipated benefits of the merger is subject to a number of uncertainties, including
whether the businesses of Exelon and PHI can be integrated in an efficient, effective and timely manner.
It is possible that the integration process could take longer than anticipated and could result in the loss of valuable employees, the disruption of
Exelon’s businesses, processes and systems or inconsistencies in standards, controls, procedures, practices and policies, any of which could
adversely affect the combined company’s ability to achieve the anticipated benefits of the merger as and when expected. Exelon could have difficulty
addressing possible differences in corporate cultures and management philosophies. Failure to achieve these anticipated benefits could result in
increased costs and could adversely affect Exelon’s future business, financial condition, operating results and prospects.
The merger may not be accretive to earnings and could cause dilution to Exelon’s earnings per share, which could negatively affect the
market price of Exelon’s common stock. (Exelon)
The timing and amount of accretion expected could be significantly adversely affected by a number of uncertainties, including market
conditions, risks related to Exelon’s businesses and whether
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the business of PHI is integrated in an efficient and effective manner. Exelon also could encounter additional transaction and integration-related
costs, could fail to realize all of the benefits anticipated in the merger or be subject to other factors that affect preliminary estimates. Any of these
factors could cause a decrease in Exelon’s adjusted earnings per share or decrease or delay the expected accretive effect of the merger and
contribute to a decrease in the price of Exelon’s common stock.
Exelon could incur unexpected transaction fees and merger-related costs in connection with the merger. (Exelon, PHI, Pepco, DPL and
ACE)
Exelon is incurring costs to combine the operations of Exelon, PHI and its subsidiaries. Exelon and PHI could incur additional unanticipated
costs in the integration of the businesses of the two companies. Although Exelon and PHI expect that the elimination of certain duplicative costs, as
well as the realization of other efficiencies related to the integration of the two businesses, will offset the incremental transaction and merger-related
costs over time, the combined company may not achieve this net benefit in the near term, or at all.
Exelon could encounter unexpected difficulties or costs in meeting commitments it made under various orders and agreements
associated with regulatory approvals for the PHI Merger. (Exelon, PHI, Pepco, DPL and ACE)
As a result of the process to obtain regulatory approvals required for the PHI Merger, Exelon is committed to various programs, contributions
and investments in several settlement agreements and regulatory approval orders, one of which may remain subject to the “most favored nation”
reconciliation process. It is possible that Exelon could encounter delays, unexpected difficulties, or additional costs in meeting these commitments in
compliance with the terms of the relevant agreements and orders. Failure to fulfill the commitments in accordance with their terms could result in
increased costs or result in penalties or fines that could adversely affect Exelon’s, PHI’s, Pepco’s, DPL’s and ACE’s financial position and operating
results.
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, 2016:
Station (a)
Region
Location
Braidwood
Byron
LaSalle
Dresden
Quad Cities
Clinton
Michigan Wind 2
Beebe
Michigan Wind 1
Harvest 2
Harvest
Beebe 1B
Ewington
Marshall
City Solar
AgriWind
Cisco
CP Windfarm
Blue Breezes
Solar Ohio
Southeast Chicago
Clinton Battery Storage
Total Midwest
Limerick
Peach Bottom
Salem
Calvert Cliffs
Three Mile Island
Oyster Creek
Conowingo
Criterion
Fourmile
Fair Wind
Solar Maryland MC
Solar New Jersey 1
Solar Horizons
Solar New Jersey 2
Solar Maryland
Solar Maryland 2
Solar Federal
Solar New Jersey 3
Solar DC
Muddy Run
Eddystone 3, 4
Perryman
Croydon
Handsome Lake
Notch Cliff
Westport
Richmond
Gould Street
Midwest
Midwest
Midwest
Midwest
Midwest
Midwest
Midwest
Midwest
Midwest
Midwest
Midwest
Midwest
Midwest
Midwest
Midwest
Midwest
Midwest
Midwest
Midwest
Midwest
Midwest
Midwest
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
Bureau Co., IL
Jackson Co., MN
Faribault Co., MN
Faribault Co., MN
Toledo, OH
Chicago, IL
Blanchester, OH
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
Mid-Atlantic
Mid-Atlantic
Mid-Atlantic
Mid-Atlantic
Mid-Atlantic
Mid-Atlantic
Mid-Atlantic
Mid-Atlantic
Mid-Atlantic
Mid-Atlantic
Mid-Atlantic
Mid-Atlantic
Sanatoga, PA
Delta, PA
Lower Alloways Creek
Township, NJ
Lusby, MD
Middletown, PA
Forked River, NJ
Darlington, MD
Oakland, MD
Garrett County, MD
Garrett County, MD
Various, MD
Various, NJ
Emmitsburg, MD
Various, NJ
Various, MD
Various, MD
Trenton, NJ
Middle Township, NJ
District of Columbia
Drumore, PA
Eddystone, PA
Aberdeen, MD
West Bristol, PA
Kennerdell, PA
Baltimore, MD
Baltimore, MD
Philadelphia, PA
Baltimore, MD
66
No. of
Units
2
2
2
2
2
1
50
34
46
33
32
21
10
9
1
4
4
2
2
3
8
1
2
2
2
2
1
1
11
28
16
12
16
6
1
2
10
3
1
5
1
8
2
5
8
5
8
1
2
1
Percent
Owned
(b)
75
99
99
99
99
50
42.59
50.01
Primary
Fuel Type
Uranium
Uranium
Uranium
Uranium
Uranium
Uranium
Wind
Wind
Wind
Wind
Wind
Wind
Wind
Wind
Solar
Wind
Wind
Wind
Wind
Solar
Gas
Energy Storage
Primary
Dispatch
Type (c)
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
Peaking
Peaking
Uranium
Uranium
Base-load
Base-load
Uranium
Uranium
Uranium
Uranium
Hydroelectric
Wind
Wind
Wind
Solar
Solar
Solar
Solar
Solar
Solar
Solar
Solar
Solar
Hydroelectric
Oil/Gas
Oil/Gas
Oil
Gas
Gas
Gas
Oil
Gas
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
Intermediate
Intermediate
Peaking
Peaking
Peaking
Peaking
Peaking
Peaking
Peaking
Net
Generation
Capacity (MW)
(d)
2,383
2,347
2,320
1,845
1,403(f)
1,069
90
82
69
59
53
50
20(f)
19(f)
9
8(f)
8(f)
4
3
3
296
10
12,150
2,317
1,301(f)
1,005(f)
879(f)(g)
837
625(e)
572
70
40
30
28
18
16
11
9
8
5
2
1
1,070
760
412
391
268
117
116
98
97
Table of Contents
Station (a)
Philadelphia Road
Eddystone
Fairless Hills
Delaware
Southwark
Falls
Moser
Riverside
Chester
Schuylkill
Salem
Pennsbury
Total Mid-Atlantic
Whitetail
Sendero
Wolf Hollow 1, 2, 3
Mountain Creek 8
Colorado Bend
Handley 3
Handley 4, 5
Mountain Creek 6, 7
LaPorte
Total ERCOT
Solar Massachusetts
Holyoke Solar
Solar Net Metering
Solar Connecticut
Mystic 8, 9
Mystic 7
Wyman
West Medway
Framingham
Mystic Jet
Total New England
Nine Mile Point
Ginna
Solar New York
Total New York
AVSR
Shooting Star
Exelon Wind 4
Bluestem
Bluegrass Ridge
Conception
Cow Branch
Solar Arizona
Mountain Home
High Mesa
Echo 1
Sacramento PV Energy
Cassia
Wildcat
Sunnyside
Solar Arizona 2
Primary
Dispatch
Type (c)
Net
Generation
Capacity (MW)
(d)
Region
Mid-Atlantic
Mid-Atlantic
Mid-Atlantic
Mid-Atlantic
Mid-Atlantic
Mid-Atlantic
Mid-Atlantic
Mid-Atlantic
Mid-Atlantic
Mid-Atlantic
Mid-Atlantic
Location
Baltimore, MD
Eddystone, PA
No. of
Units
4
4
Percent
Owned
(b)
Fairless Hills, PA
Philadelphia, PA
Philadelphia, PA
Morrisville, PA
Lower
PottsgroveTwp., PA
Baltimore, MD
Chester, PA
Philadelphia, PA
Lower Alloways Creek
Twp, NJ
2
4
4
3
3
2
3
2
1
42.59
Mid-Atlantic
Morrisville, PA
2
Primary
Fuel Type
Oil
Oil
Landfill
Gas
Oil
Oil
Oil
Oil
Oil/Gas
Oil
Oil
Oil
Landfill
Gas
Peaking
Peaking
Peaking
Peaking
Peaking
Peaking
Peaking
Peaking
Peaking
Peaking
Peaking
Peaking
ERCOT
Webb County, TX
57
Wind
Base-load
ERCOT
ERCOT
ERCOT
ERCOT
ERCOT
ERCOT
ERCOT
ERCOT
Jim Hogg and Zapata
County, TX
Granbury, TX
Dallas, TX
Wharton, TX
Fort Worth, TX
Fort Worth, TX
Dallas, TX
Laporte, TX
New England
New England
New England
New England
New England
New England
New England
New England
New England
New England
Various, MA
Various, MA
Uxbridge, MA
Various, CT
Charlestown, MA
Charlestown, MA
Yarmouth, ME
West Medway, MA
Framingham, MA
Charlestown, MA
New York
New York
New York
Scriba, NY
Ontario, NY
Bethlehem, NY
39
3
1
6
1
2
2
4
11
2
1
3
6
1
1
3
3
1
2
1
1
Other
Other
Other
Other
Other
Other
Other
Other
Other
Other
Other
Other
Other
Other
Other
Other
Lancaster, CA
Kiowa County, KS
Gruver, TX
Beaver County, OK
King City, MO
Barnard, MO
Rock Port, MO
Various, AZ
Glenns Ferry, ID
Elmore Co., ID
Echo, OR
Sacramento, CA
Buhl, ID
Lovington, NM
Sunnyside, UT
Various, AZ
1
65
38
60
27
24
24
127
20
19
21
4
14
13
1
25
67
Wind
Gas
Gas
Gas
Gas
Gas
Gas
Gas
Base-load
Intermediate
Intermediate
Intermediate
Intermediate
Peaking
Peaking
Peaking
Solar
Solar
Solar
Solar
Gas
Oil/Gas
Oil
Oil/Gas
Oil
Oil
Base-load
Base-load
Base-load
Base-load
Intermediate
Intermediate
Intermediate
Peaking
Peaking
Peaking
5.9
50.01
50.01
Uranium
Uranium
Solar
Base-load
Base-load
Base-load
Solar
Wind
Wind
Wind
Wind
Wind
Wind
Solar
Wind
Wind
Wind
Solar
Wind
Wind
Waste Coal
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
Base-load
Base-load
Base-load
Base-load
29
99
50
61
60
60
56
52
51
51
39
39
30
16(f)
6
11,624
91
78
705
568
468
395
870
240
152
3,567
5
5
2
2
1,415
575
36(f)
124
31
9
2,204
838(f)(g)
288(f)(g)
3
1,129
242
104
80
57
57
50
50
46
42
40
34(f)
30
29
27
26(f)(h)
23
Table of Contents
Station (a)
California PV Energy
Echo 2
Tuana Springs
Greensburg
Echo 3
Exelon Wind 1
Exelon Wind 2
Exelon Wind 3
Exelon Wind 5
Exelon Wind 6
Exelon Wind 7
Exelon Wind 8
Exelon Wind 9
Exelon Wind 10
Exelon Wind 11
High Plains
Three Mile Canyon
California PV Energy 2
Solar Georgia
Outback Solar
Loess Hills
Mohave Sunrise Solar
Denver Airport Solar
Solar California
Solar Georgia 2
Hillabee
Grande Prairie
SEGS 4, 5, 6
Total Other
Total
Region
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
Other
Other
Location
Various, CA
Echo, OR
Hagerman, ID
Greensburg, KS
Echo, OR
Gruver, TX
Gruver, TX
Gruver, TX
Texhoma, TX
Texhoma, TX
Sunray, TX
Sunray, TX
Sunray, TX
Dumas, TX
Dumas, TX
Panhandle, TX
Boardman, OR
Various, CA
Various, GA
Christmas Valley, OR
Rock Port, MO
Fort Mohave, AZ
Denver, CO
Various, CA
Various, GA
Alexander City, AL
Alberta, Canada
Boron, CA
No. of
Units
53
10
8
10
6
8
8
8
8
8
8
8
8
8
8
8
6
31
10
1
4
1
1
4
1
3
1
3
Percent
Owned
(b)
99
99.5
4.2-12.2
Primary
Fuel Type
Solar
Wind
Wind
Wind
Wind
Wind
Wind
Wind
Wind
Wind
Wind
Wind
Wind
Wind
Wind
Wind
Wind
Solar
Solar
Solar
Wind
Solar
Solar
Solar
Solar
Gas
Gas
Solar
Primary
Dispatch
Type (c)
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
Intermediate
Peaking
Peaking
Net
Generation
Capacity (MW)
(d)
21
20
17
13
10(f)
10(i)
10(i)
10(i)
10
10
10
10
10
10
10
10(f)
10
9
8
6
5
5
4
3
1
753
105
9(f)
2,046
32,720
(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) Generation has agreed to permanently cease generation operation at Oyster Creek by November 30, 2019.
(f) Net generation capacity is stated at proportionate ownership share.
(g) 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.
(h) Generation sold its 50% interest in Sunnyside effective February 3, 2017
(i) Generation plans to retire and cease generation operations at the Exelon Wind 1, Exelon Wind 2 and Exelon Wind 3 units effective June 1, 2017.
The net generation capability available for operation at any time may be less due to regulatory restrictions, transmission congestion, fuel
restrictions, efficiency of cooling facilities, level of water supplies or generating units being temporarily out of service for inspection, maintenance,
refueling, repairs or modifications required by regulatory authorities.
Generation maintains property insurance against loss or damage to its principal plants and properties by fire or other perils, subject to certain
exceptions. For additional information regarding nuclear insurance of generating facilities, see ITEM 1. BUSINESS—Exelon Generation Company,
LLC. For its insured losses, Generation is self-insured to the extent that any losses are within the policy deductible or exceed the amount of
insurance maintained. Any such losses could have a material adverse effect on Generation’s consolidated financial condition or results of
operations.
68
Table of Contents
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 higher voltage electric transmission lines owned and in service at December 31, 2016 were as follows:
Voltage (Volts)
765,000
345,000
138,000
Circuit
Miles
90
2,658
2,208
ComEd’s electric distribution system includes 35,397 circuit miles of overhead lines and 31,049 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 on 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.
Transmission and Distribution
PECO’s high voltage electric transmission lines owned and in service at December 31, 2016 were as follows:
Voltage (Volts)
500,000
230,000
138,000
69,000
Circuit
Miles
188 (a)
549
156
200
(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.
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Table of Contents
PECO’s electric distribution system includes 12,963 circuit miles of overhead lines and 9,290 circuit miles of underground lines.
Gas
The following table sets forth PECO’s natural gas pipeline miles at December 31, 2016:
Transmission
Distribution
Service piping
Total
Pipeline Miles
30
6,871
6,273
13,174
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
157 mmcf/day and a propane-air plant located in Chester, Pennsylvania, with a tank storage capacity of 150 mmcf and a peaking capability of 25
mmcf/day. In addition, PECO owns 31 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 on 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.
Transmission and Distribution
BGE’s high voltage electric transmission lines owned and in service at December 31, 2016 were as follows:
Voltage (Volts)
500,000
230,000
138,000
115,000
Circuit
Miles
218
331
55
709
BGE’s electric distribution system includes 9,443 circuit miles of overhead lines and 17,306 circuit miles of underground lines.
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Table of Contents
Gas
The following table sets forth BGE’s natural gas pipeline miles at December 31, 2016:
Transmission
Distribution
Service piping
Total
Pipeline Miles
161
7,239
6,230
13,630
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 on 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.
Transmission and Distribution
Pepco’s high voltage electric transmission lines owned and in service at December 31, 2016 were as follows:
Voltage (Volts)
500,000
230,000
138,000
115,000
Circuit
Miles
142
774
60
38
Pepco’s electric distribution system includes approximately 4,100 circuit miles of overhead lines and 6,800 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.
71
Table of Contents
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 on 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, 2016 were as follows:
Voltage (Volts)
500,000
230,000
138,000
69,000
Circuit
Miles
16
470
557
576
DPL’s electric distribution system includes approximately 6,100 circuit miles of overhead lines and 6,100 circuit miles of underground lines.
DPL also owns and operates a distribution system control center in New Castle, Delaware.
Gas
The following table sets forth DPL’s natural gas pipeline miles at December 31, 2016 :
Transmission (a)
Distribution
Service Piping
Total
Pipeline Miles
7
2,036
1,385
3,428
(a) DPL has a 10% undivided interest in approximately 7 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 3,045 mmcf and an
emergency sendout capability of 36,000 Mcf per 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 158,485 Mcf per day.
First Mortgage and Insurance
The principal properties of PDL 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.
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Table of Contents
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 on 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, 2016 were as follows:
Voltage (Volts)
500,000
230,000
138,000
69,000
Circuit
Miles
281
234
268
652
ACE’s electric distribution system includes approximately 7,400 circuit miles of overhead lines and 2,900 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.
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 on 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.
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Table of Contents
ITEM 3.
LEGAL PROCEEDINGS
All Registrants
The Registrants are parties to various lawsuits and regulatory proceedings in the ordinary course of their respective businesses. For
information regarding material lawsuits and proceedings, see Note 3—Regulatory Matters and Note 24—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.
74
Table of Contents
(Dollars in millions except per share data, unless otherwise noted)
PART II
ITEM 5.
Exelon
MARKET FOR REGISTRANT’S COMMON EQUITY, RELATED STOCKHOLDER MATTERS AND ISSUER PURCHASES OF
EQUITY SECURITIES
Exelon’s common stock is listed on the New York Stock Exchange. As of January 31, 2017, there were 926,589,614 shares of common stock
outstanding and approximately 113,308 record holders of common stock.
The following table presents the New York Stock Exchange—Composite Common Stock Prices and dividends by quarter on a per share basis:
2016
2015
High price
Low price
Close
Dividends
Third
Quarter
Fourth
Quarter
Second
Quarter
First
Quarter
$ 36.36 $ 37.70 $ 36.37 $ 35.95 $ 31.37 $ 34.44 $ 34.98 $ 38.25
31.71
33.61
0.310
31.28
31.42
0.310
33.18
36.36
0.318
28.41
29.70
0.310
25.09
27.77
0.310
29.82
35.49
0.318
32.86
33.29
0.318
26.26
35.86
0.310
Second
Quarter
Third
Quarter
Fourth
Quarter
Quarter
First
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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 2012 through 2016.
This performance chart assumes:
•
•
$100 invested on December 31, 2011 in Exelon common stock, in the S&P 500 Stock Index and in the S&P Utility Index; and
All dividends are reinvested.
Exelon Corporation
S&P 500
S&P Utilities
Generation
Value of Investment at December 31,
2011
$100
$100
$100
2012
$70.69
$111.68
$98.78
2013
$65.11
$144.74
$107.43
2014
$88.14
$161.22
$133.52
2015
$66.01
$160.05
$122.32
2016
$84.36
$175.31
$137.24
As of January 31, 2017, Exelon indirectly held the entire membership interest in Generation.
ComEd
As of January 31, 2017, there were 127,017,157 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, 2017, in
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addition to Exelon, there were 299 record holders of ComEd common stock. There is no established market for shares of the common stock of
ComEd.
PECO
As of January 31, 2017, there were 170,478,507 outstanding shares of common stock, without par value, of PECO, all of which were indirectly
held by Exelon.
BGE
As of January 31, 2017, 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, 2017, Exelon indirectly held the entire membership interest in PHI.
Pepco
As of January 31, 2017, 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, 2017, 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, 2017, 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.
The Federal Power Act declares it to be unlawful for any officer or director of any public utility “to participate in the making or paying of any
dividends of such public utility from any funds properly included in capital account.” What constitutes “funds properly included in capital account” is
undefined in the Federal Power Act or the related regulations; however, FERC has consistently interpreted the provision to allow dividends to be
paid as long as (1) the source of the dividends is clearly disclosed, (2) the dividend is not excessive and (3) there is no self-dealing on the part of
corporate officials. While these restrictions may limit the absolute amount of dividends that a particular subsidiary may pay, Exelon does not believe
these limitations are materially limiting because, under these limitations, the subsidiaries are allowed to pay dividends sufficient to meet Exelon’s
actual cash needs.
Under Illinois law, ComEd may not pay any dividend on its stock unless, among other things, “[its] earnings and earned surplus are sufficient to
declare and pay same after provision is made for reasonable and proper reserves,” or unless it has specific authorization from the ICC. ComEd has
also 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
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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 certain dividend restrictions established by the MDPSC. First, in connection with the Constellation merger, BGE was
prohibited from paying a dividend on its common shares through the end of 2014. Second, BGE is prohibited 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. Finally, BGE must notify
the MDPSC that it intends to declare a dividend on its common shares at least 30 days before such a dividend is paid and notify the MDPSC that
BGE’s equity ratio is at least 48% within five business days after dividend payment. There are no other limitations on BGE paying common stock
dividends unless BGE elects to defer interest payments on the 6.20% Deferrable Interest Subordinated Debentures due 2043, and any deferred
interest remains unpaid.
Pepco is subject to certain dividend restrictions limits imposed by: (i) state corporate laws, which impose limitations on the funds that can be
used to pay dividends, and (ii) the prior rights of holders of future preferred stock, if any, and existing and future mortgage bonds and other long-term
debt issued by Pepco and any other restrictions imposed in connection with the incurrence of liabilities.
DPL is subject to certain dividend restrictions imposed by: (i) state corporate laws, which impose limitations on the funds that can be used to
pay dividends, and (ii) the prior rights of holders of existing and future preferred stock, mortgage bonds and other long-term debt issued by DPL and
any other restrictions imposed in connection with the incurrence of liabilities.
ACE is subject to dividend restrictions imposed by: (i) state corporate laws, which impose limitations on the funds that can be used to pay
dividends and the regulatory requirement that ACE 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%; (ii) the prior rights of holders of existing and future preferred stock, mortgage
bonds and other long-term debt issued by ACE and any other restrictions imposed in connection with the incurrence of liabilities; and (iii) certain
provisions of the charter of ACE which impose restrictions on payment of common stock dividends for the benefit of preferred stockholders.
Currently, the restriction in the ACE charter does not limit its ability to pay common stock dividends.
Exelon’s Board of Directors has approved a dividend policy providing a raise of 2.5% each year for three years, beginning with the June 2016
dividend.
At December 31, 2016, Exelon had retained earnings of $12,030 million, including Generation’s undistributed earnings of $2,275 million,
ComEd’s retained earnings of $987 million consisting of retained earnings appropriated for future dividends of $2,626 million, partially offset by
$(1,639) million of unappropriated accumulated deficits, PECO’s retained earnings of $941 million, BGE’s retained earnings of $1,427 million, and
PHI’s undistributed earnings of $(61) million.
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The following table sets forth Exelon’s quarterly cash dividends per share paid during 2016 and 2015:
2016
2015
(per share)
Exelon
4th
1st
Quarter
$ 0.318 $ 0.318 $ 0.318 $ 0.310 $ 0.310 $ 0.310 $ 0.310 $ 0.310
Quarter
Quarter
Quarter
Quarter
Quarter
Quarter
Quarter
2nd
2nd
3rd
3rd
4th
1st
The following table sets forth Generation’s and PHI’s quarterly distributions and ComEd’s, PECO’s, Pepco’s, DPL’s and ACE’s quarterly
common dividend payments:
(in millions)
Generation
ComEd
PECO
BGE
PHI
Pepco
DPL
ACE
4th
3rd
2016
Quarter
$ 755 $
Quarter
2nd
Quarter
1st
Quarter
94
69
45
99
44
15
39
56 $
92
69
44
50
37
1
13
56 $
92
70
45
16
16
—
—
2015
4th
3rd
2nd
Quarter
Quarter
Quarter
1st
Quarter
55 $ 106 $ 106 $ 906 $1,356
75
76
91
70
70
69
36
39
45
68
69
108
—
60
39
62
18
38
12
—
11
75
69
41
69
31
—
—
73
70
42
69
55
12
—
First Quarter 2017 Dividend. On January 31, 2017, the Exelon Board of Directors declared a first quarter 2017 regular quarterly dividend of
$0.3275 per share on Exelon’s common stock payable on March 10, 2017, to shareholders of record of Exelon at the end of the day on February 15,
2017.
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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
2016 (a)
For the Years Ended December 31,
2015
2014 (b)
2013
$31,360
3,112
1,204
1,134
$29,447
4,409
2,250
2,269
$27,429
3,096
1,820
1,623
$24,888
3,669
1,729
1,719
2012 (c)
$23,489
2,373
1,171
1,160
$
$
1.22
1.26
$
$
2.54
1.24
$
$
1.88
1.24
$
$
2.00
1.46
$
$
1.42
2.10
(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) The 2012 financial results include the activity of Constellation from the merger effective date of March 12, 2012 through December 31, 2012.
(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
Preferred securities of subsidiary
Shareholders’ equity
Generation
2016
2015
2014
2013
2012
December 31,
$ 12,412
71,555
114,904
13,457
32,216
—
25,837
$15,334
57,439
95,384
9,118
24,286
—
25,793
$11,853
52,170
86,416
8,762
19,853
—
22,608
$ 9,562
47,330
79,243
7,686
18,165
—
22,732
$10,009
45,186
78,350
7,734
18,266
87
21,431
The selected financial data presented below has been derived from the audited consolidated financial statements of Generation. This data is
qualified in its entirety by reference to and should be read in conjunction with Generation’s Consolidated Financial Statements and ITEM 7.
MANAGEMENT’S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS.
(In millions)
Statement of Operations data:
Operating revenues
Operating income
Net income
2016
For the Years Ended December 31,
2015
2014 (a)
2013
2012 (b)
$17,751
836
558
$19,135
2,275
1,340
$17,393
1,176
1,019
$15,630
1,677
1,060
$14,437
1,113
558
(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
consolidated basis.
(b) The 2012 financial results include the activity of Constellation from the merger effective date of March 12, 2012 through December 31, 2012.
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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 affiliate
Member’s equity
ComEd
2016
2015
December 31,
2014
2013
2012
$ 6,528
25,585
46,974
5,683
8,124
11,482
$ 6,342
25,843
46,529
4,933
8,869
11,635
$ 7,311
23,028
44,951
4,459
7,582
12,718
$ 5,964
20,111
40,700
3,842
7,111
12,725
$ 6,211
19,531
40,648
3,969
7,422
12,557
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)
Statement of Operations data:
Operating revenues
Operating income
Net income
(In millions)
Balance Sheet data:
Current assets
Property, plant and equipment, net
Total assets
Current liabilities
Long-term debt, including long-term debt to financing trusts
Shareholders’ equity
PECO
2016
For the Years Ended December 31,
2015
2014
2013
2012
$5,254
1,205
378
$4,905
1,017
426
$4,564
980
408
$4,464
954
249
$5,443
886
379
2016
2015
December 31,
2014
2013
2012
$ 1,554
19,335
28,335
2,938
6,813
8,725
$ 1,518
17,502
26,532
2,766
6,049
8,243
$ 1,723
15,793
25,358
1,923
5,870
7,907
$ 1,540
14,666
24,089
2,032
5,235
7,528
$ 1,692
13,826
22,793
1,655
5,492
7,323
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)
Statement of Operations data:
Operating revenues
Operating income
Net income
2016
For the Years Ended December 31,
2015
2014
2013
2012
$2,994
702
438
$3,032
630
378
$3,094
572
352
$3,100
666
395
$3,186
623
381
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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
Preferred securities
Shareholders’ equity
BGE
2016
2015
2014
2013
2012
December 31,
757
$
7,565
10,831
727
2,764
—
3,415
842
$
7,141
10,367
944
2,464
—
3,236
$ 645
6,801
9,860
653
2,416
—
3,121
$ 821
6,384
9,521
889
2,120
—
3,065
$1,054
6,078
9,303
1,158
1,821
87
2,982
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)
Statement of Operations data:
Operating revenues
Operating income
Net income
(In millions)
Balance Sheet data:
Current assets
Property, plant and equipment, net
Total assets
Current liabilities
Long-term debt, including long-term debt to financing trusts and variable
interest entities
Shareholders’ equity
PHI
2016
For the Years Ended December 31,
2015
2014
2013
2012
$3,233
550
294
$3,135
558
288
$3,165
439
211
$3,065
449
210
$2,735
132
4
2016
2015
December 31,
2014
2013
2012
$ 842
7,040
8,704
707
$ 845
6,597
8,295
1,134
$ 951
6,204
8,056
794
$1,009
5,864
7,839
800
$ 979
5,498
7,485
980
2,533
2,848
1,732
2,687
2,109
2,563
2,179
2,365
1,949
2,168
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)
Statement of Operations data (a) :
Operating revenues
Operating income
Net (loss) income from continuing operations
Net (loss) income
Successor
March 24 -
December 31
2016
$
3,643
93
(61)
(61)
January 1 -
March 23
2016
Predecessor
For the Years Ended
December 31,
2015
2014
$
1,153
105
19
19
$ 4,935
673
318
327
$ 4,808
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
Member’s equity/Shareholders’ equity
Successor
December 31,
2016
$
1,838
11,598
21,025
2,284
5,645
—
8,016
Predecessor
December 31,
2015
$
1,474
10,864
16,188
2,327
4,823
183
4,413
(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.
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 (loss) income
(In millions)
Balance Sheet data (a) :
Current assets
Property, plant and equipment, net
Total assets
Current liabilities
Long-term debt
Shareholders’ equity
For the Years Ended December 31,
2016
2015
2014
$ 2,186
174
42
$ 2,129
385
187
$ 2,055
349
171
December 31,
2016
2015
$ 684
5,571
7,335
596
2,333
2,300
$ 726
5,162
6,908
455
2,340
2,240
(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.
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 (loss) income
For the Years Ended December 31,
2016
2015
2014
$ 1,277
50
(9)
$ 1,302
165
76
$ 1,282
207
104
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(In millions)
Balance Sheet data (a) :
Current assets
Property, plant and equipment, net
Total assets
Current liabilities
Long-term debt
Shareholders’ equity
December 31,
2016
2015
$ 370
3,273
4,153
381
1,221
1,326
$ 388
3,070
3,969
564
1,061
1,237
(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.
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 (loss) income
(In millions)
Balance Sheet data (a) :
Current assets
Property, plant and equipment, net
Total assets
Current liabilities
Long-term debt
Shareholders’ equity
For the Years Ended December 31,
2016
2015
2014
$
1,257
7
(42)
$
1,295
134
40
$
1,210
137
46
December 31,
2016
2015
$ 399
2,521
3,457
320
1,120
1,034
$ 546
2,322
3,387
297
1,153
1,000
(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.
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Item 7.
MANAGEMENT’S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS
Exelon
Executive Overview
Exelon, a utility services holding company, operates through the following principal subsidiaries:
•
•
•
•
•
•
Generation, whose 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.
ComEd, whose business consists of the purchase and regulated retail sale of electricity and the provision of electricity transmission and
distribution services in northern Illinois, including the City of Chicago.
PECO, whose business consists of the purchase and regulated retail sale of electricity and the provision of electricity 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 services in the Pennsylvania counties surrounding the City of Philadelphia.
BGE, whose business consists of the purchase and regulated retail sale of electricity and natural gas and the provision of electricity
distribution and transmission and gas distribution services in central Maryland, including the City of Baltimore.
Pepco, whose business consists of the purchase and regulated retail sale of electricity and the provision of electricity distribution and
transmission in the District of Columbia and major portions of Prince George’s County and Montgomery County in Maryland.
DPL, whose business consists of the purchase and regulated retail sale of electricity and the provision of electricity distribution and
transmission services in portions of Maryland and Delaware, and the purchase and regulated retail sale of natural gas and the provision of
natural gas distribution services in northern Delaware.
•
ACE, whose business consists of the purchase and regulated retail sale of electricity and the provision of electricity transmission and
distribution services in southern New Jersey.
Pepco, DPL and ACE are operating companies of PHI, which is a utility services holding company and a wholly owned subsidiary of Exelon.
Exelon has twelve reportable segments consisting of Generation’s six reportable segments (Mid-Atlantic, Midwest, New England, New York,
ERCOT and Other Power Regions in Generation), ComEd, PECO, BGE and PHI’s three utility reportable segments (Pepco, DPL and ACE). See
Note 26—Segment Information of the Combined Notes to Consolidated Financial Statements for additional information regarding Exelon’s reportable
segments.
Through its business services subsidiary BSC, Exelon provides its operating subsidiaries with a variety of support services at cost. The costs
of these services are directly charged or allocated to the applicable operating segments. Additionally, the results of Exelon’s corporate operations
include costs for corporate governance and interest costs and income from various investment and financing activities.
PHI Service Company, a wholly owned subsidiary of PHI, provides a variety of support services at cost, including legal, accounting,
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 PHI Service Company and the participating
operating subsidiaries.
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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.
Financial Results of Operations
GAAP Results of Operations
The following tables set forth Exelon’s GAAP consolidated results of operations for the year ended December 31, 2016 compared to the same
period in 2015. 2016 amounts include the operations of PHI, Pepco, DPL and ACE from March 24, 2016 through December 31, 2016. All amounts
presented below are before the impact of income taxes, except as noted.
For the Years Ended December 31,
Favorable
2015
Generation ComEd PECO BGE PHI (b) Other Exelon Exelon
$
17,751 $ 5,254 $ 2,994 $ 3,233 $ 3,643 $ (1,515) $31,360 $29,447 $
8,830 1,458 1,047 1,294 1,447 (1,436) 12,640 13,084
(79) 18,720 16,363
8,921 3,796 1,947 1,939 2,196
2016
(Unfavorable)
Variance
Operating revenues
Purchased power and fuel expense
Revenue net of purchased power and fuel expense (a)
Other operating expenses
Operating and maintenance
Depreciation and amortization
Taxes other than income
Total other operating expenses
Gain (Loss) on sales of assets
Operating income (loss)
Other income and (deductions)
Interest expense, net
Other, net
Total other income and (deductions)
Income (loss) before income taxes
Income taxes
Equity in (losses) earnings of unconsolidated
affiliates
Net income (loss)
Net income (loss) attributable to noncontrolling interests
and preference stock dividends
Net income (loss) attributable to common
5,641 1,530
775
1,879
293
506
811
737 1,233
270
515
423
354
164
229
8,026 2,598 1,245 1,389 2,102
(1)
93
7 — —
550
(59)
836 1,205
702
96 10,048 8,322
74 3,936 2,450
30 1,576 1,200
200 15,560 11,972
18
(48)
(274) 3,112 4,409
5
(364)
401
37
873
290
(461)
(65)
(526)
679
301
(123)
8
(115)
587
149
(103)
21
(82)
468
174
(195)
44
(151)
(58)
3
4
(290) (1,536) (1,033)
(46)
413
(286) (1,123) (1,079)
(560) 1,989 3,330
761 1,073
(156)
(25) — — — —
(61)
438
558
294
378
1
(7)
(24)
(403) 1,204 2,250
1,913
444
2,357
(1,726)
(1,486)
(376)
(3,588)
(66)
(1,297)
(503)
459
(44)
(1,341)
312
(17)
(1,046)
62 — —
8 — —
70
(19)
89
shareholders
$
496 $ 378 $ 438 $ 286 $
(61) $ (403) $ 1,134 $ 2,269 $
(1,135)
(a) The Registrants’ evaluate operating performance using the measure of revenues net of purchased power and fuel expense. The Registrants’ believe that revenues net of
purchased power and fuel expense is a useful measurement because it provides information that can be used to evaluate its operational performance. Revenues net of
purchased power and fuel
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expense 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.
(b) As a result of the PHI Merger, PHI includes the consolidated results of PHI, Pepco, DPL and ACE from March 24, 2016 through December 31, 2016.
Exelon’s net income attributable to common shareholders was $1,134 million for the year ended December 31, 2016 as compared to
$2,269 million for the year ended December 31, 2015, and diluted earnings per average common share were $1.22 for the year ended
December 31, 2016 as compared to $2.54 for the year ended December 31, 2015.
Operating revenues net of purchased power and fuel expense, which is a non-GAAP measure discussed below, increased by $2,357 million
as compared to 2015. The year-over-year increase was primarily due to the following favorable factors:
•
•
•
•
Increase of $2,196 million in revenue net of purchased power and fuel due to the inclusion of PHI’s results for the period of March 24,
2016 to December 31, 2016;
Increase of $210 million at ComEd primarily due to increased distribution and transmission formula rate revenue resulting from increased
capital investment, as well as, favorable weather;
Increase of $109 million at BGE primarily due to increased transmission revenue as a result of increased capital investments and
operating and maintenance expense recoveries and increased distribution revenue pursuant to increased rates as a result of the
distribution rate orders issued by the MDPSC in June 2016 and July 2016;
Increase of $105 million at Generation primarily due to the impact of the Ginna Reliability Support Services Agreement and a decrease in
nuclear outage days at higher capacity units despite an increase in overall outage days, partially offset by lower realized energy prices;
and
•
Increase of $105 million at PECO primarily due to increased electric distribution revenue pursuant to a rate increase effective January 1,
2016.
The year-over-year increase in operating revenues net of purchased power and fuel expense described above was partially offset by a
decrease of $298 million at Generation due to mark-to-market losses of $41 million in 2016 from economic hedging activities as compared to gains
of $257 million in 2015.
Operating and maintenance expense increased by $1,726 million as compared to 2015. The year-over-year increase was primarily due to the
following unfavorable factors:
•
•
•
•
•
Increase of $910 million, exclusive of merger commitment costs discussed above, due to the inclusion of PHI’s results for the period
March 24, 2016 to December 31, 2016;
Approval of the merger across all regulatory jurisdictions was conditioned on Exelon and PHI agreeing to certain commitments pursuant to
which, upon acquisition close, Exelon recorded $513 million of costs;
Increase in Generation’s labor, contracting and materials cost of $185 million related to the inclusion of Pepco Energy Services results in
2016 and increased contracting costs related to energy efficiency projects;
Long-lived asset impairments of $171 million at Generation in 2016 compared to $10 million in 2015;
Increase of $54 million at BGE primarily as a result of one-time charges associated with the reduction of regulatory assets and other long-
lived assets stemming from certain cost disallowances contained within the distribution rate orders issued by the MDPSC in June and July
2016; and
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•
Increase of $28 million at Generation for the recognition of one-time charges associated with Generation’s 2016 decision to early retire the
Clinton and Quad Cities nuclear generating facilities.
The year-over-year increase in operating and maintenance expense was partially offset by the following favorable factors:
•
•
•
Decrease of $79 million at Generation as a result of the annual update of the Generation nuclear decommissioning obligation related to
the non-regulatory units in 2016 versus 2015;
Decrease of $79 million at Generation as a result of a decrease in nuclear outage days in 2016, excluding Salem; and
Decrease of $77 million in pension and non-pension post-retirement benefit costs resulting from the favorable impact of higher pension
and OPEB discount rates in 2016.
Depreciation and amortization expense increased by $1,486 million primarily as a result of accelerated depreciation and amortization expense
related to Generation’s previous decision to early retire the Clinton and Quad Cities nuclear generating facilities, increased nuclear decommissioning
amortization at Generation, increased depreciation expense due to ongoing capital expenditures across all operating companies and the inclusion of
PHI’s results for the period of March 24, 2016 to December 31, 2016.
Taxes other than income increased $376 million primarily due to increased property and utility taxes as a result of the inclusion of PHI’s results
for the period March 24, 2016 to December 31, 2016.
Gain (Loss) on sales of assets decreased $66 million 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.
Interest expense, net increased by $503 million primarily due to the recognition of the interest due on the asserted penalty related to the Tax
Court’s decision on Exelon’s like-kind exchange tax position, higher outstanding debt to fund the PHI acquisition and general corporate purposes
and the absence of the forward-starting interest rate swaps in 2016.
Other, net increased by $459 million primarily due to the change in realized and unrealized gains and losses on NDT funds at Generation,
partially offset by the recognition of the penalty related to the Tax Court’s decision on Exelon’s like-kind exchange tax position.
Exelon’s effective income tax rates for the years ended December 31, 2016 and 2015 were 38.3% and 32.2%, respectively. See Note 15—
Income Taxes of the Combined Notes to Consolidated Financial Statements for additional information regarding the components of the effective
income tax rates. Exelon recorded an after-tax charge of $98 million for the year ended December 31, 2016 as a result of the assessment and
remeasurement of certain federal and state PHI, Pepco, DPL and ACE uncertain tax positions.
For further detail regarding the financial results for the years ended December 31, 2016 and 2015, including explanation of the non-GAAP
measure revenues net of purchased power and fuel expense, see the discussions of Results of Operations by Segment below.
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Adjusted (non-GAAP) Operating Earnings
Exelon’s adjusted (non-GAAP) operating earnings for the year ended December 31, 2016 were $2,488 million, or $2.68 per diluted share,
compared with adjusted (non-GAAP) operating earnings of $2,227 million, or $2.49 per diluted share, for the same period in 2015. 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, 2016 as compared to 2015:
For the years ended December 31,
2015
2016
(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)
Unrealized (Gains) Losses Related to NDT Fund Investments (b)
Plant Retirements and Divestitures (c)
Asset Retirement Obligation (d)
Merger and Integration Costs (e)
Amortization of Commodity Contract Intangibles (f)
Reassessment of State Deferred Income Taxes (g)
Long-Lived Asset Impairments (h)
Tax Settlements (i)
Mark-to-Market Impact of PHI Merger Related Interest Rate Swaps (j)
PHI Merger Related Redeemable Debt Exchange (k)
Reduction in State Income Tax Reserve (l)
Midwest Generation Bankruptcy Recoveries (m)
Merger Commitments (n)
Curtailment of Generation Growth and Development Activities (o)
Cost Management Program (p)
Like-Kind Exchange Tax Position (q)
CENG Noncontrolling Interests (r)
Adjusted (non-GAAP) Operating Earnings
$1,134
24
(118)
432
(75)
114
35
10
103
—
—
—
—
—
437
57
34
199
102
$2,488
$
Earnings
per
Diluted
Share
1.22
0.03
(0.13)
0.47
(0.08)
0.12
0.04
0.01
0.11
—
—
—
—
—
0.47
0.06
0.04
0.21
0.11
2.68
$
$2,269
(158)
115
—
(6)
58
(5)
41
21
(52)
(21)
13
(10)
(6)
—
—
—
—
(32)
$2,227
$
Earnings
per
Diluted
Share
2.54
(0.18)
0.13
—
(0.01)
0.07
—
0.05
0.02
(0.06)
(0.02)
0.01
(0.01)
(0.01)
—
—
—
—
(0.04)
2.49
$
(a) Reflects the impact of (gains) losses for the years ended December 31, 2016 and 2015 (net of taxes of $18 million and $99 million, respectively) on Generation’s
economic hedging activities. See Note 13—Derivative Financial Instruments of the Combined Notes to Consolidated Financial Statements for additional detail related to
Generation’s hedging activities.
(b) Reflects the impact of unrealized (gains) losses for the years ended December 31, 2016 and 2015 (net of taxes of $112 million and $148 million, respectively) on
Generation’s NDT fund investments for Non-Regulatory Agreement Units.
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See Note 16—Asset Retirement Obligations of the Combined Notes to Consolidated Financial Statements for additional detail related to Generation’s NDT fund
investments.
(c) Primarily reflects incremental accelerated depreciation and amortization expenses from June 2, 2016 through December 6, 2016 and construction work in progress
impairments pursuant to the second quarter decision to early retire the Clinton and Quad Cities nuclear generating facilities, which decision was reversed in December
2016 (net of taxes of $285 million), partially offset by a gain associated with Generation’s 2016 sale of the New Boston generating site (net of taxes of $12 million).
(d) Reflects a non-cash benefit pursuant to the annual update of the Generation nuclear decommissioning obligation related to the Non-Regulatory Agreement Units for the
years ended December 31, 2016 and 2015 (net of taxes of $13 million and $4 million, respectively).
(e) Reflects certain costs associated with mergers and acquisitions incurred for the years ended December 31, 2016 and 2015 (net of taxes of $50 million and $38 million,
respectively) including professional fees, employee-related expenses, integration activities and upfront credit facilities fees related to the PHI acquisition and pending
Fitzpatrick acquisition, partially offset in 2016 at ComEd, BGE and PHI by the anticipated recovery of previously incurred PHI acquisition costs.
(f) Reflects the non-cash impact for the years ended December 31, 2016 and 2015 (net of taxes of $22 million and $3 million, respectively) of the amortization of commodity
contracts recorded at fair value associated with prior acquisitions, if and when applicable.
(g) Reflects the non-cash impacts of the remeasurement of state deferred income taxes, primarily as a result of changes in forecasted apportionment.
(h) Reflects impairment of upstream assets and certain wind projects in 2016 (net of taxes of $68 million) and the impairment of investment in long-term leases at Corporate
in 2015 (net of taxes of $13 million).
(i) Reflects a benefit related to the favorable settlement in 2015 of certain income tax positions on Constellation’s pre-acquisition tax returns.
(j) Reflects the impact of mark-to-market activity on forward-starting interest rate swaps held at Exelon Corporate related to financing for the PHI acquisition for the year
ended December 31, 2015 (net of taxes of $14 million).
(k) Reflects the costs associated with the exchange and redemption in December 2015 of certain mandatorily redeemable debt issued to finance the PHI merger (net of taxes
of $8 million in 2015).
(l) Reflects the reduction of a previously recorded state income tax reserve associated with the 2014 sales of Keystone and Conemaugh for the year ended December 31,
2015.
(m) Reflects a benefit for the favorable settlement of a long-term railcar lease agreement pursuant to the Midwest Generation bankruptcy for the year ended December 31,
2015 (net of taxes of $4 million).
(n) Represents adjustments to costs incurred as part of the settlement orders approving the PHI acquisition and a charge related to a 2012 CEG merger commitment for the
year ended December 31, 2016 (net of taxes of $126 million).
(o) Reflects the one-time recognition for a loss on sale of assets and asset impairment charges pursuant to Generation’s strategic decision to narrow the scope and scale of
its growth and development activities for the year ended December 31, 2016 (net of taxes of $35 million).
(p) Represents 2016 severance expense and reorganization costs related to a cost management program (net of taxes of $21 million).
(q) Represents the recognition of a penalty and associated interest expense in the third quarter of 2016, as a result of a tax court decision on Exelon’s like-kind exchange tax
position (net of taxes of $61 million).
(r) Represents elimination from Generation’s results of the noncontrolling interests related to CENG exclusion items, primarily related to the impact of unrealized gains and
losses on NDT fund investments and changes in asset retirement obligations in 2016, and in 2015 the impact of unrealized gains and losses on NDT fund investments
and mark-to-market activity.
Merger and Acquisition Costs
On March 23, 2016, the Exelon and PHI Merger was completed. On the merger date, PHI shareholders received $27.25 of cash in exchange
for each share of PHI common stock. The resulting company retained the Exelon name and is headquartered in Chicago.
As a result of the PHI Merger, Exelon has incurred costs associated with evaluating, structuring and executing the PHI Merger transaction
itself, and will continue to incur cost associated with meeting the various commitments set forth by regulators and agreed-upon with other interested
parties as part of the merger approval process, and integrating the former PHI businesses into Exelon.
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The table below presents the one-time pre-tax charges recognized for the PHI Merger included in the Registrant’s respective Consolidated
Statements of Operations and Comprehensive Income.
Merger commitments
Changes in accounting and tax related policies and estimates
Total
For the Year Ended December 31, 2016
Exelon
$ 513
—
$ 513
Generation
3
$
—
3
$
Pepco
$ 126
25
$ 151
DPL
$ 86
15
$101
ACE
$111
5
$116
Successor
March 24,
2016 to
December 31,
2016
PHI
$
$
323
—
323
In addition to the one-time PHI Merger charges discussed above, for the years ended December 31, 2016 and 2015, expense has been
recognized for the PHI Merger, Constellation acquisition and the pending FitzPatrick acquisition as follows:
Merger Integration and
Acquisition Expense:
Transaction (c)
Employee-related (d)
Other (e)
Total
Pre-tax Expense
For the Year Ended December 31, 2016
Exelon
(a)
34
77
52
$ 163
Generation
(a)
2
10
44
56
$
ComEd
—
2
(8)
(6)
$
PECO
—
1
4
5
$
BGE
—
1
(2)
$ (1)
PHI
(a)
—
64
5
$ 69
Pepco
(a)
—
30
(2)
$ 28
DPL
(a)
—
18
2
$ 20
ACE
(a)
—
15
4
$ 19
Merger Integration and Acquisition Expense:
Financing (b)
Transaction (c)
Other (e)
Total
Exelon
21
$
23
51
95
$
Pre-tax Expense
For the Year Ended December 31, 2015
Generation
—
$
—
32
32
ComEd
$ —
—
9
9
PECO
$ —
—
4
4
$
$
$
BGE
$ —
—
5
5
$
(a) For Exelon, Generation, PHI, Pepco, DPL, and ACE, includes the operations of the acquired businesses beginning on March 24, 2016.
(b) Reflects costs incurred at Exelon related to the financing of the PHI Merger, including upfront credit facility fees and mark-to-market activity on forward-starting interest
rate swaps and costs associated with the exchange and redemption of mandatorily redeemable debt.
(c) External, third party costs paid to advisors, consultants, lawyers and other experts to assist in the due diligence and regulatory approval processes and in the closing of
transactions.
(d) Costs primarily for employee severance, pension and OPEB expense and retention bonuses.
(e) For the year ended December 31, 2016, includes the reversal of previously incurred acquisition, integration and financing costs of $8 million, $6 million, $11 million,
$4 million and $16 million incurred at ComEd, BGE, Pepco, DPL and PHI, respectively, that has been deferred and recorded as a regulatory asset for anticipated
recovery. See Note 3—Regulatory Matters of the Combined Notes to Consolidated Financial Statements for more information. For the year ended December 31, 2015,
includes costs to integrate CENG, Constellation and Integrys systems into Exelon and terminate certain Constellation debt agreements. Also includes professional fees
primarily related to integration for the PHI acquisition.
As of December 31, 2016, Exelon expects to incur total PHI acquisition and integration related costs of approximately $700 million, excluding
merger commitments. Of this amount, including costs incurred from 2014 through December 31, 2016, Exelon and PHI have incurred approximately
$610 million. Included in this amount are costs to fund the merger of which $76 million has been
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expensed, $56 million has been paid and recorded as deferred debt issuance costs and $60 million has been incurred and charged to common
stock. The remaining costs will be primarily within Operating and maintenance expense within Exelon’s Consolidated Statements of Operations and
Comprehensive Income and will also include approximately $30 million for integration costs expected to be capitalized to Property, plant and
equipment.
Significant 2016 Transactions and Developments
PHI Acquisition
On March 23, 2016, Exelon completed its acquisition of PHI for a total cash purchase price of $7.1 billion, significantly expanding its regulated
utility business and resulting in a total of over 10 million utility customers. In accounting for the acquisition as a business combination, Exelon and
PHI recorded $4.0 billion in goodwill. 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 customer rate credits, funding for energy efficiency and delivery system modernization
programs, and other various requirements, for which Exelon recorded $513 million of Operating and maintenance expense for the year ended
December 31, 2016. The Registrants have also incurred costs for evaluating, structuring and executing the transaction, as well as integrating the
former PHI businesses into Exelon. See Note 4—Mergers, Acquisitions, and Dispositions of the Combined Notes to the Consolidated Financial
Statements for additional information regarding the PHI acquisition and related costs.
Illinois Future Energy Jobs Act
On December 7, 2016, FEJA was signed into law by the Governor of Illinois. FEJA is effective June 1, 2017, and includes, among other
provisions, (1) a ZES providing compensation for certain nuclear-powered generating facilities, (2) an extension of and certain adjustments to
ComEd’s electric distribution formula rate, (3) new cumulative persisting annual energy efficiency MWh savings goals for ComEd, (4) revisions to the
Illinois RPS requirements, (5) provisions for adjustments to or termination of FEJA programs if the average impact on ComEd’s customer rates
exceeds specified limits, (6) revisions to the existing net metering statute to (i) mandate net metering for community generation projects, and
establish billing procedures for subscribers to those projects, (ii) provide immediately for netting at the energy-only rate for nonresidential customers,
and (iii) transition from netting at the full retail rate to the energy-only rate for certain residential net metering customers once the net meter customer
load equals 5% of total peak demand supplied in the previous year and (7) support for low income rooftop and community solar programs. FEJA
establishes new or adjusts existing rate recovery mechanisms for ComEd to recover costs associated with the new or expanded energy efficiency
and RPS requirements. Regulatory or legal challenges over the validity of FEJA are possible. See Note 3—Regulatory Matters of the Combined
Notes to the Consolidated Financial Statements for additional information regarding FEJA. See Note 9—Early Nuclear Plant Retirements of the
Combined Notes to the Consolidated Financial Statements for the impacts of ZES on Generation’s Consolidated Balance Sheets and Consolidated
Statements of Operations and Comprehensive Income.
New York Clean Energy Standard
On August 1, 2016, the New York Public Service Commission (NYPSC) issued an order establishing the CES, a component of a Tier 3 ZEC
program targeted at preserving the environmental attributes of qualifying zero-emissions nuclear-powered generating facilities, including CENG’s
Ginna, and Nine Mile Point and Entergy Nuclear Fitzpatrick LLC’s (Entergy) 838 MW single unit James A. FitzPatrick facilities. On November 18,
2016, required contracts with the New York State Energy Research and Development Authority (NYSERDA) were executed for each of these three
plants.
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Regulatory and legal challenges over the validity the New York CES have been made, the outcomes of which remain uncertain. Also in August 2016,
Generation executed a series of agreements with Entergy to acquire the Fitzpatrick nuclear generating station, subject to various regulatory
approvals. The transaction is anticipated to close in the first or second quarter of 2017. See Note 3—Regulatory Matters Matters of the Combined
Notes to the Consolidated Financial Statements for regulatory updates related to the New York CES, Note 9—Early Nuclear Plant Retirements of the
Combined Notes to the Consolidated Financial Statements for additional information relative to Ginna and Nine Mile Point, and Note 4—Mergers,
Acquisitions, and Dispositions of the Combined Notes to the Consolidated Financial Statements for additional information on Generation’s proposed
acquisition of FitzPatrick.
Potential Early Nuclear Plant Retirements
Exelon and Generation continually evaluate the current and expected economic value of each of Generation’s nuclear plants. Factors that will
continue to affect the economic value of Generation’s nuclear plants include, but are not limited to: market power prices, results of capacity auctions,
potential legislative and regulatory solutions to ensure nuclear plants are fairly compensated for their carbon-free emissions, and the impact of final
rules from the EPA requiring reduction of carbon and other emissions and the efforts of states to implement those final rules. In 2015 and 2016,
Generation identified the Clinton, Quad Cities, Ginna, Nine Mile Point, and Three Mile Island nuclear plants as having the greatest risk of early
retirement based on economic valuation and other factors. On June 2, 2016, Generation announced its decision to shut down the Clinton and Quad
Cities nuclear plants on June 1, 2017 and June 1, 2018, respectively; thereby resulting in accelerated depreciation for these plant assets thereafter.
With the passage of the Illinois ZES on December 7, 2016, Generation reversed its original decision, and revised the expected economic useful lives
for both facilities to 2027 for Clinton and to 2032 for Quad Cities. Furthermore, assuming the successful implementation of the Illinois ZES and the
New York CES for their entire terms, Generation no longer considers Clinton, Quad Cities, Ginna or Nine Mile Point to be at heightened risk of early
retirement. Generation currently considers Three Mile Island to be at the greatest risk of early retirement due to current economic valuations and
other factors. See Note 9—Early Nuclear Plant Retirements of the Combined Notes to the Consolidated Financial Statements for additional
information.
Like-Kind Exchange
On September 19, 2016, the United States Tax Court rejected Exelon’s position on its 1999 income tax return to defer under the like-kind
exchange provisions of the IRC $1.2 billion of tax gain on the sale of ComEd’s fossil generating assets. In addition, contrary to Exelon’s evaluation
that any penalty was unwarranted, the Tax Court ruled that Exelon is liable for the penalty and interest thereon asserted by the IRS, pursuant to
which Exelon and ComEd recorded charges to earnings in 2016 of $106 million and $86 million, respectively. Exelon expects to timely appeal this
decision to the U.S. Court of Appeals for the Seventh Circuit. While awaiting a final calculation from the IRS, Exelon estimates an approximate
$1.4 billion payment will be due, including $300 million form ComEd, in the second quarter of 2017 at the time it expects to file its appeal. Of this
amount, Exelon deposited with the IRS $1.25 billion in October 2016, with the remainder to be paid at the time the appeal is filed. See Note 15—
Income Taxes of the Combined Notes to Consolidated Financial Statements for further information related to the like-kind exchange tax matter,
including Exelon’s agreement to hold ComEd harmless from any unfavorable impacts of after-tax interest or penalty amounts on ComEd’s equity.
BGE 2015 Electric and Natural Gas Distribution Base Rates
On November 6, 2015, and as amended through the course of the proceeding, BGE filed for electric and natural gas base rate increases with
the MDPSC, which included recovery of electric and
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natural gas smart grid initiative costs. On June 3, 2016, the MDPSC issued an order in which the MDPSC found compelling evidence to conclude
that BGE’s smart grid initiative overall was cost beneficial to customers. However, the June 3 order contained several cost disallowances and
adjustments, which BGE filed a petition for rehearing on and certain of which were reversed by the MDPSC in an order issued on July 29, 2016. See
Note 3—Regulatory Matters of the Combined Notes to Consolidated Financial Statements for further information.
Pepco Maryland 2016 Electric Distribution Base Rates
On November 15, 2016, the MDPSC approved an increase in electric distribution base rates of $53 million based on a ROE of 9.55%. The new
rates became effective for services rendered on or after November 15, 2016. MDPSC also approved Pepco’s recovery of substantially all of its
capital investment and regulatory assets associated with its AMI program as part of the newly effective rates as well as recovery over a five-year
period of transition costs related to a new billing system implemented in 2015. As a result, during the fourth quarter of 2016, Exelon, PHI and Pepco
established a regulatory asset of $13 million, wrote off $3 million in disallowed AMI costs and recorded a pre-tax credit to net income for $10 million.
Additionally, the MDPSC denied Pepco’s request to extend its Grid Resiliency Program surcharge for new system reliability and safety improvement
projects, with costs for such programs to be recovered going forward through base rates. See Note 3—Regulatory Matters of the Combined Notes to
Consolidated Financial Statements for further information.
DPL Delaware 2016 Electric and Natural Gas Distribution Base Rates
The DPSC approved provisional increases in annual electric and natural gas distribution base rates of $2.5 million effective May 17, 2016, and
an additional $30 million effective December 17, 2016, for electric and of $2.5 million effective May 17, 2016, and an additional $10 million effective
December 17, 2016, for gas. These increases are subject to refund based on the final DPSC orders. See Note 3—Regulatory Matters of the
Combined Notes to Consolidated Financial Statements for further information.
DPL filed an application with the DPSC to increase its annual electric and natural gas distribution base rates by $63 million and $22 million,
respectively, based on a requested ROE of 10.6%. While the DPSC is not required to issue a decision on the application within a specified period of
time, Delaware law allowed DPL to put into effect $2.5 million of each of the rate increases two months after filing the applications which were
effective July 16, 2016. On December 1, 2016, the DPSC approved that an additional $30 million in electric distribution base rates be implemented
effective December 17, 2016, subject to refund based on the final DPSC order, and an additional $10 million in gas base rates be implemented
effective December 17, 2016, subject to refund based on the final DPSC order. See Note 3—Regulatory Matters of the Combined Notes to
Consolidated Financial Statements for further information.
ACE 2016 Electric Distribution Base Rates
On August 24, 2016, the NJBPU issued an order approving a stipulation of settlement among ACE, the New Jersey Division of Rate Counsel,
NJBPU Staff and Unimin Corporation, and an increase of $45 million (before New Jersey sales and use tax) to its electric distribution base rates,
with the new rates effective immediately. The stipulation of settlement provided that a determination on PowerAhead would be separated into a
phase II of the rate proceeding and decided at a later date, most likely in the first quarter of 2017. See Note 3—Regulatory Matters of the Combined
Notes to Consolidated Financial Statements for further information.
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Exelon’s Strategy and Outlook for 2017 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:
•
•
Exelon’s utilities provide a foundation for stable earnings, which translates to a stable currency in our stock.
Generation’s competitive businesses provide free cash flow to invest primarily into 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 Exelon utilities 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 Exelon utilities 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, ComEd, PECO and BGE anticipate
making significant future investments in smart meter 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 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 has approved a dividend policy providing a raise of 2.5% each year for three years, beginning with the June
2016 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. See ITEM 1A. RISK FACTORS for
additional information.
Continually optimizing the cost structure is a key component of Exelon’s financial strategy. Through a recent focused cost management
program, the company has committed to reducing operation and maintenance expenses and capital costs by approximately $350 million and
$50 million,
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respectively, of which approximately 35% of run-rate savings was achieved by the end of 2016. Approximately 60% of run-rate savings are expected
to be achieved by the end of 2017 and fully realized in 2018. At least 75% of the savings are expected to be allocated to Generation, with the
remaining amount allocated to the Utility Registrants.
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 provides an opportunity to accelerate Exelon’s regulated growth to provide stable cash flows,
earnings accretion, and dividend support. Additionally, the Utility Registrants anticipate investing approximately $25 billion over the next five years in
electric and natural gas infrastructure improvements and modernization projects, including smart meter and smart grid initiatives, storm hardening,
advanced reliability technologies, and transmission projects, which is projected to result in an increase to current rate base of approximately
$9 billion by the end of 2021. The Utility Registrants invest in rate base where beneficial to customers and the community by increasing reliability and
the service experience or otherwise meeting customer needs. These investments are made at the lowest reasonable cost to customers.
See Note 3—Regulatory Matters of the Combined Notes to Consolidated Financial Statements for additional information on the Smart Meter
and Smart Grid Initiatives and infrastructure development and enhancement programs.
Competitive Energy Businesses . Generation continually assesses the optimal structure and composition of our generation assets as well as
explores wholesale and retail opportunities within the power and gas sectors. Generation’s long-term growth strategy is to prioritize investments in
long-term contracted generation across multiple technologies and identify and capitalize on opportunities that provide generation to load matching as
a means to provide stable earnings, while identifying emerging technologies where strategic investments provide the option for significant future
growth or influence in market development. As of December 31, 2016, Generation has currently approved plans to invest a total of approximately
$1 billion in 2017 through 2019 on capital growth projects (primarily new plant construction and distributed generation).
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, $0.5 billion, $0.5 billion and $0.4 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.
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Project Financing
Generation utilizes individual project financings as a means to finance the construction of various generating asset projects. Project financing
is based upon a nonrecourse financial structure, in which project debt and equity used to finance the project are paid back from the cash generated
by the newly constructed asset once operational. 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 life. See Note 14—Debt and Credit Agreements of the Combined Notes
to the Consolidated Financial Statements for additional information on nonrecourse debt.
ExGen Texas Power
In September 2014, ExGen Texas Power, LLC (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.
EGTP’s operating cash flows have been negatively impacted by certain market conditions including, but not limited to: low power prices, higher fuel
prices and the seasonality of its cash flows . Despite the declining operating cash flows, EGTP remains in compliance with its covenants related to
the project specific financing. Management continues to monitor the project entity’s short term liquidity needs. See Note 14—Debt and Credit
Agreements of the Combined Notes to the Consolidated Financial Statements for additional information on the EGTP.
Other Key Business Drivers and Management Strategies
Utility Rates and Rate Proceedings
The Utility Registrants file rate cases with their regulatory commissions seeking increases or decreases to their electric transmission and
distribution, and gas distribution rates to recover their costs and earn a fair return on their investments. The outcomes of these regulatory
proceedings impact the Utility Registrants’ current and future results of operations, cash flows and financial position. See Note 3—Regulatory
Matters of the Combined Notes to Consolidated Financial Statements for further details 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).
Capacity Market Changes in PJM
In the wake of the January 2014 Polar Vortex that blanketed much of the Eastern and Midwestern United States, it became clear that while a
major outage event was narrowly avoided, resources in PJM were not providing the level of reliability expected by customers. As a result, on
December 12,
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2014, PJM filed at FERC a proposal to make significant changes to its current capacity market construct, the Reliability Pricing Model (RPM). PJM’s
proposed changes generally sought to improve resource performance and reliability largely by limiting the excuses for non-performance and by
increasing the penalties for performance failures. The proposal permits suppliers to include in capacity market offers additional costs and risk so they
can meet these higher performance requirements. While offers are expected to put upward pressure on capacity clearing prices, operational
improvements made as a result of PJM’s proposal are expected to improve reliability, to reduce energy production costs as a result of more efficient
operations and to reduce the need for out of market energy payments to suppliers. Generation participated actively in PJM’s stakeholder process
through which PJM developed the proposal and also actively participated in the FERC proceeding including filing comments. On June 9, 2015,
FERC approved PJM’s filing largely as proposed by PJM, including transitional auction rules for delivery years 2016/2017 through 2017/2018. As a
result of this and several related orders, PJM hosted its 2018/2019 Base Residual Auction (results posted on August 21, 2015) and its transitional
auction for delivery year 2016/2017 (results posted on August 31, 2015) and its transitional auction for delivery years 2017/2018 (results posted on
September 9, 2015). On May 10, 2016, FERC largely denied rehearing, and a number of parties appealed to the U.S. Court of Appeals for the DC
Circuit for review of the decision. It is too early in the process to predict the appeal outcome.
MISO Capacity Market Results
On April 14, 2015, the Midcontinent Independent System Operator (MISO) released the results of its capacity auction covering the June 2015
through May 2016 delivery year. As a result of the auction, capacity prices for the zone 4 region in downstate Illinois increased to $150 per MW per
day beginning in June 2015, an increase from the prior pricing of $16.75 per MW per day that was in effect from June 2014 to May 2015. Generation
had an offer that was selected in the auction. However, due to Generation’s ratable hedging strategy, the results of the capacity auction have not
had a material impact on Exelon’s and Generation’s consolidated results of operations and cash flows.
Additionally, in late May and June 2015, separate complaints were filed at the FERC by each of the State of Illinois, the Southwest Electric
Cooperative, Public Citizens, Inc., and the Illinois Industrial Energy Consumers challenging the results of this MISO capacity auction for the
2015/2016 delivery in MISO delivery zone 4. The complaints allege generally that 1) the results of the capacity auction for zone 4 are not just and
reasonable, 2) the results should be suspended, set for hearing and replaced with a new just and reasonable rate, 3) a refund date should be
established and that 4) certain alleged behavior by one of the market participants other than Exelon or Generation, be investigated.
On October 1, 2015, the FERC announced that it was conducting a non-public investigation (that does not involve Exelon or Generation) into
whether market manipulation or other potential violations occurred related to the auction. On December 31, 2015, the FERC issued a decision that
certain of the rules governing the establishment of capacity prices in downstate Illinois are “not just and reasonable” on a prospective basis. The
FERC ordered that certain rules be changed prior to the April 2016 auction which set capacity prices for the 2016/2017 planning year. In response to
this order, MISO filed certain rule changes with the FERC. On March 18, 2016, FERC largely denied rehearing of its December 31, 2015 order.
FERC continues to conduct its non-public investigation to determine if the April 2015 auction results were manipulated and, if so, whether refunds
are appropriate. The FERC did establish May 28, 2015, the day the first complaint was filed, as the date from which refunds (if ordered) would be
calculated, and it also made clear that the findings in the December 31, 2015 order do not prejudge the investigation or related proceedings.
Generation cannot predict the impact the FERC order may ultimately have on future auction results, capacity pricing or decisions related to the
potential early retirement of the Clinton nuclear plant, however, such impacts could be material to Generation’s future results of operations and cash
flows. See Note 9—Early Nuclear Plant Retirements of the Combined Notes to the Consolidated Financial Statements for additional information on
the impacts of the MISO announcement.
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MISO has acknowledged the need for capacity market design changes in the zone 4 regions, and on November 1, 2016 filed a comprehensive
capacity market proposal for the zone 4 region (as well as another zone). It is too early to predict the outcome of that filing. Exelon is generally
supportive of such changes. However, several fossil generators have requested that FERC impose an expanded minimum offer price rule (MOPR)
that could affect capacity offers from the Clinton nuclear plant. See Note 9—Early Nuclear Plant Retirements of the Combined Notes to the
Consolidated Financial Statements for additional information on the impacts of the MISO announcement. Exelon is actively participating in this
aspect of the proceeding, seeking to avoid the implementation of such a MOPR mechanism. However, it is too early in the proceeding to predict.
Subsidized Generation
The rate of expansion of subsidized generation, in the markets in which Generation’s output is sold can negatively impact wholesale power
prices, and in turn, Generation’s results of operations.
Various states have attempted to implement or propose legislation, regulations or other policies to subsidize new generation development
which may result in artificially depressed wholesale energy and capacity prices. For example, the New Jersey legislature enacted into law in January
2011, the Long Term Capacity Pilot Program Act (LCAPP). LCAPP provides eligible generators with 15-year fixed contracts for the sale of capacity
in the PJM capacity market. Under LCAPP, the local utilities in New Jersey are required to pay (or receive) the difference between the price eligible
generators receive in the capacity market and the price guaranteed under the 15-year contract. New Jersey ultimately selected three proposals to
participate in LCAPP and build new generation in the state. In addition, on April 12, 2012, the MDPSC issued an order directing the Maryland electric
utilities to enter into a 20-year contract for differences (CfD) with CPV Maryland, LLC (CPV), under which CPV was required to construct an
approximately 700 MW combined cycle gas turbine in Waldorf, Maryland. The CfD mandated that utilities (including BGE, Pepco and DPL) pay (or
receive) the difference between CPV’s contract price and the revenues it receives for capacity and energy from clearing the unit in the PJM capacity
market.
Exelon and others challenged the constitutionality and other aspects of the New Jersey legislation in federal court. The actions taken by the
MDPSC were also challenged in federal court in an action to which Exelon was not a party. The federal trial courts in both the New Jersey and
Maryland actions effectively invalidated the actions taken by the New Jersey legislature and the MDPSC, respectively. Each of those decisions was
upheld by the U.S. Court of Appeals for the Third Circuit and the U.S. Court of Appeals for the Fourth Circuit, respectively. On April 19, 2016, the
U.S. Supreme Court affirmed the decision of the U.S. Court of Appeals for the Fourth Circuit, and subsequently denied certiorari with respect to the
appeal from the U.S. Court of Appeals for the Third Circuit, leaving in place that court’s decision. The matter is now considered closed.
As required under their contracts, generator developers who were selected in the New Jersey and Maryland programs (including CPV) offered
and cleared in PJM’s capacity market auctions. To the extent that the state-required customer subsidies are included under their respective
contracts, Exelon believes that these projects may have artificially suppressed capacity prices in PJM in these auctions and may continue to do so in
future auctions to the detriment of Exelon. While the court decisions are positive developments, continuation of these state efforts, if successful and
unabated by an effective minimum offer price rule (MOPR) for future capacity auctions, could continue to result in artificially depressed wholesale
capacity and/or energy prices. Other states could seek to establish programs, which could substantially impact Exelon’s position and could have a
significant effect on Exelon’s financial results of operations, financial position and cash flows.
One such state is Ohio, where state-regulated utility companies FirstEnergy Ohio (FE) and AEP Ohio (AEP) initiated actions at the Public
Utilities Commission of Ohio (PUCO) to obtain approval for Riders that would effectively allow these two companies to pass through to all customers
in their service territories the differences between their costs and market revenues on PPAs entered into
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between the utility and its merchant generation affiliate for what was collectively more than 6,000MW of primarily coal-fired generation. Thus, the
Riders were similar to the CfDs described above (except that the PPA Riders in Ohio would apply to existing generation facilities whereas the CfDs
applied to new generation facilities). While FERC orders on April 27, 2016 largely alleviated the concerns related to the Riders by holding that the
PPAs ran afoul of affiliate restrictions on FE and AEP, we continue to closely monitor developments in Ohio.
In addition, Exelon continues to monitor developments in Maryland, New Jersey, and other states and participates in stakeholder and other
processes to ensure that similar state subsidies are not developed. Exelon remains active in advocating for competitive markets, while opposing
policies that require taxpayers and/ or consumers to subsidize or give preferential treatment to generation providers or technologies that do not
provide superior reliability or environmental benefits, or that would threaten the reliability and value of the integrated electricity grid.
Complaints at FERC Seeking to Mitigate Illinois and New York Programs Providing ZECs
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 remove the revenues it receives through a federal, state or other
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 resources. Exelon has generally opposed policies that required subsidies or give preferential treatment to
generation providers or technologies that do not provide superior reliability or environmental benefits, or that would threaten the reliability and value
of the integrated electricity grid. Thus, Exelon has supported a MOPR as a means of minimizing the detrimental impact of certain subsidized
resources could have on capacity markets (such as the New Jersey (LCAPP) and Maryland (CfD) programs. However, in Exelon’s view, MOPRs
should not be applied to resources that receive compensation for providing superior reliability or environmental benefits.
On January 9, 2017, the Electric Power Supply Association (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. Both filings allege that the
relevant MOPR should be expanded to also apply to existing resources receiving ZEC compensation under the New York CES and Illinois ZES
programs. Exelon has 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 that have generally not been subject to a MOPR. However, if successful, an expanded MOPR
could result in mitigation of Generation’s Quad Cities, Ginna, and Nine Mile Point facilities, which are expected to receive ZEC compensation, such
that they would have an increased risk of not clearing in future capacity auctions and thus no longer receiving capacity revenues during the
respective ZEC programs. This would also impact the FitzPatrick facility that Generation is currently in the process of acquiring from Entergy. 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
timing of FERC’s decision with respect to both proceedings is currently unknown and the outcome of these matters is currently uncertain.
Energy Demand
Modest economic growth partially offset by energy efficiency initiatives is resulting in positive growth for electricity for Pepco, a decrease in
projected load for electricity for BGE, DPL and ACE, and an essentially flat projected load for electricity for ComEd and PECO. ComEd, PECO, BGE,
Pepco, DPL and ACE are projecting load volumes to increase (decrease) by (0.3)%, 0.6%, (1.4)%, (1.7)%, 0.8% and (0.7)%, respectively, in 2017
compared 2016.
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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. The market experienced high price volatility in the first quarter of 2014 which contributed to bankruptcies and
consolidations within the industry during the year. However, 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 quarter 2016 dividends of $0.31 per share each on Exelon’s common stock. The second, third and
fourth quarter 2016 dividends declared was $0.318 on Exelon’s common stock, and the first quarter 2017 dividends declared was $0.328 per share.
The dividends for the first, second, third and fourth quarter 2016 were paid on March 10, 2016, June 10, 2016, September 9, 2016 and December 9,
2016, respectively. The first quarter 2017 dividend is payable on March 10, 2017.
Exelon’s Board of Directors has approved a dividend policy providing a raise of 2.5% each year for three years, beginning with the June 2016
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 2017 and 2018. 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, 2016, the percentage of expected generation hedged
for the major reportable segments was 91%-94%, 56%-59% and 28%-31% for 2017, 2018, and 2019 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
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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 39% of Generation’s uranium concentrate
requirements from 2017 through 2021 are supplied by three producers. In the event of non-performance by these or other suppliers, Generation
believes that replacement uranium concentrate can be obtained, although at prices that may be unfavorable when compared to the prices under the
current supply agreements. Non-performance by these counterparties could have a material adverse impact on Exelon’s and Generation’s results of
operations, cash flows and financial position.
The Utility Registrants mitigate commodity price risk through regulatory mechanisms that allow them to recover procurement costs from retail
customers.
Tax Matters
Potential Corporate Tax Reform
The results of the November 2016 U.S. elections have introduced greater uncertainty with respect to federal tax policies. President Trump has
stated that one of his top priorities is comprehensive tax reform and House Republicans plan to advance their tax reform “blueprint”. Tax reform
proposals call for a reduction in the corporate federal income tax rate from the current 35% to as low as 15%. Other proposals provide, among other
items, for the immediate deduction of capital investment expenditures and full or partial elimination of debt interest expense deductions. It is
uncertain whether, to what extent or when these or any other changes in federal tax policies will be enacted or the transition time frame for such
changes. Further, for the Utility Registrants, regulators may impose rate reductions to provide the benefit of any income tax expense reductions to
customers and refund “excess” deferred income taxes previously collected through rates. The amounts and timing of any such rate changes would
be subject to the discretion of the rate regulator in each specific jurisdiction. For these reasons, the Registrants cannot predict the impact any
potential changes may have on their future results of operations, cash flows or financial position, and such changes could be material.
See Note 15—Income Taxes of the Combined Notes to the Consolidated Financial Statements for additional information
Environmental Legislative and Regulatory Developments
Exelon is actively involved in the EPA’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 electric generating units, as set forth in the discussion below. These regulations have a disproportionate adverse impact on fossil-
fuel power plants, requiring significant expenditures of capital and variable operating and maintenance expense, and have resulted in the retirement
of older, marginal facilities. Retirements of coal-fired power plants will continue as additional EPA regulations take effect, and as air quality standards
are updated and further restrict emissions. Due to its low emission generation portfolio, Generation will not be significantly directly affected by these
regulations, representing a competitive advantage relative to electric generators that are more reliant on fossil-fuel plants. Various bills have been
introduced in the U.S. Congress that would prohibit or impede the EPA’s rulemaking efforts, and it is uncertain whether any of these bills will become
law.
Air Quality
In recent years, the EPA has been implementing a series of increasingly stringent regulations under the Clean Air Act applicable to electric
generating units. These regulations have resulted in more stringent emissions limits on fossil-fuel electric generating stations as states implement
their compliance plans.
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National Ambient Air Quality Standards (NAAQS). The EPA continues to review and update its NAAQS for conventional air pollutants relating
to ground-level ozone and emissions of particulate matter, SO2 and NOx. Following five years of litigation, the EPA is implementing the Cross State
Air Pollution Rule that requires upwind states in the eastern half of the United States to significantly improve air quality by reducing power plant
emissions that cross state lines and contribute to ground-level ozone and fine particle pollution in downwind states, and otherwise contributes to
non-attainment status of downwind states with the various NAAQS requirements.
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. As such, 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.
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” of “Convention”). See ITEM 1.—BUSINESS,“Global Climate Change” for further discussion.
Water Quality
Section 316(b) of the Clean Water Act requires that 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 changes to the existing regulations. Those facilities are Calvert Cliffs, Clinton, Dresden, Eddystone, Fairless Hills, Ginna,
Gould Street, Handley, Mountain Creek, Mystic 7, Nine Mile Point Unit 1, Oyster Creek, Peach Bottom, Quad Cities, Riverside, Salem and Schuylkill.
See ITEM 1.—BUSINESS ,“Water Quality” for further discussion.
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 reserves 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
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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 24—Commitments and Contingencies of the Combined Notes to Consolidated Financial Statements for further detail related to
environmental matters, including the impact of environmental regulation.
Other Legislative and Regulatory Developments
NRC Task Force on Fukishima
In July 2011, an NRC Task Force formed in the aftermath of the March 11, 2011, 9.0 magnitude earthquake and ensuing tsunami, that
seriously damaged the nuclear units at the Fukushima Daiichi Nuclear Power Station, issued a report of its review of the accident, including tiered
recommendations for future regulatory action by the NRC to be taken in the near and longer term. The Task Force’s report concluded that nuclear
reactors in the United States are operating safely and do not present an imminent risk to public health and safety. The NRC and its staff have issued
orders and implementation guidance for commercial reactor licensees operating in the United States. The NRC and its staff are continuing to
evaluate additional requirements. Generation has assessed the impacts of the Tier 1 orders and information requests and will continue monitoring
the additional recommendations under review by the NRC staff, both from an operational and a financial impact standpoint. A comprehensive review
of the NRC Tier 1 orders and information requests, as well as preliminary engineering assumptions and analysis, indicate that the financial impact of
compliance for Generation, net of expected co-owner reimbursements, for the period from 2017 through 2019 is expected to be between
approximately $75 million and $100 million of capital and $15 million of operating expense. Generation’s current assessments are specific to the Tier
1 recommendations. The NRC has not finalized actions with respect to the Tier 2 and Tier 3 recommendations and is expected to do so in 2017.
Exelon and Generation are unable to conclude at this time to what extent any actions to comply with the requirements of Tier 2 and Tier 3 will impact
their future financial position, results of operations, and cash flows. Generation will continue to engage in nuclear industry assessments and actions
and stakeholder input.
Employees
During 2016, Exelon BSC and ComEd extended the collective bargaining agreement (CBA) with IBEW Local 15 by three years; with an
expiration date of September 30, 2022. Exelon Generation extended its CBA with both the IBEW Local 15 (covering the five (5) Midwest nuclear
plants) and IBEW Local 51 (Clinton) by three years; with expiration dates of April 30, 2022 and December 15, 2023, respectively. Additionally,
Exelon Nuclear Security successfully ratified its CBA with the UGSOA Local 17 at Oyster Creek to an extension of five (5) years, and Exelon Power
successfully ratified its CBA with the IBEW Local 614 to a three (3) extension. In January 2017, an election was held at BGE which resulted in union
representation for approximately 1,400 employees. BGE and IBEW Local 410 will begin negotiations for 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.
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
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amounts of assets and liabilities reported in the financial statements. Management discusses these policies, estimates and assumptions with its
Accounting and Disclosure Governance Committee on a regular basis and provides periodic updates on management decisions to the Audit
Committee of the Exelon Board of Directors. 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
discussion 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 $8.7 billion at December 31, 2016. The authoritative guidance
requires that Generation estimate its obligation for the future decommissioning of its nuclear generating plants. To estimate that liability, Generation
uses an internally-developed, probability-weighted, discounted cash flow model which, on a unit-by-unit basis, considers multiple decommissioning
outcome scenarios.
As a result of recent nuclear plant retirements in the industry, nuclear operators and third-party service providers are obtaining more
information about costs associated with decommissioning activities. At the same time, regulators are gaining more information about
decommissioning activities which could result in changes to existing decommissioning requirements. In addition, as more nuclear plants are retired,
it is possible that technological advances will be identified that could create efficiencies and lead to a reduction in decommissioning costs. The
availability of decommissioning trust 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
methodologies and significant estimates and assumptions described as follows:
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 (such as a change in assumed operating life for a nuclear plant). 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.
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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. Probabilities are also assigned
to four different decommissioning approaches. In response to expected increased security costs for spent fuel stored in the spent fuel pool (wet
storage), in 2016 Generation has evaluated an alternative approach for managing spent fuel between the date of a plant’s cessation of operations
and the fuel’s acceptance for disposal by the DOE. This new approach, the Shortened SAFSTOR approach, provides for increased usage of dry
cask storage for the spent fuel, and is now considered as one of the decommissioning approaches in determining the ARO as follows:
1.
2.
3.
4.
DECON—a method of decommissioning shortly after the cessation of operation in which the equipment, structures, and portions of a
facility and site containing radioactive contaminants are removed and safely buried in a LLRW landfill or decontaminated to a level that
permits property to be released for unrestricted use. Spent fuel is transferred to dry cask storage as soon as possible until DOE
acceptance for disposal.
Delayed DECON—similar to the DECON scenario but with a delay to allow for spent fuel to be removed from the site prior to onset of
decommissioning activities. Spent fuel is retained in existing location (either wet or dry storage) until DOE acceptance for disposal.
Shortened SAFSTOR—similar to the DECON scenario but with generally a 30 year delay prior to onset of decommissioning activities.
Spent fuel is transferred to dry cask storage as soon as possible until DOE acceptance for disposal.
SAFSTOR—a method of decommissioning in which the nuclear facility is placed and maintained in such condition that the nuclear facility
can be safely stored and subsequently decontaminated to levels that permit release for unrestricted use generally within 60 years after
cessation of operations. Spent fuel is transferred to dry cask storage as soon as possible until DOE acceptance for disposal.
The actual decommissioning approach selected once a nuclear facility is shutdown will be determined by Generation at the time of shutdown
and may be influenced by multiple factors including the funding status of the nuclear decommissioning trust fund at the time of shutdown.
The assumed plant shutdown timing scenarios include the following four alternatives: (1) the probability of operating through the original
40-year nuclear license term, (2) the probability of operating through an extended 60-year nuclear license term (regardless of whether such 20-year
license extension has been received for each unit), (3) the probability of a second, 20-year license renewal for some nuclear units, and (4) the
probability of early plant retirement for certain sites due to changing market conditions and regulatory environments. The successful operation of
nuclear plants in the U.S. beyond the initial 40-year license terms has prompted the NRC to consider regulatory and technical requirements for
potential plant operations for an 80-year nuclear operating term. As power market and regulatory environment developments occur, Generation
evaluates and incorporates, as necessary, the impacts of such developments into its nuclear ARO assumptions and estimates.
Generation’s probabilistic cash flow models also include an assessment of the timing of DOE acceptance of SNF for disposal. Generation
currently assumes DOE will begin accepting SNF in 2030. The SNF acceptance date assumption is based on management’s estimates of the
amount of time required for DOE to select a site location and develop the necessary infrastructure for long-term SNF storage. For more information
regarding the estimated date that DOE will begin accepting SNF, see Note 24—Commitments and Contingencies of the Combined Notes to
Consolidated Financial Statements.
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License Renewals
Except for its Clinton unit, Generation has successfully obtained initial 20-year operating license renewal extensions (i.e. extending the total
license term to 60 years) for all of its operating nuclear units (including the two Salem units co-owned by Generation, but operated by PSEG).
Generation intends to apply for an initial 20-year renewal for the Clinton unit. No prior Generation license extension application has been denied.
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. The accounting guidance required Generation
to establish an ARO at fair value at the time of the initial adoption of the current accounting standard. Subsequent to the initial adoption, the ARO is
adjusted for changes to estimated costs, timing of future cash flows and modifications to decommissioning assumptions, as described above.
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.
Under the current accounting framework, the ARO is not required or permitted to be re-measured for changes in the CARFR that occur in
isolation. This differs from the accounting requirements for other long-dated obligations, such as pension and other post-employment benefits that
are required to be re-measured as and when corresponding discount rates change. If Generation’s future nominal cash flows associated with the
ARO were to be discounted at current prevailing CARFRs, the obligation would increase from approximately $8.7 billion to approximately $9.7 billion.
To illustrate 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: i) had Generation used the 2015 CARFRs rather than the 2016 CARFRs in performing its annual
2016 ARO update, Generation would have decreased the ARO by an additional $45 million; and ii) if the CARFR used in performing the annual 2016
ARO update was increased by 100 basis points or decreased by 50 basis points, the ARO would have decreased by $1.2 billion and increased by
$150 million, respectively, as compared to the actual decrease of $385 million.
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.
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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 20 percent
Increase the likelihood of the DECON scenario by 10 percentage points and decrease the likelihood of the
SAFSTOR scenario by 10 percentage points
Shorten each unit’s probability weighted operating life assumption by 2 years
Extend the estimated date for DOE acceptance of SNF to 2035
Increase (Decrease) to
ARO at
December 31, 2016
$
1,730
1,610
470
840
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For more information regarding accounting for nuclear decommissioning obligations, see Note 1—Significant Accounting Policies, Note 9—
Early Nuclear Plant Retirements and Note 16—Asset Retirement Obligations of the Combined Notes to Consolidated Financial Statements.
Goodwill (Exelon, Generation, ComEd, PHI and DPL)
As of December 31, 2016, 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 as part of the formation of Exelon and $4 billion at PHI pursuant to Exelon’s acquisition of PHI in the first quarter of
2016. DPL has $8 million of goodwill as of December 31, 2016, related to its 1995 acquisition of the Conowingo Power Company. Generation also
has goodwill of $47 million as of December 31, 2016. Under the provisions of the authoritative guidance for goodwill, these entities are required to
perform an assessment for possible impairment of their goodwill at least annually or more frequently if an event occurs or circumstances change that
would more likely than not reduce the fair value of the reporting units below their carrying amount. Under the authoritative guidance, 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, and PHI’s operating
segments are Pepco, DPL and ACE. See Note 26—Segment Information of the Combined Notes to Consolidated Financial Statements for additional
information. There is no level below these operating segments for which operating results are regularly reviewed by segment management.
Therefore, the ComEd, Pepco, DPL and ACE operating segments are also considered reporting units for goodwill impairment testing purposes.
Exelon’s and ComEd’s $2.6 billion of goodwill has been assigned entirely to the ComEd reporting unit, while Exelon’s and PHI’s $4 billion of goodwill
has been assigned to the Pepco, DPL and ACE reporting units in the amounts of $1.7 billion, $1.1 billion and $1.2 billion, respectively. DPL’s
$8 million of goodwill is assigned entirely to the DPL reporting unit.
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 conditions and 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.
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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. 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 accounting guidance in order to determine the implied fair value of goodwill. If the implied 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.
Exelon, ComEd, PHI and DPL performed quantitative tests as of November 1, 2016, for their 2016 annual goodwill impairment assessments.
The first step of the tests comparing the estimated fair values of the ComEd, Pepco, DPL and ACE reporting units to their carrying values, including
goodwill, indicated no impairments of goodwill; therefore, no second steps were 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, PHI’s
or DPL’s goodwill, which could be material. Based on the results of the annual goodwill tests performed as of November 1, 2016, the estimated fair
values of the ComEd, Pepco, DPL and ACE reporting units would have needed to decrease by more than 30%, 10%, 10% and 10%, respectively,
for Exelon, ComEd and PHI to have failed the first step of their respective impairment tests. For the $8 million of goodwill recorded at DPL related to
DPL’s 1995 acquisition of the Conowingo Power Company, the fair value of the DPL reporting unit would have needed to decrease by more than
50% for DPL to fail the first step of the impairment test.
See Note 1—Significant Accounting Policies, Note 11—Intangible Assets and Note 15—Income Taxes of the Combined Notes to Consolidated
Financial Statements for additional information.
Purchase Accounting (Exelon, Generation and PHI)
In accordance with the authoritative accounting guidance, the 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 it exceeds the estimated net fair value and as a bargain purchase gain on
the income statement if it is below 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, can materially impact the financial statements in periods after acquisition, such as through depreciation and
amortization expense. Accounting guidance provides that the allocation of the purchase price may be modified up to one year from the date of the
merger as more information is obtained about the fair
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value of assets acquired and liabilities assumed. See Note 4—Mergers, Acquisitions, and Dispositions of the Combined Notes to Consolidated
Financial Statements for additional information.
Unamortized Energy Contract Assets and Liabilities (Exelon, Generation, PHI, Pepco, DPL and ACE)
Unamortized energy contract assets and liabilities represent the remaining unamortized balances of non-derivative energy contracts that
Generation has acquired and the electricity and gas energy supply contracts Exelon has acquired as part of the PHI acquisition. The initial amount
recorded represents the fair value of the contracts at the time of acquisition. 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. Amortization expense and income are recorded through purchased
power and fuel expense or operating revenues, respectively. Refer to Note 3—Regulatory Matters, Note 4—Mergers, Acquisitions, and Dispositions
and Note 11—Intangible Assets of the Combined Notes to Consolidated Financial Statements for further discussion.
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, specific regulatory disallowance, advances in technology, or plans to dispose of a long-
lived asset significantly before the end of its useful life, 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, costs 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
effect on 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).
On a quarterly basis, Generation assesses its 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 less costs to sell. 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
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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.
Generation evaluates its equity method investments and other investments in debt and equity securities to determine whether or not they are
impaired based on whether the investment has experienced a decline in value that is not temporary in nature.
See Note 8—Impairment of Long-Lived Assets 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 composite method in which depreciation is calculated using the average
estimated useful life of assets within an asset group. The estimation of asset useful lives requires management judgment, supported by formal
depreciation studies of historical asset retirement experience. Depreciation studies are 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 rates, unless the depreciation rates reflected in rates do not align with management’s judgment as to an appropriate estimated
useful life or have not been updated on a timely basis. Consistent with each utility’s regulatory recovery method, the Utility Registrant’s depreciation
expense for each asset group includes an amount for the estimated cost of dismantling and removing plant from service spread straight line over the
asset group’s average remaining useful life. 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 9—Early Nuclear
Plant Retirements of the Combined Notes to the Consolidated Financial Statements for additional information on expected and potential early
nuclear plant retirements.
Generation completed a depreciation rate study during the first quarter of 2015, which resulted in revised depreciation rates effective
January 1, 2015.
ComEd is required to file an electric distribution depreciation rate study at least every five years with the ICC. ComEd completed an electric
distribution and transmission depreciation study and filed the updated depreciation rates with both the ICC and FERC in January 2014, resulting in
new depreciation rates effective first quarter 2014.
PECO is required to file electric distribution and gas depreciation rate studies at least every five years with the PAPUC. In March 2015, PECO
filed a depreciation rate study with the PAPUC for both its electric distribution and gas assets, resulting in new depreciation rates for electric
transmission assets effective January 1, 2015, for gas distribution assets effective July 1, 2015, and for electric distribution assets January 1, 2016.
The MDPSC does not mandate the frequency or timing of BGE’s electric distribution or gas depreciation studies. In July 2014, BGE filed
revised depreciation rates with the MDPSC for both its electric distribution and gas assets, which became effective December 15, 2014.
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The MDPSC does not mandate the frequency or timing of Pepco’s electric distribution depreciation studies, while the DCPSC directs Pepco as
to when it should file an electric distribution depreciation study. In 2016 and 2013, Pepco filed revised electric distribution depreciation rates with the
MDPSC and DCPSC, respectively, with the new rates effective November 15, 2016 and April 16, 2014, respectively.
Neither the DPSC nor the MDPSC mandates the frequency or timing of DPL’s electric distribution or gas depreciation studies. DPL filed
revised depreciation rates for gas assets in 2006, with the new rates effective April 1, 2007. In 2013, DPL filed revised electric distribution
depreciation rates with the MDPSC, with the new rates effective July 20, 2013. On July 20, 2016, DPL filed revised electric depreciation rates with
the MDPSC as part of the electric distribution base rate filing. Any adjustments to the depreciation rates approved by the MDPSC are expected to
take effect in the first quarter of 2017. On May 17, 2016, DPL filed revised electric and natural gas depreciation rates with the DPSC as part of the
electric and natural gas base rate case filing. The DPSC is not required to issue a decision on the application within a specific period of time and
adjustments to the depreciation rates will be made based on the outcome of the final orders, when received.
The NJBPU does not mandate the frequency or timing of ACE’s electric distribution depreciation studies. In 2012, ACE filed revised electric
distribution depreciation rates with the NJBPU, with the new rates effective July 1, 2013.
FERC does not mandate the frequency or timing of electric transmission depreciation studies.
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 employees. See Note 17—
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.
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 costs
attributed to the operating companies are labor costs and are ultimately allocated to projects within the operating companies, some of which are
capitalized.
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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. See Note 17—Retirement Benefits
of the Combined Notes to Consolidated Financial Statements for information on fair value measurements of pension and other postretirement plan
assets, including valuation techniques and classification under the fair value hierarchy in accordance with authoritative guidance.
Expected Rate of Return on Plan Assets
The long-term EROA assumption used in calculating pension costs for Exelon plans was 7.00% for each of 2016, 2015 and 2014. For the
predecessor periods of 2016, 2015 and 2014, the long-term EROA assumption used in calculating pension costs for the PHI plans was 6.50%,
6.50% and 7.00%, respectively. The weighted after-tax average EROA assumption used in calculating other postretirement benefit costs for Exelon
plans was 6.71%, 6.50% and 6.59% in 2016, 2015 and 2014, respectively. For the predecessor periods of 2016, 2015 and 2014, the EROA
assumption used in calculating other postretirement benefit costs for PHI plans was 6.75%, 6.75% and 7.25%, respectively. The pension trust
activity is non-taxable, while other postretirement benefit trust activity is partially taxable. In 2010, Exelon began implementation of a liability-driven
investment strategy in order to reduce the volatility of its pension assets relative to its pension liabilities. Over time, Exelon has decreased its equity
investments and increased its investments in fixed income securities and alternative investments within the pension asset portfolio in order to
achieve a balanced portfolio of liability hedging and return-generating assets. See Note 17—Retirement Benefits of the Combined Notes to
Consolidated Financial Statements for additional information regarding Exelon’s asset allocations. Exelon used an EROA of 7.00% and 6.60% to
estimate its 2017 pension and other postretirement benefit costs, respectively.
Exelon calculates the amount of expected return on pension and other postretirement benefit plan assets by multiplying the EROA by the MRV
of plan assets at the beginning of the year, taking into consideration anticipated contributions and benefit payments to be made during the year. In
determining MRV, the authoritative guidance for pensions and postretirement benefits allows the use of either fair value or a calculated value that
recognizes changes in fair value in a systematic and rational manner over not more than five years. For the majority of pension plan assets, Exelon
uses a calculated value that adjusts for 20% of the difference between fair value and expected MRV of plan assets. Use of this calculated value
approach enables less volatile expected asset returns to be recognized as a component of pension cost from year to year. For other postretirement
benefit plan assets and certain pension plan assets, Exelon uses fair value to calculate the MRV.
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 the Registrants’ pension and other postretirement benefit plans for the year ended December 31, 2016 were 7.30% and 6.02%,
respectively, compared to an expected long-term return assumption of 7.00% and 6.71%, respectively.
Discount Rate
The discount rate used to determine the majority of the December 31, 2016 pension and other postretirement benefit obligations was 4.04%,
representing a weighted-average of the rate for the majority of pension and other postretirement benefit plans. At December 31, 2016 and 2015, for
both Exelon and PHI, 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.
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The discount rate assumptions used to determine the obligation valuation at year end are also used to determine the cost for the following
year. Exelon used discount rates ranging from 3.66% to 4.17% to estimate its 2017 pension and other postretirement benefit costs.
Health Care Cost Trend Rate
Assumed health care cost trend rates impact the costs reported for Exelon’s other postretirement benefit plans for participant populations with
plan designs that do not have a cap on cost growth. Accounting guidance requires that annual health care cost estimates be developed using past
and present health care cost trends (both for Exelon and across the broader economy), as well as expectations of health care cost escalation,
changes in health care utilization and delivery patterns, technological advances and changes in the health status of plan participants. Therefore, the
trend rate assumption is subject to significant uncertainty. Exelon assumed an initial health care cost trend rate of 5.50% for 2016, decreasing to an
ultimate health care cost trend rate of 5.00% in 2017 for the majority of its plans.
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 uses a mortality base table for its accounting
valuation that is consistent with the IRS-required table for determining plan funding requirements pursuant to ERISA (referred to as RP-2000).
Exelon is utilizing the Scale BB 2-Dimensional improvement scale with long-term improvements of 0.75% for its mortality improvement assumption.
The mortality assumption is supported by an actuarial experience study on Exelon’s plan participants performed in 2014.
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 2016 cost:
Discount rate (a)
EROA
Health care cost trend rate
Change in benefit obligation at
December 31, 2016:
Discount rate (a)
Health care cost trend rate
Change in
Assumption
Pension
Other Postretirement
Benefits
Total
$
0.5%
(0.5)%
0.5%
(0.5)%
1.00%
(1.00)%
0.5%
(0.5)%
1.00%
(1.00)%
$
(65)
78
(82)
82
N/A
N/A
(1,119)
1,298
N/A
N/A
(16)
20
(12)
12
9
(8)
(250)
290
105
(95)
$
(81)
98
(94)
94
9
(8)
(1,369)
1,588
105
(95)
(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 implemented a liability-
driven investment strategy for a portion of its pension asset portfolio in 2010. The sensitivities shown above do not reflect the offsetting impact that changes in discount
rates may have on pension asset returns.
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Average Remaining Service Period
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
11.9 years, 11.9 years and 11.8 years for the years ended December 31, 2016, 2015 and 2014, respectively. For the predecessor periods, the
average remaining service period of PHI’s defined benefit plans was approximately 11 years for both 2015 and 2014.
For other postretirement benefits, Exelon amortizes its unrecognized prior service costs over participants’ average remaining service period to
benefit eligibility age and amortizes its transition obligations and 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
9.0 years, 10.8 years and 9.1 years for the years ended December 31, 2016, 2015 and 2014, respectively. The average remaining service period of
postretirement benefit plan participants related to expected retirement was 9.7 years, 9.7 years and 10.1 years for the years ended December 31,
2016, 2015 and 2014, respectively. For the predecessor periods, the average remaining service period of PHI’s other postretirement benefit plans
was approximately 11 years for both 2015 and 2014.
Regulatory Accounting (Exelon, ComEd, PECO, BGE, PHI, Pepco, DPL and ACE)
Exelon and the Utility Registrants account for their regulated electric and gas operations in accordance with the authoritative guidance, which
requires Exelon and the Utility Registrants to reflect the effects of cost-based rate regulation in their financial statements. This guidance is applicable
to 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 are set at levels that will recover
the entities’ costs 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) 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 (2) billings in advance of expenditures for
approved regulatory programs. As of December 31, 2016, Exelon and the Utility Registrants have concluded that the operations of each such
Registrant meet the criteria to apply the authoritative guidance. If it is concluded in a future period that a separable portion of operations no longer
meets the criteria of this guidance, 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. See Note 3—
Regulatory Matters of the Combined Notes to Consolidated Financial Statements for additional information regarding regulatory matters, including
the regulatory assets and liabilities tables of Exelon and the Utility Registrants.
For each regulatory jurisdiction in which they conduct business, Exelon and the Utility Registrants assess whether the regulatory assets and
liabilities continue to meet the criteria for probable future recovery or settlement at each balance sheet date and when regulatory events occur. This
assessment includes consideration of recent rate orders, historical regulatory treatment for similar costs in each Registrant’s jurisdictions, and
factors such as changes in applicable regulatory and political environments. Furthermore, each Registrant makes other judgments related to the
financial statement impact of their regulatory environments, such as the types of adjustments to rate base that will be acceptable to regulatory
bodies, if any, for which costs will be recoverable through rates. Refer to the revenue recognition discussion below for additional information on the
annual revenue reconciliations associated with ComEd’s distribution formula rate, pursuant to EIMA, and FERC-approved
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transmission formula rate tariffs for ComEd, BGE, Pepco, DPL and ACE. Additionally, estimates are made in accordance with the authoritative
guidance for contingencies as to the amount of revenues billed under certain regulatory orders that may ultimately be refunded to customers upon
finalization of applicable regulatory or judicial processes. These assessments are based, to the extent possible, on past relevant experience with
regulatory bodies in each Registrant’s jurisdictions, known circumstances specific to a particular matter and hearings held with the applicable
regulatory body. 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 on their results of operations, financial position, and cash flows could be material.
ACE has a recovery mechanism for purchased power costs associated with BGS. ACE records a deferred energy supply costs regulatory
asset or regulatory liability for under or over-recovered costs that are expected to be recovered from or refunded to ACE customers, respectively. In
the first quarter of 2016, ACE changed its method of accounting for determining under or over-recovered costs in this recovery mechanism to include
unbilled revenues in the determination of under or over-recovered costs. ACE believes this change is preferable as it better reflects the economic
impacts of dollar-for-dollar cost recovery mechanisms. ACE applied the change retrospectively. The impact of the change was a $12 million
reduction to ACE’s opening Retained earnings as of January 1, 2014 with a corresponding reduction to Regulatory assets. The impact of the change
on Net income attributable to common shareholder was an increase of $2 million and $1 million for the years ended December 31, 2015 and
December 31, 2014, respectively.
The 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.
Accounting for Derivative Instruments (All Registrants)
The Registrants utilize derivative instruments to manage their exposure to fluctuations in interest rates, changes in interest rates related to
planned future debt issuances and changes in the fair value of outstanding debt. Generation uses a variety of derivative and non-derivative
instruments to manage the commodity price risk of its electric generation facilities, including power sales, fuel and energy purchases and other
energy-related products marketed and purchased. Additionally, Generation enters into energy-related derivatives for proprietary trading purposes.
ComEd has entered into contracts to procure energy, capacity and ancillary services. In addition, ComEd currently holds floating-to-fixed energy
swaps with several unaffiliated suppliers that extend into 2032. PECO and BGE have entered into derivative natural gas contracts to hedge their
long-term price risk in the natural gas market. PECO has also entered into derivative contracts to procure electric supply through a competitive RFP
process as outlined in its PAPUC-approved DSP Program. BGE has also entered into derivative contracts to procure electric supply through a
competitive auction process as outlined in its MDPSC-approved SOS Program. Pepco has contracts to procure SOS electric supply that are
executed through a competitive procurement process approved by the MDPSC and DCPSC. DPL has contracts to procure SOS electric supply that
are executed through a competitive procurement process approved by the MDPSC and the DPSC. DPL also uses derivatives to reduce natural gas
commodity volatility and to limit its customers’ exposure to natural gas price fluctuations under a hedging program approved by the DPSC. ACE has
contracts to procure BGS electric supply that are executed through a competitive procurement process approved by the NJBPU. ComEd, PECO,
BGE, Pepco, DPL and ACE do not enter into derivatives for proprietary trading purposes. The Registrants’ derivative activities are in accordance
with Exelon’s Risk Management Policy (RMP). See Note 13—Derivative Financial Instruments of the Combined Notes to Consolidated Financial
Statements for additional information regarding the Registrants’ derivative instruments.
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The Registrants account for derivative financial instruments under the applicable authoritative guidance. Determining whether or not a contract
qualifies as a derivative under this guidance 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 amounts. Changes in management’s assessment of contracts
and the liquidity of their markets, and changes in authoritative guidance related to derivatives, could result in previously excluded contracts being
subject to the provisions of the authoritative derivative guidance. Generation has determined that contracts to purchase uranium, contracts to
purchase and sell capacity in certain ISO’s, certain emission products and RECs do not meet the definition of a derivative under the current
authoritative guidance since they do not provide for net settlement and neither the uranium, certain capacity, emission nor the REC markets are
sufficiently liquid to conclude that physical forward contracts are readily convertible to cash. If these markets do become sufficiently liquid in the
future and Generation would be required to account for these contracts as derivative instruments, the fair value of these contracts would be
accounted for consistent with Generation’s other derivative instruments. In this case, if market prices differ from the underlying prices of the
contracts, Generation would be required to record mark-to-market gains or losses, which may have a significant impact to Exelon’s and Generation’s
financial positions and results of operations.
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. Further, derivatives that qualify and are designated for hedge
accounting are classified as fair value or cash flow hedges. For fair value hedges, changes in fair values for both the derivative and the underlying
hedged exposure are recognized in earnings each period. For cash flow hedges, the portion of the derivative gain or loss that is effective in offsetting
the change in the hedged cash flows of the underlying exposure is deferred in accumulated OCI and later reclassified into earnings when the
underlying transaction occurs. Gains and losses from the ineffective portion of any hedge are recognized in earnings immediately. Generally, hedge
accounting is not elected for commodity transactions. Economic hedges for commodities are recorded at fair value through earnings. In addition, for
energy-related derivatives entered into for proprietary trading purposes, changes in the fair value of the derivatives are recognized in earnings each
period. For economic hedges that are not designated for hedge accounting for the Utility Registrants, changes in the fair value each period are
recorded with a corresponding offsetting regulatory asset or liability if there is an ability to recover the associated costs.
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 as normal purchases and normal sales and are thus
not required to be recorded at fair value, but rather on an accrual basis of accounting. Determining whether a contract qualifies for the normal
purchases and normal sales exception requires that management exercise 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 which 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 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
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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 accounting for derivatives, 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. In accordance with 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 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 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 Registrant’s derivatives are traded
predominately at liquid trading points. The remaining derivative contracts are valued using models that take into account 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. 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. The Registrants
consider nonperformance risk, including credit risk in the valuation of derivative contracts categorized in Level 1, 2 and 3, including both historical
and current market data in its assessment of nonperformance risk, including credit risk. The impacts of credit and nonperformance 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, which are typically designated as fair value hedges, as a means 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 in anticipation of future financings 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. The
characterization of the interest rate derivative contracts between the economic hedge and proprietary trading activity is driven by the corresponding
characterization of the underlying commodity position that gives rise to the interest rate exposure. 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
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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 the terms and conditions of the agreements and the forward interest rate and foreign exchange curves. As these inputs are based on
observable data and valuations of similar instruments, the interest rate and foreign exchange derivatives 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.
See ITEM 7A. QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK and Note 12—Fair Value of Financial Assets and
Liabilities and Note 13—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. In accordance with applicable authoritative
guidance, 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. 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. 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.
In the first quarter of 2016, PHI, Pepco, DPL and ACE changed their accounting principle for classification of interest on uncertain tax
positions. PHI, Pepco, DPL and ACE have reclassified interest on uncertain tax positions as interest expense from income tax expense in the
Consolidated Statements of Operations and Comprehensive Income. GAAP does not address the preferability of one acceptable method of
accounting over the other for the classification of interest on uncertain tax positions. However, PHI, Pepco, DPL and ACE believe this change is
preferable for comparability of their financial statements with the financial statements of the other Registrants in the combined filing, for consistency
with FERC classification and for a more appropriate representation of the effective tax rate as they manage the settlement of uncertain tax positions
and interest expense separately. PHI, Pepco, DPL and ACE applied the change retrospectively. The reclassification in the Consolidated Statements
of Operations and Comprehensive Income for the year ended December 31, 2015 is $34 million and $4 million for PHI and Pepco, respectively, and
for the year ended December 31, 2014 is $1 million for both Pepco and ACE. The impact on all other PHI Registrants for years ended December 31,
2015 and December 31, 2014 is less than $1 million.
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 evaluate for negative
evidence that could indicate the Registrant’s inability to realize its deferred tax assets, such as historical operating loss or tax credit carryforward
expiration. Based on the combined assessment, the Registrants record valuation allowances for deferred tax assets when they conclude it is
more-likely-than-not such benefit will not be realized in future periods.
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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. While the Registrants believe the resulting tax balances as of
December 31, 2016 and 2015 are appropriately accounted for in accordance with the applicable authoritative guidance, the ultimate outcome of tax
matters could result in favorable or unfavorable adjustments to their consolidated financial statements and such adjustments could be material. See
Note 15—Income Taxes of the Combined Notes to Consolidated Financial Statements for additional information regarding taxes.
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 amounts recorded may
differ from the actual expense incurred when the uncertainty is resolved. The estimates that the Registrants make in accounting for loss
contingencies and the actual results that they record upon the ultimate resolution of these uncertainties could have a significant effect on their
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. Periodic studies are conducted
at ComEd, PECO, BGE, Pepco, DPL and ACE to determine future remediation requirements and estimates are adjusted accordingly. In addition,
periodic reviews are performed at Generation to assess the adequacy of its environmental reserves. These matters, if resolved in a manner different
from the estimate, could have a significant effect on the Registrants’ results of operations, financial position and cash flows. See Note 24—
Commitments and Contingencies of the Combined Notes to Consolidated Financial Statements for further 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 effect on the Registrants’ results
of operations, financial position and cash flows.
Revenue Recognition (All Registrants)
Sources of Revenue and Determination of Accounting Treatment
The Registrants earn revenues from various business activities including: the sale of energy and energy-related products, such as natural gas,
capacity, and other commodities in non-regulated markets (wholesale and retail) ; the sale and delivery of electricity and natural gas in regulated
markets; and the provision of other energy-related non-regulated products and services.
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The appropriate accounting treatment for revenue recognition is based on the nature of the underlying transaction and applicable accounting
standards. The Registrants primarily use accrual and mark-to-market accounting as discussed in more detail below.
Accrual Accounting
Under accrual accounting, the Registrants record revenues in the period when services are rendered or energy is delivered to customers. The
Registrants generally use accrual accounting to recognize revenues for sales of electricity, natural gas and other commodities as part of their
physical delivery activities. The Registrants enter into these sales transactions using a variety of instruments, including non-derivative agreements,
derivatives that qualify for and are designated as normal purchases and normal sales (NPNS) of commodities that will be physically delivered, sales
to utility customers under regulated service tariffs and spot-market sales, including settlements with independent system operators.
Mark-to-Market Accounting
The Registrants record revenues and expenses using the mark-to-market method of accounting for transactions that meet the definition of a
derivative for which they are not permitted, or have not elected, the NPNS exception. These mark-to-market 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 and realized; and unrealized gains and losses from changes in the fair value of open contracts.
Unbilled Revenues
The determination of Generation’s and the Utility Registrants’ retail energy 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 receivables 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 would
also have an effect on the measurement of unbilled revenue; however, total operating revenues would remain materially unchanged.
See Note 6—Accounts Receivable of the Combined Notes to Consolidated Financial Statements for additional information.
Regulated Distribution & Transmission Revenues
ComEd’s EIMA distribution formula rate provides for annual reconciliations to the distribution revenue requirement. As of the balance sheet
dates, ComEd has recorded its best estimates of the distribution revenue impact resulting from changes in rates that ComEd believes are probable
of approval by the ICC in accordance with the formula rate mechanism.
ComEd’s, BGE’s, Pepco’s, DPL’s and ACE’s FERC transmission formula rate tariffs provide for annual reconciliations to the transmission
revenue requirements. As of the balance sheet dates,
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ComEd, BGE, Pepco, DPL and ACE have recorded the best estimate of their respective transmission revenue impact resulting from changes in
rates that each Registrant believes are probable of approval by FERC in accordance with the formula rate mechanism.
Distribution and transmission formula rates require significant estimates. Estimates are based upon actual costs incurred 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 1—Significant Accounting Policies of the Combined Notes to Consolidated Financial Statements for more information on the
potential impacts of the new revenue accounting standard effective for annual reporting periods beginning on or after December 15, 2017.
Allowance for Uncollectible Accounts (All Registrants)
The allowance for uncollectible accounts reflects the Registrants’ best estimates of losses on the accounts receivable balances. For
Generation, the allowance is based on accounts receivable aging historical experience and other currently available information. ComEd, PECO and
BGE 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. At December 31, 2015, Pepco, DPL and ACE estimated the allowance for
uncollectible accounts based on specific identification of material amounts at risk by customer and maintained a reserve based on their historical
collection experience. At December 31, 2016, Pepco, DPL and ACE aligned the estimation of their allowance for uncollectible accounts to be
consistent with ComEd, PECO and BGE, as described above. 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 historical average charge-offs as a percentage of accounts receivable in each risk segment. The Utility Registrant
customers’ 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. See Note 6—Accounts Receivable of the Combined Notes to Consolidated Financial
Statements for additional information regarding accounts receivable.
Results of Operations by Business Segment
The comparisons of operating results and other statistical information for the years ended December 31, 2016, 2015 and 2014 set forth below
include intercompany transactions, which are eliminated in Exelon’s consolidated financial statements.
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Net Income (Loss) Attributable to Common Shareholders by Registrant
Exelon
Generation
ComEd
PECO
BGE
Pepco
DPL
ACE
PHI
For the Years
Ended
December 31,
2016
$1,134
496
378
438
286
42
(9)
(42)
2015
$2,269
1,372
426
378
275
187
76
40
Favorable
(unfavorable)
2016 vs. 2015
variance
For the Year
Ended
December 31,
2014
Favorable
(unfavorable)
2015 vs. 2014
variance
$
$
(1,135)
(876)
(48)
60
11
(145)
(85)
(82)
$
1,623
835
408
352
198
171
104
46
646
537
18
26
77
16
(28)
(6)
Successor
March 24, 2016 to
December 31, 2016
(61)
$
January 1, 2016 to
March 23, 2016
19
$
Predecessor
For the Year
Ended
December 31,
2015
For the Year
Ended
December 31,
2014
Favorable
(unfavorable)
2015 vs. 2014
variance
$
327
$
242
$
85
Results of Operations—Generation
Operating revenues
Purchased power and fuel expense
Revenues net of purchased power and fuel expense (b)
Other operating expenses
Operating and maintenance
Depreciation and amortization
Taxes other than income
Total other operating expenses
Equity in losses of unconsolidated affiliates
Gain (Loss) on sales of assets
Gain on consolidation and acquisition of businesses
Operating income
Other income and (deductions)
Interest expense
Other, net
Total other income and (deductions)
Income before income taxes
Income taxes
Equity in losses of unconsolidated affiliates
Net income
Net income (loss) attributable to noncontrolling interests
Net income attributable to membership interest
Favorable
(unfavorable)
2016 vs. 2015
variance
$
$
(1,384)
1,191
(193)
(333)
(825)
(17)
(1,175)
—
(71)
—
(1,439)
1
461
462
(977)
212
(17)
(782)
94
(876)
Favorable
(unfavorable)
2015 vs. 2014
variance
$
$
1,742
(96)
1,646
258
(87)
(24)
147
20
(425)
(289)
1,099
(9)
(466)
(475)
624
(295)
(8)
321
(216)
537
2014 (a)
$17,393
9,925
7,468
5,566
967
465
6,998
(20)
437
289
1,176
(356)
406
50
1,226
207
—
1,019
184
835
$
2015
$19,135
10,021
9,114
5,308
1,054
489
6,851
—
12
—
2,275
(365)
(60)
(425)
1,850
502
(8)
1,340
(32)
$ 1,372
2016
$17,751
8,830
8,921
5,641
1,879
506
8,026
—
(59)
—
836
(364)
401
37
873
290
(25)
558
62
496
123
$
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(a) On April 1, 2014, Generation assumed operational control of CENG’s nuclear fleet. As a result, beginning on April 1, 2014, the financial results include CENG’s results of
operations on a fully consolidated basis.
(b) Generation evaluates its operating performance using the measure of revenues net of purchased power and fuel expense. Generation believes that revenues net of
purchased power and fuel expense is a useful measurement because it provides information that can be used to evaluate its operational performance. Revenues net of
purchased power and fuel expense 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.
Net Income Attributable to Membership Interest
Year Ended December 31, 2016 Compared to Year Ended December 31, 2015. Generation’s net income attributable to membership interest
decreased compared to the same period in 2015, primarily due to lower revenues net of purchased power and fuel expense, higher operating and
maintenance expense, higher depreciation and amortization expense, and losses on sales of assets in 2016, partially offset by increased other
income and decreased income tax expense. The decrease in revenues net of purchased power and fuel expense primarily relates to lower
mark-to-market results in 2016 compared to 2015 and lower realized energy prices, partially offset by the Ginna Reliability Support Services
Agreement and a decrease in outage days at higher capacity units despite an increase in overall outage days. The increase in operating and
maintenance expense is primarily related to the impairment of Upstream assets and certain wind projects, and increased costs related to the
implementation of the cost management program. The increase in depreciation and amortization expense is primarily related to accelerated
depreciation and amortization expense related to the previous decision to early retire the Clinton and Quad Cities nuclear generating facilities,
increased nuclear decommissioning amortization and increased depreciation expense due to ongoing capital expenditures. The increase in losses
on sales of assets is primarily due to Generation’s strategic decision to narrow the scope and scale of its growth and development activities. The
increase in other income is primarily due to the change in realized and unrealized gains and losses on NDT funds.
Year Ended December 31, 2015 Compared to Year Ended December 31, 2014. Generation’s net income attributable to membership interest
increased compared to the same period in 2014 primarily due to higher revenue net of purchase power and fuel expense and lower operating and
maintenance expense; partially offset by the absence of the 2014 gains recorded on the sales of Generation’s ownership interest in generating
stations, the absence of the 2014 gain recorded upon the consolidation of CENG, decreased other income and increased income tax expense. The
increase in revenue, net of purchase power and fuel expense was primarily due to the inclusion of CENG’s results on fully consolidated basis in
2015, the benefit of lower cost to serve load (including the absence of higher procurement costs for replacement power in 2014), the cancellation of
the DOE SNF disposal fee, increased capacity prices, the inclusion of Integrys’ results in 2015, favorability from portfolio management optimization
activities, increased load served, and mark-to-market gains in 2015 compared to mark-to-market losses in 2014, partially offset by lower margins
resulting from the 2014 sale of generating assets, lower realized energy prices, and the absence of the 2014 fuel optimization opportunities in the
South region due to extreme cold weather. The decrease in operating and maintenance expense was largely due to the reduction of long-lived asset
impairment charges in 2015 versus 2014, partially offset by increased labor, contracting and materials expense due to the inclusion of CENG’s
results on a fully consolidated basis in 2015 and increased energy efficiency projects. The decrease in other income is primarily the result of the
change in realized and unrealized gains and losses on NDT fund investments in 2015 as compared to 2014.
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
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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. 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, which includes portions of Illinois, Pennsylvania, Indiana, Ohio, Michigan,
Kentucky and Tennessee, and the United States footprint of MISO excluding MISO’s Southern Region, which covers all or most of North
Dakota, South Dakota, Nebraska, Minnesota, Iowa, Wisconsin, the remaining parts of Illinois, Indiana, Michigan and Ohio not covered by
PJM, and parts of Montana, Missouri and Kentucky.
New England represents the operations within ISO-NE covering the states of Connecticut, Maine, Massachusetts, New Hampshire, Rhode
Island and Vermont.
New York represents operations within ISO-NY, which covers the state of New York in its entirety.
ERCOT represents operations within Electric Reliability Council of Texas, covering most of the state of Texas.
Other Power Regions :
•
•
•
South represents operations in the FRCC, MISO’s Southern Region, and the remaining portions of the SERC not included within
MISO or PJM, which includes all or most of Florida, Arkansas, Louisiana, Mississippi, Alabama, Georgia, Tennessee, North
Carolina, South Carolina and parts of Missouri, Kentucky and Texas. Generation’s South region also includes operations in the SPP,
covering Kansas, Oklahoma, most of Nebraska and parts of New Mexico, Texas, Louisiana, Missouri, Mississippi and Arkansas.
West represents operations in the WECC, which includes California ISO, and covers the states of California, Oregon, Washington,
Arizona, Nevada, Utah, Idaho, Colorado, and parts of New Mexico, Wyoming and South Dakota.
Canada represents operations across the entire country of Canada and includes the AESO, OIESO and the Canadian portion of
MISO.
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 Generation’s 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 the initial early retirement decision for Clinton and Quad Cities; and
other miscellaneous revenues.
Generation evaluates the operating performance of its power marketing activities using the measure of revenues net of purchased power and
fuel expense, which is a non-GAAP measurement. 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 owned generation and fuel costs associated with tolling agreements.
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For the years ended December 31, 2016 compared to 2015 and December 31, 2015 compared to 2014, Generation’s revenues net of
purchased power and fuel expense by region were as follows:
2016 vs. 2015
2015 vs. 2014
2016
2015 Variance % Change
Mid-Atlantic (a)(b)(e)
Midwest (c)
New England
New York (a)(e)
ERCOT
Other Power Regions
Total electric revenues net of purchased power and fuel expense
Proprietary Trading
Mark-to-market gains (losses)
Other (d)
Total revenue net of purchased power and fuel expense
$ 3,317 $ 3,571 $
2,971
438
742
281
336
8,085
15
(41)
862
2,892
461
634
293
250
8,101
1
257
755
$ 8,921 $ 9,114 $
(254)
79
(23)
108
(12)
86
(16)
14
(298)
107
(193)
2014 Variance % Change
140
(7.1)% $ 3,431 $
293
2,599
2.7%
110
351
(5.0)%
151
483
17.0%
(24)
317
(4.1)%
(77)
327
34.4%
593
7,508
(0.2)%
(41)
42
n.m.
848
(591)
(116.0)%
14.2%
246
509
(2.1)% $ 7,468 $ 1,646
4.1%
11.3%
31.3%
31.3%
(7.6)%
(23.5)%
7.9%
(97.6)%
n.m.
48.3%
22.0%
(a) On April 1, 2014, Generation assumed operational control of CENG’s nuclear fleet. As a result, beginning April 1, 2014, the financial results include CENG’s results on a
fully consolidated basis.
(b) Results of transactions with PECO and BGE are included in the Mid-Atlantic region. Results of transactions with Pepco, DPL, and ACE are included in the Mid-Atlantic
region for the successor period of March 24, 2016 to December 31, 2016.
(c) Results of transactions with ComEd are included in the Midwest region.
(d) Other represents activities not allocated to a region. See text above for a description of included activities. Includes a $57 million decrease to RNF, an $8 million increase
to RNF, and a $124 million decrease to RNF for the amortization of intangible assets related to commodity contracts recorded at fair value for the years ended
December 31, 2016, 2015, and 2014, respectively, and accelerated nuclear fuel amortization associated with the initial early retirement of Clinton and Quad Cities as
discussed in Note 9—Early Nuclear Plant Retirements of the Combined Notes to the Financial Statements of $60 million for the year ended December 31, 2016.
Includes $113 million and $169 million of purchased power from CENG prior to its consolidation on April 1, 2014 in the Mid-Atlantic and New York regions, respectively, for
the year ended December 31, 2014. See Note 27—Related Party Transactions of the Combined Notes to Consolidated Financial Statements for additional information.
(e)
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Generation’s supply sources by region are summarized below:
Supply Source (GWh)
Nuclear Generation (a)
Mid-Atlantic
Midwest
New York
Total Nuclear Generation
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 (b)
Mid-Atlantic (c)
Midwest (c)
New England
New York
ERCOT
Other Power Regions
Total Supply/Sales by Region
2016
2015
Variance % Change
2014
Variance % Change
2016 vs. 2015
2015 vs. 2014
63,447
94,668
18,684
176,799
63,283
93,422
18,769
175,474
164
1,246
(85)
1,325
0.3%
1.3%
(0.5)%
0.8%
58,809
94,000
13,645
166,454
4,474
(578)
5,124
9,020
2,731
1,488
6,968
3
6,785
8,179
26,154
2,774
1,547
2,983
3
5,763
7,848
20,918
(43)
(59)
3,985
—
1,022
331
5,236
(1.6)%
(3.8)%
133.6%
— %
17.7%
4.2%
25.0%
11,025
1,372
5,233
4
7,164
7,955
32,753
(8,251)
175
(2,250)
(1)
(1,401)
(107)
(11,835)
16,874
2,255
16,632
—
10,637
13,589
59,987
8,160
2,325
24,309
—
10,070
18,773
63,637
8,714
(70)
(7,677)
—
567
(5,184)
(3,650)
106.8%
(3.0)%
(31.6)%
— %
5.6%
(27.6)%
(5.7)%
6,082
2,004
12,354
2,857
8,651
14,795
46,743
2,078
321
11,955
(2,857)
1,419
3,978
16,894
83,052
98,411
23,600
18,687
17,422
21,768
262,940
74,217
97,294
27,292
18,772
15,833
26,621
260,029
8,835
1,117
(3,692)
(85)
1,589
(4,853)
2,911
11.9%
1.1%
(13.5)%
(0.5)%
10.0%
(18.2)%
1.1%
75,916
97,376
17,587
16,506
15,815
22,750
245,950
(1,699)
(82)
9,705
2,266
18
3,871
14,079
7.6%
(0.6)%
37.6%
5.4%
(74.8)%
12.8%
(43.0)%
(25.0)%
(19.6)%
(1.3)%
(36.1)%
34.2%
16.0%
96.8%
(100.0)%
16.4%
26.9%
36.1%
(2.2)%
(0.1)%
55.2%
13.7%
0.1%
17.0%
5.7%
(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).
(b) Excludes physical proprietary trading volumes of 6,179 GWh, 7,310 GWh, and 10,571 GWh for the years ended December 31, 2016, 2015, and 2014, respectively.
(c)
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 for the successor period of March 24, 2016 to December 31, 2016.
Mid-Atlantic. Year Ended December 31, 2016 Compared to Year Ended December 31, 2015 . The $254 million decrease in revenues net of
purchased power and fuel expense in the Mid-Atlantic was primarily due to lower realized energy prices, decreased capacity prices and higher oil
inventory write-downs in 2016, partially offset by increased load volumes served.
Year Ended December 31, 2015 Compared to Year Ended December 31, 2014 . The $140 million increase in revenues net of purchased
power and fuel expense in the Mid-Atlantic was primarily due to the inclusion of CENG’s results on a fully consolidated basis for the full year in 2015,
the benefit of lower cost to serve load (which includes the absence of higher procurement costs for replacement power due to extreme cold weather
in the first quarter of 2014), increased load volumes served, higher
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nuclear volumes, the cancellation of the DOE SNF disposal fee, and favorability from portfolio management optimization activities, partially offset by
lower capacity revenues, and lower generation volumes due to the sale of generating assets.
Midwest. Year Ended December 31, 2016 Compared to Year Ended December 31, 2015 . The $79 million increase in revenues net of
purchased power and fuel expense in the Midwest was primarily due to decreased nuclear outage days and decreased nuclear fuel prices.
Year Ended December 31, 2015 Compared to Year Ended December 31, 2014 . The $293 million increase in revenues net of purchased
power and fuel expense in the Midwest was primarily due to higher capacity revenues, increased load volumes served, the inclusion of Integrys’
results in 2015, the cancellation of the DOE SNF disposal fee in 2014, and favorability from portfolio management optimization activities, partially
offset by lower nuclear volumes.
New England. Year Ended December 31, 2016 Compared to Year Ended December 31, 2015 . The $23 million decrease in revenues net of
purchased power and fuel expense in New England was primarily due to lower realized energy prices and higher oil inventory write-downs in 2016,
partially offset by increased capacity prices.
Year Ended December 31, 2015 Compared to Year Ended December 31, 2014 . The $110 million increase in revenues net of purchased
power and fuel expense in New England was primarily due to the benefit of lower cost to serve load, increased load volumes served, the inclusion of
Integrys’ results in 2015, and favorability from portfolio management optimization activities, partially offset by lower generation volumes due to the
sale of a generating asset.
New York. Year Ended December 31, 2016 Compared to Year Ended December 31, 2015. The $108 million increase in revenues net of
purchased power and fuel expense in New York was primarily due to the impact of the Ginna Reliability Support Service Agreement, partially offset
by lower realized energy prices.
Year Ended December 31, 2015 Compared to Year Ended December 31, 2014 . The $151 million increase in revenues net of purchased
power and fuel expense in New York was primarily due to the inclusion of CENG’s results on a fully consolidated basis for the full year in 2015,
increased nuclear volumes and the inclusion of Integrys’ results in 2015, partially offset by lower realized energy prices and decreased capacity
revenues.
ERCOT. Year Ended December 31, 2016 Compared to Year Ended December 31, 2015. The $12 million decrease in revenues net of
purchased power and fuel expense in ERCOT was primarily due to lower realized energy prices, partially offset by increased output from renewable
assets.
Year Ended December 31, 2015 Compared to Year Ended December 31, 2014. The $24 million decrease in revenues net of purchased
power and fuel expense in ERCOT was primarily due to lower realized energy prices and a decrease in generation volumes due to the sale of a
generating asset, partially offset by the absence of higher procurement costs for replacement power in 2014 and decreased fuel costs.
Other Power Regions. Year Ended December 31, 2016 Compared to Year Ended December 31, 2015. The $86 million increase in revenues
net of purchased power and fuel expense in Other Power Regions was primarily due to higher realized energy prices.
Year Ended December 31, 2015 Compared to Year Ended December 31, 2014. The $77 million decrease in revenues net of purchased
power and fuel expense in Other Power Regions was primarily
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due to the amortization of contracts recorded at fair value associated with prior acquisitions, lower realized energy prices, the absence of the 2014
fuel optimization opportunities, partially offset by increased generation from power purchase agreements, and decreased fuel costs.
Proprietary Trading. Year Ended December 31, 2016 Compared to Year Ended December 31, 2015. The $14 million increase in revenues
net of purchased power and fuel expense in Proprietary trading was primarily due to congestion activity.
Year Ended December 31, 2015 Compared to Year Ended December 31, 2014. The $41 million decrease in revenues net of purchased
power and fuel expense in Proprietary trading was primarily due to the absence of gains on congestion trading products.
Mark-to-market. Generation is exposed to market risks associated with changes in commodity prices and enters into economic hedges to
mitigate exposure to these fluctuations. See Note 12—Fair Value of Financial Assets and Liabilities and Note 13—Derivative Financial Instruments
of the Combined Notes to the Consolidated Financial Statements for information on gains and losses associated with mark-to-market derivatives.
Year Ended December 31, 2016 Compared to Year Ended December 31, 2015 . Mark-to-market losses on economic hedging activities were
$41 million in 2016 compared to gains of $257 million in 2015.
Year Ended December 31, 2015 Compared to Year Ended December 31, 2014 . Mark-to-market gains on economic hedging activities were
$257 million in 2015 compared to losses of $591 million in 2014.
Other. Year Ended December 31, 2016 Compared to Year Ended December 31, 2015. The $107 million increase in other revenue net of
purchased power and fuel was primarily due to revenue related to the inclusion of Pepco Energy Services results in 2016 and revenue related to
energy efficiency projects, partially offset by the amortization of energy contracts recorded at fair value associated with prior acquisitions, and
accelerated nuclear fuel amortization associated with the initial early retirement decision for Clinton and Quad Cities as discussed in Note 9—Early
Nuclear Plant Retirements of the Combined Notes to the Financial Statements.
Year Ended December 31, 2015 Compared to Year Ended December 31, 2014. The $246 million increase in other revenue net of purchased
power and fuel was primarily due to the amortization of energy contracts recorded at fair value associated with prior acquisitions, the inclusion of
Integrys’ gas results in 2015, and an increase in distributed generation and energy efficiency activity. See Note 11—Intangible Assets of the
Combined Notes to Consolidated Financial Statements for information regarding energy contract intangibles.
Nuclear Fleet Capacity Factor
The following table presents nuclear fleet operating data for 2016, as compared to 2015 and 2014, for the Generation-operated plants. 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 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 (a)
2016
94.6% 93.7%
2015
2014
94.3%
(a) Excludes Salem, which is operated by PSEG Nuclear, LLC. Reflects ownership percentage of stations operated by Exelon. As of April 1, 2014, CENG is included at
ownership.
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Year Ended December 31, 2016 Compared to Year Ended December 31, 2015 . The nuclear fleet capacity factor, which excludes Salem,
increased in 2016 compared to 2015 primarily due to fewer refueling and non-refueling outage days. For 2016 and 2015, planned refueling outage
days totaled 245 and 290, respectively, and non-refueling outage days totaled 63 and 82, respectively.
Year Ended December 31, 2015 Compared to Year Ended December 31, 2014 . The nuclear fleet capacity factor, which excludes Salem,
decreased in 2015 compared to 2014 primarily due to a higher number of refueling outage days and non-outage energy losses, partially offset by a
lower number of unplanned outage days. For 2015 and 2014, planned refueling outage days totaled 290 and 275, respectively, and non-refueling
outage days totaled 82 and 92, respectively.
Operating and Maintenance Expense
The changes in operating and maintenance expense for 2016 compared to 2015, consisted of the following:
Impairment and related charges of certain generating assets (a)
Merger and integration costs
Midwest Generation bankruptcy charges
ARO update (b)
Pension and non-pension postretirement benefits expense (c)
Corporate allocations (d)
Plant retirements and divestitures (e)
Accretion expense
Nuclear refueling outage costs, including the co-owned Salem plant (f)
Merger commitments
Labor, other benefits, contracting and materials (g)
Cost management program (h)
Curtailment of Generation growth and development activities (i)
Other
Increase in operating and maintenance expense
Increase
(Decrease)
161
$
27
10
(79)
(42)
(12)
(50)
(21)
(61)
53
185
43
24
95
333
$
(a) Reflects increased impairments in 2016 compared to 2015, primarily related to the impairments of certain Upstream assets and wind generating assets in 2016.
(b) Reflects a non-cash benefit pursuant to the annual update of the Generation nuclear decommissioning obligation related to the non-regulatory units.
(c) Reflects the favorable impact of higher pension and OPEB discount rates.
(d) Reflects a decreased share of corporate allocated costs.
(e) Reflects the impact of the Generation’s previous decision to early retire the Clinton and Quad cities nuclear facilities.
(f) Reflects the favorable impacts of decreased nuclear outages in 2016.
(g) Reflects an increase of labor, other benefits, contracting and materials costs primarily due to increased contracting costs related to energy efficiency projects and the
inclusion of Pepco Energy Services results in 2016. Also includes cost of sales of our other business activities that are not allocated to a region.
(h) Represents the 2016 severance expense and reorganization costs related to a cost management program.
(i) Reflects the one-time recognition for 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.
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The changes in operating and maintenance expense for 2015 compared to 2014, consisted of the following:
Impairment and related charges of certain generating assets (b)
Maryland merger commitments
Merger and integration costs
Midwest Generation bankruptcy charges
Decrease in asbestos bodily injury reserve
ARO update
Regulatory fees and assessments
Pension and non-pension postretirement benefits expense
Corporate allocations (c)
Accretion expense
Nuclear refueling outage costs, including the co-owned Salem plant (d)
Labor, other benefits, contracting and materials (e)
Other
Decrease in operating and maintenance expense
Increase
(Decrease) (a)
(651)
$
(44)
(28)
(14)
(12)
8
10
15
16
18
64
323
37
(258)
$
(a) On April 1, 2014, Generation assumed operational control of CENG’s nuclear fleet. As a result, the 2014 operating results include CENG’s results of operations on a fully
consolidated basis from April 1, 2014 through December 31, 2014.
(b) Primarily relates to impairments of certain generating assets held-for-sale, Upstream assets, and wind generating assets during 2014 that did not reoccur in 2015.
(c) Reflects an increased share of corporate allocated costs primarily due to the inclusion of CENG beginning April 1, 2014.
(d) Reflects the unfavorable impacts of increased nuclear outages in 2015.
(e) Reflects an increase of labor, other benefits, contracting and materials costs primarily due to the inclusion of CENG on a fully consolidated basis in 2015. Also includes
cost of sales of our other business activities that are not allocated to a region.
Depreciation and Amortization
Year Ended December 31, 2016 Compared to Year Ended December 31, 2015 . Depreciation and amortization expense increased 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, and increased depreciation expense due to ongoing capital expenditures.
Excluding the impacts of future capital additions, Generation expects total annual depreciation for Clinton and Quad Cities in 2017 and future
years will be consistent with the annual depreciation recognized prior to the June 2016 early retirement decision, with the impact on prospective
depreciation of the reduction in the plants’ book values as a result of the accelerated depreciation recorded from June 2, 2016 to December 6, 2016,
being essentially offset by the impact of shortening Clinton’s expected economic useful life from the original 2046 date to the now expected 2027
date.
Year Ended December 31, 2015 Compared to Year Ended December 31, 2014 . The increase in depreciation and amortization expense was
primarily due to the inclusion of CENG’s results on a fully consolidated basis in 2015, increased nuclear decommissioning amortization, and an
increase in ongoing capital expenditures.
Taxes Other Than Income
Year Ended December 31, 2016 Compared to Year Ended December 31, 2015 . The increase in taxes other than income was primarily due
to an increase in gross receipts tax.
Year Ended December 31, 2015 Compared to Year Ended December 31, 2014 . The increase in taxes other than income was primarily due
to the inclusion of CENG’s results on a fully consolidated basis in 2015.
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Equity in Losses of Unconsolidated Affiliates
Year Ended December 31, 2016 Compared to Year Ended December 31, 2015 . The year-over-year change in Equity in losses of
unconsolidated affiliates is primarily the result of increased losses on equity investments.
Year Ended December 31, 2015 Compared to Year Ended December 31, 2014 . The year-over-year change in Equity in losses of
unconsolidated affiliates is primarily the result of the consolidation of CENG’s results of operations beginning April 1, 2014, which were previously
accounted for under the equity method of accounting.
Gain (Loss) on Sales of Assets
Year Ended December 31, 2016 Compared to Year Ended December 31, 2015 . The decrease in gain (loss) on sales of assets is primarily
related to the one-time recognition for a loss on sale of assets pursuant to Generation’s strategic decision in the fourth quarter of 2016 to narrow the
scope and scale of its growth and development activities, partially offset by a gain associated with Generation’s sale of the retired New Boston
generating site in 2016.
Year Ended December 31, 2015 Compared to Year Ended December 31, 2014 . The decrease in gain (loss) on sales of assets is primarily
related to the absence of $411 million of gains recorded on the sale of Generation’s ownership interests in Safe Harbor Water Power Corporation,
Fore River and West Valley generating stations in 2014. Refer to Note 4—Mergers, Acquisitions, and Dispositions in the Combined Notes to
Consolidated Financial Statements for additional information.
Gain on Consolidation and Acquisition of Businesses
Year Ended December 31, 2015 Compared to Year Ended December 31, 2014 . The decrease in gain on consolidation and acquisition of
businesses reflects the absence of a $261 million gain upon consolidation of CENG resulting from the difference in fair value of CENG’s net assets
as of April 1, 2014 and the equity method investment previously recorded on Generation’s and Exelon’s books and the settlement of pre-existing
transactions between Generation and CENG recorded in 2014, and the absence of a $28 million bargain-purchase gain related to the Integrys
acquisition recorded in 2014.
Interest Expense
The changes in interest expense for 2016 compared to 2015 and 2015 compared to 2014 consisted of the following:
Interest expense on long-term debt
Interest expense on interest rate swaps
Interest expense on tax settlements
Other interest expense
(Decrease) increase in interest expense, net
Other, Net
Increase
(Decrease)
2016 vs. 2015
8
$
1
16
(26)
(1)
$
Increase
(Decrease)
2015 vs. 2014
53
$
22
(37)
(29)
9
$
Year Ended December 31, 2016 Compared to Year Ended December 31, 2015 . The increase in Other, net primarily reflects the net increase
in realized and unrealized gains related to the NDT fund investments of Generation’s Non-Regulatory Agreement Units as described in the table
below. Other, net also reflects $80 million and $(22) million for the years ended December 31, 2016 and 2015,
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respectively, related to the contractual elimination of income tax expense associated with the NDT fund investments of the Regulatory Agreement
Units. Refer to Note 16—Asset Retirement Obligations of the Combined Notes to Consolidated Financial Statements for additional information
regarding NDT fund investments.
Year Ended December 31, 2015 Compared to Year Ended December 31, 2014 . The decrease in Other, net primarily reflects the net
decrease in realized and unrealized gains related to the NDT fund investments of Generation’s Non-Regulatory Agreement Units as described in the
table below. Other, net also reflects $(22) million and $67 million for the years ended December 31, 2015 and 2014, respectively, related to the
contractual elimination of income tax expense associated with the NDT fund investments of the Regulatory Agreement Units. Refer to Note 16—
Asset Retirement Obligations of the Combined Notes to Consolidated Financial Statements for additional information regarding NDT fund
investments.
The following table provides unrealized and realized gains (losses) on the NDT fund investments of the Non-Regulatory Agreement Units
recognized in Other, net for 2016, 2015 and 2014:
Net unrealized gains (losses) on decommissioning trust funds
Net realized gains on sale of decommissioning trust funds
Effective Income Tax Rate.
2016
$194
35
2015
$(197)
66
2014
$134
77
Generation’s effective income tax rates for the years ended December 31, 2016, 2015 and 2014 were 33.2%, 27.1% and 16.9%, respectively.
See Note 15—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—ComEd
Operating revenues
Purchased power expense
Revenues net of purchased power expense (a)(b)
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
Favorable
(unfavorable)
2016 vs. 2015
variance
$
$
349
(139)
210
37
(68)
3
(28)
6
188
(129)
(86)
(215)
(27)
(21)
(48)
Favorable
(unfavorable)
2015 vs. 2014
variance
$
$
341
(142)
199
(138)
(20)
(3)
(161)
(1)
37
(11)
4
(7)
30
(12)
18
2014
$4,564
1,177
3,387
1,429
687
293
2,409
2
980
(321)
17
(304)
676
268
$ 408
2015
$4,905
1,319
3,586
1,567
707
296
2,570
1
1,017
(332)
21
(311)
706
280
$ 426
2016
$5,254
1,458
3,796
1,530
775
293
2,598
7
1,205
(461)
(65)
(526)
679
301
$ 378
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(a) ComEd evaluates its operating performance using the measure of Revenue net of purchased power expense. ComEd believes that Revenue net of purchased power
expense is a useful measurement because it provides information that can be used to evaluate its operational performance. In general, ComEd only earns margin based
on the delivery and transmission of electricity. ComEd has included its discussion of Revenue net of purchased power expense below as a complement to the financial
information provided in accordance with GAAP. However, Revenue net of purchased power expense 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.
(b) For regulatory recovery mechanisms, including ComEd’s electric distribution and transmission formula rates, and riders, revenues increase and decrease i) as fully
recoverable costs fluctuate (with no impact on net earnings), and ii) pursuant to changes in rate base, capital structure and ROE (which impact net earnings).
Net Income
Year Ended December 31, 2016 Compared to Year Ended December 31, 2015. ComEd’s Net income for the year ended December 31, 2016
was lower than the same period in 2015 primarily due to the recognition of the penalty and the after-tax interest related to the Tax Court’s decision
on Exelon’s like-kind exchange tax position, partially offset by increased electric distribution and transmission formula rate earnings (reflecting the
impacts of increased capital investment, partially offset by lower allowed electric distribution ROE) and favorable weather.
Year Ended December 31, 2015 Compared to Year Ended December 31, 2014. ComEd’s Net income for the year ended December 31, 2015
was higher than the same period in 2014 primarily due to increased electric distribution and transmission formula rate earnings (reflecting the
impacts of increased capital investment, partially offset by lower allowed electric distribution ROE), partially offset by unfavorable weather and
volume.
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
procurement costs and participation in customer choice programs. ComEd is permitted to recover electricity procurement costs from retail customers
without mark-up. Therefore, fluctuations in electricity procurement costs have no impact on Revenue net of purchased power expense. See Note 3—
Regulatory Matters of the Combined Notes to Consolidated Financial Statements for additional information on ComEd’s electricity procurement
process.
All ComEd customers have the choice to purchase electricity from a competitive electric generation supplier. Customer choice programs do not
impact ComEd’s volume of deliveries, but do affect ComEd’s Operating revenues related to supplied energy, which is fully offset in Purchased power
expense. Therefore, customer choice programs have no impact on Revenue net of purchased power expense.
Retail deliveries purchased from competitive electric generation suppliers (as a percentage of kWh sales) for the years ended December 31,
2016, 2015 and 2014, consisted of the following:
Electric
2016
For the Years Ended December 31,
2015
72%
76%
2014
80%
Retail customers purchasing electric generation from competitive electric generation suppliers at December 31, 2016, 2015 and 2014
consisted of the following:
December 31, 2016
December 31, 2015
December 31, 2014
Number of
customers
1,502,900
% of total
retail
customers
38%
134
Number of
customers
1,655,400
% of total
retail
customers
42%
Number of
customers
2,426,900
% of total
retail
customers
63%
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Under an Illinois law allowing municipalities to arrange the purchase of electricity for their participating residents, the City of Chicago previously
participated in ComEd’s customer choice program and arranged the purchase of electricity from Constellation (formerly Integrys), for those
participating residents. In September 2015, the City of Chicago discontinued its participation in the customer choice program and many of those
participating residents resumed their purchase of electricity from ComEd. ComEd’s Operating revenues has increased as a result of the City of
Chicago switching, but that increase is fully offset in Purchased power expense.
The changes in ComEd’s Revenue net of purchased power expense for the year ended December 31, 2016 compared to the same period in
2015, and for the year ended December 31, 2015 compared to the same period in 2014, consisted of the following:
Weather
Volume
Electric distribution revenue
Transmission revenue
Regulatory required programs
Uncollectible accounts recovery, net
Pricing and customer mix
Revenue subject to refund
Other
Increase in revenue net of purchased power
Increase
(Decrease)
2016 vs. 2015
54
$
(2)
69
97
(31)
(13)
14
—
22
210
$
Increase
(Decrease)
2015 vs. 2014
(16)
$
(22)
180
48
(1)
27
(4)
9
(22)
199
$
Weather. The demand for electricity is affected by weather conditions. Very warm weather in summer months and very cold weather in other
months are referred to as “favorable weather conditions” because these weather conditions result in increased customer usage. Conversely, mild
weather reduces demand. For the year ended December 31, 2016, favorable weather conditions increased Operating revenues net of purchased
power expense when compared to the prior years. For the year ended December 31, 2015, unfavorable weather conditions reduced Operating
revenues net of purchased power expense when compared to the prior years.
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 ComEd’s service territory with
cooling degree days generally having a more significant impact to ComEd, particularly during the summer months. The changes in heating and
cooling degree days in ComEd’s service territory for the years ended December 31, 2016, 2015 and 2014 consisted of the following:
Heating and Cooling Degree-Days
Heating Degree-Days
Cooling Degree-Days
Heating and Cooling Degree-Days
Heating Degree-Days
Cooling Degree-Days
For the Years Ended
December 31,
2016
5,715
1,157
2015
6,091
806
For the Years Ended
December 31,
2015
6,091
806
2014
7,027
799
135
Normal
6,341
842
Normal
6,341
842
% Change
2016 vs. 2015
2016 vs. Normal
(6.2)%
43.5%
(9.9)%
37.4%
% Change
2015 vs. 2014
2015 vs. Normal
(13.3)%
0.9%
(3.9)%
(4.3)%
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Volume. Revenue net of purchased power expense remained relatively consistent as a result of delivery volume, exclusive of the effects of
weather, for the year ended December 31, 2016, reflecting a consistent average usage per residential customer as compared to the same period in
2015. For the year ended December 31, 2015, Revenue net of purchased power expense decreased as a result of lower delivery volume, exclusive
of the effects of weather, reflecting decreased average usage per residential customer and the impacts of energy efficiency programs, as compared
to the same period in 2014.
Electric Distribution Revenue. EIMA 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 EIMA, electric
distribution revenue varies from year to year based upon fluctuations in the underlying costs, investments being recovered and allowed ROE.
ComEd’s allowed ROE is the annual average rate on 30-year treasury notes plus 580 basis points, subject to a collar of plus or minus 50 basis
points. Therefore, the collar limits favorable and unfavorable impacts of weather and load on revenue. In addition, ComEd’s allowed ROE is subject
to reduction if ComEd does not deliver the reliability and customer service benefits to which it has committed over the ten-year life of the investment
program. During the year ended December 31, 2016, electric distribution revenue increased $69 million, primarily due to increased capital
investment and depreciation expense, partially offset by lower allowed ROE due to a decrease in treasury rates. During the year ended
December 31, 2015, electric distribution revenue increased $180 million, primarily due to higher Operating and maintenance expense and increased
capital investment, partially offset by lower allowed ROE due to decreased treasury rates. See Operating and Maintenance Expense below and
Note 3—Regulatory Matters of the Combined Notes to Consolidated Financial Statements for additional information.
Transmission Revenue. Under a FERC-approved formula, transmission revenue varies from year to year based upon fluctuations in the
underlying costs, 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. For the years ended
December 31, 2016 and 2015, ComEd recorded increased transmission revenue due to increased capital investment, higher depreciation expense
and increased highest daily peak load. See Operating and Maintenance Expense below and Note 3—Regulatory Matters of the Combined Notes to
Consolidated Financial Statements for additional information.
Regulatory Required Programs. This represents the change in Operating revenues collected under approved riders to recover costs incurred
for regulatory programs such as ComEd’s energy efficiency and demand response and purchased power administrative costs. The riders are
designed to provide full and current cost recovery. An equal and offsetting amount has been included in Operating and maintenance expense. See
Operating and maintenance expense discussion below for additional information on included programs.
Uncollectible Accounts Recovery, Net. Uncollectible accounts recovery, net, represents recoveries under ComEd’s uncollectible accounts tariff.
See Operating and maintenance expense discussion below for additional information on this tariff.
Pricing and Customer Mix. For the year ended December 31, 2016, the increase in Revenue net of purchased power as a result of pricing and
customer mix is primarily attributable to higher overall effective rates due to decreased usage across all major customer classes and change in
customer mix. For the year ended December 31, 2015, the decrease in Revenue net of purchased power as a result of pricing and customer mix is
primarily attributable to lower overall effective rates due to increased usage across all major customer classes and change in customer mix.
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Revenue Subject to Refund. ComEd records revenue subject to refund based upon its best estimate of customer collections that may be
required to be refunded. Revenue net of purchase power expense was higher for the year ended December 31, 2015, due to the one-time revenue
refund recorded in 2014 associated with the 2007 Rate Case.
Other. Other revenue, which can vary period to period, includes rental revenue, revenue related to late payment charges, assistance provided
to other utilities through mutual assistance programs, recoveries of environmental costs associated with MGP sites, and recoveries of energy
procurement costs.
Operating and Maintenance Expense
Operating and maintenance expense—baseline
Operating and maintenance expense—regulatory
required programs (a)
Total operating and maintenance expense
Year Ended
December 31,
Increase
(Decrease)
Year Ended
December 31,
2016
$ 1,347
2015
$ 1,353
2016 vs. 2015
(6)
$
2015
$ 1,353
2014
$ 1,214
Increase
(Decrease)
2015 vs. 2014
139
$
183
$ 1,530
214
$ 1,567
$
(31)
(37)
214
$ 1,567
215
$ 1,429
$
(1)
138
(a) Operating and maintenance expense for regulatory required programs are costs for various legislative and/or regulatory programs that are recoverable from customers on
a full and current basis through approved regulated rates. An equal and offsetting amount has been reflected in Operating revenues.
The changes in Operating and maintenance expense for year ended December 31, 2016, compared to the same period in 2015, and for the
year ended December 31, 2015, compared to the same period in 2014, consisted of the following:
Baseline
Labor, other benefits, contracting and materials (a)
Pension and non-pension postretirement benefits expense (b)
Storm-related costs
Uncollectible accounts expense—provision (c)
Uncollectible accounts expense—recovery, net (c)
BSC costs (d)
Other
Regulatory required programs
Energy efficiency and demand response programs
Increase in operating and maintenance expense
Increase
(Decrease)
2016 vs. 2015
Increase
(Decrease)
2015 vs. 2014
$
$
12
(24)
(9)
5
(18)
29
(1)
(6)
(31)
(37)
$
$
31
19
27
(7)
34
30
5
139
(1)
138
(a) Primarily reflects increased contracting costs related to preventative maintenance and other projects for the year ended December 31, 2015.
(b) Primarily reflects the favorable impact of higher assumed pension and OPEB discount rates for the year ended December 31, 2016 and the unfavorable impact of lower
assumed pension and OPEB discount rates for the year ended December 31, 2015.
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(c) ComEd is allowed to recover from or refund to customers the difference between the utility’s annual uncollectible accounts expense and the amounts collected in rates
annually through a rider mechanism. ComEd recorded a net decrease and increase in 2016 and 2015, respectively, in Operating and maintenance expense related to
uncollectible accounts due to the timing of regulatory cost recovery. An equal and offsetting amount has been recognized in Operating revenues for the periods presented.
(d) Primarily reflects increased information technology support services from BSC during 2016 and 2015.
Depreciation and Amortization Expense
The increases in Depreciation and amortization expense for 2016 compared to 2015, and 2015 compared to 2014, consisted of the following:
Depreciation expense (a)
Regulatory asset amortization (b)
Other
Total increase
Increase
(Decrease)
2016 vs. 2015
58
$
(5)
15
68
$
Increase
(Decrease)
2015 vs. 2014
43
$
(28)
5
20
$
(a) Primarily reflects ongoing capital expenditures for the years ended December 31, 2016 and 2015.
(b) Primarily reflects a decrease in MGP regulatory asset amortization for the year ended December 31, 2015,
Taxes Other Than Income
Taxes other than income, which can vary year to year, include municipal and state utility taxes, real estate taxes, and payroll taxes. Taxes
other than income taxes remained relatively consistent for the year ended December 31, 2016 compared to the same period in 2015, and for the
year ended December 31, 2015 compared to the same period in 2014.
Gain on Sale of Assets
Gain on sale of assets increased primarily due to the sale of land during the year ended December 31, 2016, compared to the same period in
2015. Gain on sale of assets remained relatively consistent for the year ended December 31, 2015, compared to the same period in 2014.
Interest Expense, Net
The increases in Interest expense, net, for the year ended 2016 compared to the same period in 2015, and for the year ended 2015 compared
to the same period in 2014, consisted of the following:
Interest expense related to uncertain tax positions (a)
Interest expense on debt (including financing trusts) (b)
Other
Increase (decrease) in interest expense, net
Increase
(Decrease)
2016 vs. 2015
109
$
24
(4)
129
$
Increase
(Decrease)
2015 vs. 2014
2
$
13
(4)
11
$
(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 third quarter of 2016. See Note
15—Income Taxes of the Combined Notes to Consolidated Financial Statements for additional information.
(b) Primarily reflects an increase in interest expense due to the issuance of First Mortgage Bonds for the years ended December 31, 2016 and 2015. See Note 14—Debt and
Credit Agreements of the Combined Notes to Consolidated Financial Statements for additional information on ComEd’s debt obligations.
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Other, Net
The increase (decrease) in other, net, for the year ended 2016 compared to the same period in 2015, and for the year ended 2015 compared
to the same period in 2014, consisted of the following:
Other income and deductions, net (a)
AFUDC equity
Other
Increase (decrease) in other, net
Increase
(Decrease)
2016 vs. 2015
(94)
$
9
(1)
(86)
$
Increase
(Decrease)
2015 vs. 2014
2
$
2
—
4
$
(a) Primarily reflects the recognition of the 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—
Debt and Credit Agreements of the Combined Notes to Consolidated Financial Statements for additional information.
Effective Income Tax Rate
ComEd’s effective income tax rates for the years ended December 31, 2016, 2015 and 2014, were 44.3%, 39.7% and 39.6%, respectively.
The increase in the effective income tax rate for the year ended December 31, 2016 compared to the same period in 2015 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 15—Income Taxes of the Combined Notes to Consolidated Financial Statements for additional information regarding the components of
the effective income tax rates.
ComEd Electric Operating Statistics and Revenue Detail
Retail Deliveries to customers (in GWhs)
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
Total
2016
2015
27,790
31,975
27,842
1,298
88,905
26,496
31,717
27,210
1,309
86,732
%
Change
2016 vs.
2015
Weather-
Normal
%
Change
%
Change
2015 vs.
2014
Weather-
Normal
%
Change
2014
4.9%
0.8%
2.3%
(0.8)%
2.5%
(0.6)%
(0.3)%
1.5%
(0.8)%
0.2%
27,230
32,146
27,847
1,358
88,581
(2.7)%
(1.3)%
(2.3)%
(3.6)%
(2.1)%
(1.5)%
(0.9)%
(2.0)%
(2.6)%
(1.4)%
2016
As of December 31,
2015
3,595,376
374,644
2,007
4,750
3,976,777
3,550,239
370,932
1,976
4,820
3,927,967
2014
3,502,386
369,053
1,998
4,815
3,878,252
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Electric Revenue
Retail Sales (a)
Residential
Small commercial & industrial
Large commercial & industrial
Public authorities & electric railroads
Total retail
Other revenue (b)
Total electric revenue (c)
2016
2015
$2,597
1,316
462
45
4,420
834
$5,254
$2,360
1,337
443
42
4,182
723
$4,905
%
Change
2016 vs.
2015
10.0%
(1.6)%
4.3%
7.1%
5.7%
15.4%
7.1%
%
Change
2015 vs.
2014
13.8%
0.1%
2.1%
(8.7)%
7.5%
7.1%
7.5%
2014
$2,074
1,335
434
46
3,889
675
$4,564
(a) Reflects delivery revenue and volume from customers purchasing electricity directly from ComEd and customers purchasing electricity from a competitive electric
generation supplier, as all customers are assessed delivery charges. For customers purchasing electricity from ComEd, revenue also reflects the cost of energy and
transmission.
(b) Other revenue primarily includes transmission revenue from PJM. Other revenue also includes rental revenue, revenue related to late payment charges, revenue from
other utilities for mutual assistance programs and recoveries of remediation costs associated with MGP sites.
Includes operating revenues from affiliates totaling $15 million, $4 million, and $4 million for the years ended December 31, 2016, 2015, and 2014, respectively.
(c)
Results of Operations—PECO
Operating revenues
Purchased power and fuel
Revenues net of purchased power and fuel expense (a)
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 attributable to common shareholder
2016
$2,994
1,047
1,947
811
270
164
1,245
—
702
(123)
8
(115)
587
149
$ 438
2015
$3,032
1,190
1,842
794
260
160
1,214
2
630
(114)
5
(109)
521
143
$ 378
Favorable
(unfavorable)
2016 vs. 2015
variance
$
$
(38)
143
105
(17)
(10)
(4)
(31)
(2)
72
(9)
3
(6)
66
(6)
60
2014
$3,094
1,261
1,833
866
236
159
1,261
—
572
(113)
7
(106)
466
114
$ 352
Favorable
(unfavorable)
2015 vs. 2014
variance
$
$
(62)
71
9
72
(24)
(1)
47
2
58
(1)
(2)
(3)
55
(29)
26
(a) PECO evaluates its operating performance using the measures of revenue net of purchased power expense for electric sales and revenue net of fuel expense for gas
sales. PECO believes revenue net of purchased power expense and revenue net of fuel expense are useful measurements of its performance because they provide
information that can be used to
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evaluate its net revenue from operations. PECO has included the analysis below as a complement to the financial information provided in accordance with GAAP.
However, revenue net of purchased power expense and revenue net of fuel expense figures are not a presentation defined under GAAP and may not be comparable to
other companies’ presentations or more useful than the GAAP information provided elsewhere in this report.
Net Income Attributable to Common Shareholder
Year Ended December 31, 2016 Compared to Year Ended December 31, 2015. PECO’s net income attributable to common shareholder for
the year ended December 31, 2016 was higher than the same period in 2015, primarily due to an increase in Revenues net of purchased power and
fuel expense as a result of increased electric distribution revenue pursuant to the 2015 PAPUC authorized electric distribution rate increase effective
January 1, 2016.
Year Ended December 31, 2015 Compared to Year Ended December 31, 2014. PECO’s net income attributable to common shareholder for
the year ended December 31, 2015 was higher than the same period in 2014, primarily due to a decrease in Operating and maintenance expense
due to a decrease in storm costs.
Revenues Net of Purchased Power and Fuel Expense
Electric and natural gas revenue and purchased power and fuel expense are affected by fluctuations in commodity procurement costs. PECO’s
electric supply and natural gas cost rates charged to customers are subject to adjustments as specified in the PAPUC-approved tariffs that are
designed to recover or refund the difference between the actual cost of electric supply and natural gas and the amount included in rates in
accordance with PECO’s GSA and PGC, respectively. Therefore, fluctuations in electric supply and natural gas procurement costs have no impact
on electric and natural gas revenues net of purchased power and fuel expense.
Electric and natural gas revenue and purchased power and fuel expense are also affected by fluctuations in participation in the Customer
Choice Program. All PECO customers have the choice to purchase electricity and natural gas from competitive electric generation and natural gas
suppliers, respectively. The customer’s choice of suppliers does not impact the volume of deliveries, but affects revenue collected from customers
related to supplied energy and natural gas service. Customer Choice Program activity has no impact on electric and natural gas revenue net of
purchase power and fuel expense.
Retail deliveries purchased from competitive electric generation and natural gas suppliers (as a percentage of kWh and mmcf sales,
respectively) for the years ended December 31, 2016, 2015, and 2014 consisted of the following:
Electric
Natural Gas
2016
For the Years Ended December 31,
2015
70%
26%
70%
25%
2014
70%
22%
Retail customers purchasing electric generation and natural gas from competitive electric generation and natural gas suppliers at
December 31, 2016, 2015, and 2014 consisted of the following:
Electric
Natural Gas
December 31, 2016
December 31, 2015
December 31, 2014
Number of
customers
587,200
81,300
% of total
retail
customers
36%
16%
141
Number of
customers
563,400
81,100
% of total
retail
customers
35%
16%
Number of
customers
546,900
78,400
% of total
retail
customers
34%
16%
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The changes in PECO’s Operating revenues net of purchased power and fuel expense for the years ended December 31, 2016 and
December 31, 2015 compared to the same periods in 2015 and 2014, respectively, consisted of the following:
Weather
Volume
Pricing
Regulatory required programs
Other
Total increase (decrease)
2016 vs. 2015
Increase (Decrease)
Electric
1
$
6
160
(46)
(7)
$ 114
Gas
$ (12)
4
(1)
—
—
$ (9)
Total
$ (11)
10
159
(46)
(7)
$105
2015 vs. 2014
Increase (Decrease)
Electric
28
$
4
4
(6)
(12)
18
$
Gas
$ (19)
7
2
—
1
$ (9)
Total
$ 9
11
6
(6)
(11)
$ 9
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. Operating revenues net of purchased power and fuel expense for the year ended December 31, 2016 was reduced by the
impact of unfavorable weather conditions in PECO’s service territory.
Operating revenues net of purchased power and fuel expense for the year ended December 31, 2015, was higher primarily due to the impact
of favorable 2015 summer and first quarter winter weather conditions, partially offset by the impact of unfavorable fourth quarter 2015 winter 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, 2016 and December 31, 2015 compared
to the same periods in 2015 and 2014, respectively, and normal weather consisted of the following:
Heating and Cooling Degree-Days
Heating Degree-Days
Cooling Degree-Days
Heating and Cooling Degree-Days
Heating Degree-Days
Cooling Degree-Days
For the Years Ended
December 31,
2016
4,041
1,726
2015 Normal
4,613
4,245
1,301
1,720
For the Years Ended
December 31,
2015
4,245
1,720
2014 Normal
4,613
4,749
1,301
1,311
% Change
2016 vs. 2015
2016 vs. Normal
(4.8)%
0.3%
(12.4)%
32.7%
% Change
2015 vs. 2014
2015 vs. Normal
(10.6)%
31.2%
(8.0)%
32.2%
Volume. The increase in Operating revenues net of purchased power and fuel expense related to delivery volume, exclusive of the effects of
weather, for the year ended December 31, 2016 and 2015, primarily reflects the impact of moderate economic and customer growth partially offset
by energy efficiency initiatives on customer usages for gas and residential and small commercial and industrial electric classes. Additionally, the
increase represents a shift in the volume profile across classes from large commercial and industrial classes to residential and small commercial and
industrial classes for electric.
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Pricing. The increase in electric operating revenues net of purchased power expense as a result of pricing for the year ended December 31,
2016 reflects an increase in electric distribution rates charged to customers. The increase in electric distribution rates was effective January 1, 2016
in accordance with the 2015 PAPUC approved electric distribution rate case settlement. See Note 3—Regulatory Matters for further information.
The increase in electric operating revenues net of purchased power expense as a result of pricing for the year ended December 31, 2015 is
primarily attributable to increased monthly customer demand in the commercial and industrial classes. The increase in natural gas operating
revenues net of fuel expense as a result of pricing for the year ended December 31, 2015, is primarily attributable to higher overall effective rates
due to decreased retail gas usage.
Regulatory Required Programs. This represents the change in operating 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. Refer to the Operating and maintenance expense discussion below for additional information on included programs.
Other. Other revenue, which can vary period to period, primarily includes wholesale transmission revenue, rental revenue, revenue related to
late payment charges and assistance provided to other utilities through mutual assistance programs.
Operating and Maintenance Expense
Operating and maintenance expense—
baseline
Operating and maintenance expense—
regulatory required programs (a)
Total operating and maintenance expense
Year Ended
December 31,
Increase
(Decrease)
Year Ended
December 31,
2016
2015
2016 vs. 2015
2015
2014
Increase
(Decrease)
2015 vs. 2014
$
$
740 $
685
71
811 $
109
794
$
$
$
55
(38)
17
$
$
685 $
761
109
794 $
105
866
$
$
$
(76)
4
(72)
(a) Operating and maintenance expenses for regulatory required programs are costs for various legislative and/or regulatory programs that are recoverable from customers
on a full and current basis through approved regulated rates. An equal and offsetting amount has been reflected in operating revenues.
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The changes in Operating and maintenance expense for 2016 compared to 2015 and 2015 compared to 2014 consisted of the following:
Baseline
Labor, other benefits, contracting and materials
Storm-related costs
Pension and non-pension postretirement benefits expense
PHI merger integration costs
BSC costs (a)
Uncollectible accounts expense
Other
Regulatory required programs
Smart meter
Energy efficiency
GSA
Other
Increase (decrease) in operating and maintenance expense
(a) Primarily reflects increased information technology support services from BSC during 2016.
(b) Reflects a reduction of $67 million in incremental storm costs, primarily as a result of the February 5, 2014 ice storm.
Increase
(Decrease)
2016 vs. 2015
Increase
(Decrease)
2015 vs. 2014
$
$
22
(9)
(4)
6
36
1
3
55
(28)
(7)
(2)
(1)
(38)
17
$
$
1
(78) (b)
3
2
9
(22)
9
(76)
(3)
8
—
(1)
4
(72)
Depreciation and Amortization Expense
The changes in Depreciation and amortization expense for 2016 compared to 2015 and 2015 compared to 2014, consisted of the following:
Depreciation expense
Regulatory asset amortization
Increase in depreciation and amortization expense
Taxes Other Than Income
Increase
(Decrease)
2016 vs. 2015
5
$
5
10
$
Increase
(Decrease)
2015 vs. 2014
13
$
11
24
$
Taxes other than income, which can vary year to year, include municipal and state utility taxes, real estate taxes, and payroll taxes. Taxes
other than income increased for the year ended December 31, 2016, compared to the same period in 2015 primarily due to an increase in gross
receipts tax driven by increases in electric revenue, which was impacted primarily by the new distribution rates that went into effect in January 2016 .
Taxes other than income remained relatively consistent for the year ended December 31, 2015, compared to the same period in 2014.
Interest Expense, Net
The increase in Interest expense, net for the year ended December 31, 2016, compared to the same period in 2015, primarily reflects an
increase in interest expense due to the issuance of First and Refunding Mortgage Bonds in October 2015.
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Interest expense, net remained relatively consistent for the year ended December 31, 2015, compared to the same period in 2014.
Other, Net
Other, net remained relatively consistent for the year ended December 31, 2016, compared to the same period in 2015, and the year ended
December 31, 2015, compared to the same period in 2014.
Effective Income Tax Rate
PECO’s effective income tax rates for the years ended December 31, 2016, 2015 and 2014 were 25.4%, 27.4% and 24.5%, respectively. See
Note 15—Income Taxes of the Combined Notes to Consolidated Financial Statements for further discussion of the change in effective income tax
rates.
PECO Electric Operating Statistics and Revenue Detail
Retail Deliveries to Customers (in GWhs)
Retail Deliveries (a)
Residential
Small commercial & industrial
Large commercial & industrial
Public authorities & electric railroads
Total electric retail deliveries
Number of Electric Customers
Residential
Small commercial & industrial
Large commercial & industrial
Public authorities & electric railroads
Total
Electric Revenue
Retail Sales (a)
Residential
Small commercial & industrial
Large commercial & industrial
Public authorities & electric railroads
Total retail
Other revenue (b)
Total electric operating revenues (c)
2016
2015
13,664
8,099
15,263
890
37,916
13,630
8,118
15,365
881
37,994
%
Change
2016 vs.
2015
Weather-
Normal
%
Change
%
Change
2015 vs.
2014
Weather-
Normal
%
Change
2014
0.2%
(0.2)%
(0.7)%
1.0%
(0.2)%
0.4%
0.5%
(1.4)%
1.0%
(0.3)%
13,222
8,025
15,310
937
37,494
3.1%
1.2%
0.4%
(6.0)%
1.3%
0.3%
0.6%
(0.5)%
(6.0)%
(0.1)%
2016
As of December 31,
2015
1,456,585
150,142
3,096
9,823
1,619,646
1,444,338
149,200
3,091
9,805
1,606,434
2014
1,434,011
149,149
3,103
9,734
1,595,997
2016
2015
$1,631
430
234
32
2,327
204
$2,531
$1,599
428
221
31
2,279
207
$2,486
%
Change
2016 vs.
2015
2.0%
0.5%
5.9%
3.2%
2.1%
(1.4)%
1.8%
%
Change
2015 vs.
2014
2.8%
1.2%
1.8%
(3.1)%
2.3%
(6.3)%
1.6%
2014
$1,555
423
217
32
2,227
221
$2,448
(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. For customers purchasing electricity from PECO, revenue also reflects the cost of energy and
transmission.
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(b) Other revenue includes transmission revenue from PJM and wholesale electric revenue.
(c) Total electric revenue includes operating revenues from affiliates totaling $7 million, $1 million and $1 million for the years ended December 31, 2016, 2015, and 2014,
respectively.
PECO Gas Operating Statistics and Revenue Detail
Deliveries to customers (in mmcf)
Retail Deliveries (a)
Retail sales
Transportation and other
Total natural gas deliveries
Number of Gas Customers
Residential
Commercial & industrial
Total retail
Transportation
Total
Gas revenue
Retail Sales (a)
Retail sales
Transportation and other
Total natural gas operating revenues (b)
2016
2015
%
Change
2016 vs.
2015
Weather-
Normal
%
Change
%
Change
2015 vs.
2014
Weather-
Normal
%
Change
2014
56,447
27,630
84,077
59,003
27,879
86,882
(4.3)%
(0.9)%
(3.2)%
1.5%
(0.1)%
1.0%
62,734
27,208
89,942
(5.9)%
2.5%
(3.4)%
3.3%
1.2%
2.6%
As of December 31,
2015
2016
472,606
43,668
516,274
790
517,064
467,263
43,160
510,423
827
511,250
2014
462,663
42,686
505,349
855
506,204
2016
2015
%
Change
2016 vs.
2015
$430
33
$463
$511
35
$546
(15.9)%
(5.7)%
(15.2)%
%
Change
2015 vs.
2014
(16.0)%
(7.9)%
(15.5)%
2014
$608
38
$646
(a) Reflects delivery volumes and revenue from customers purchasing natural gas directly from PECO and customers purchasing natural gas from a competitive natural gas
supplier as all customers are assessed distribution charges. For customers purchasing natural gas from PECO, revenue also reflects the cost of natural gas.
(b) Total natural gas revenues includes operating revenues from affiliates totaling $1 million for the years ended December 31, 2016, 2015 and 2014.
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Results of Operations—BGE
Operating revenues
Purchased power and fuel expense
Revenues net of purchased power and fuel expense (a)
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
Preference stock dividends
Net income attributable to common shareholder
2016
$3,233
1,294
1,939
737
423
229
1,389
—
550
(103)
21
(82)
468
174
294
8
$ 286
2015
$3,135
1,305
1,830
683
366
224
1,273
1
558
(99)
18
(81)
477
189
288
13
$ 275
Favorable
(unfavorable)
2016 vs. 2015
variance
$
$
98
11
109
(54)
(57)
(5)
(116)
(1)
(8)
(4)
3
(1)
(9)
15
6
5
11
2014
$3,165
1,417
1,748
717
371
221
1,309
—
439
(106)
18
(88)
351
140
211
13
$ 198
Favorable
(unfavorable)
2015 vs. 2014
variance
$
$
(30)
112
82
34
5
(3)
36
1
119
7
—
7
126
(49)
77
—
77
(a) BGE evaluates its operating performance using the measures of revenue net of purchased power expense for electric sales and revenue net of fuel expense for gas sales.
BGE believes revenues net of purchased power and fuel expense are useful measurements of its performance because they provide information that can be used to
evaluate its net revenue from operations. BGE has included the analysis below as a complement to the financial information provided in accordance with GAAP. However,
revenues net of purchased power and fuel expense figures are not a presentation defined under GAAP and may not be comparable to other companies’ presentations or
more useful than the GAAP information provided elsewhere in this report.
Net Income Attributable to Common Shareholder
Year Ended December 31, 2016 Compared to Year Ended December 31, 2015. Net income attributable to common shareholder was higher
primarily due to lower income tax expense and decreased preference stock dividends partially offset by slightly lower operating income. The lower
income tax expense was driven by a one-time adjustment associated with transmission-related regulatory assets. The slight decrease in operating
income was driven by an increase in Operating and maintenance expense as a result of cost disallowances which reduced certain regulatory assets
and other long-lived assets stemming from the distribution rate orders issued by the MDPSC in June 2016 and July 2016 and increased storm costs.
This increase in Operating and maintenance expense was offset by an increase in Revenues net of purchased power and fuel expense, primarily as
a result of an increase in transmission formula rate revenues and higher electric and natural gas revenues as a result of the distribution rate orders
issued by the MDPSC in June 2016 and July 2016.
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Year Ended December 31, 2015 Compared to Year Ended December 31, 2014. Net income attributable to common shareholder was higher
primarily due to an increase in Revenues net of purchased power and fuel expense as a result of the December 2014 electric and natural gas
distribution rate order issued by the MDPSC, an increase in transmission formula rate revenues and a reduction in Operating and maintenance
expense as a result of a decrease in bad debt expense and storm costs in the BGE service territory.
Revenues Net of Purchased Power and Fuel Expense
There are certain drivers to Operating revenues that are offset by their impact on Purchased power and fuel expense, such as commodity
procurement costs and programs allowing customers to select a competitive electric or natural gas supplier. Operating revenues and Purchased
power and fuel expense are affected by fluctuations in commodity procurement costs. BGE’s electric and natural gas rates charged to customers are
subject to periodic adjustments that are designed to recover or refund the difference between the actual cost of purchased electric power and
purchased natural gas and the amount included in rates in accordance with the MDPSC’s market-based SOS and gas commodity programs,
respectively.
Electric and natural gas revenue and purchased power and fuel expense are also affected by fluctuations in the number of customers electing
to use a competitive electric generation or natural gas supplier. All BGE customers have the choice to purchase electricity and natural gas from
competitive electric generation and natural gas suppliers, respectively. This customers’ choice of suppliers does not impact the volume of deliveries,
but does affect revenue collected from customers related to supplied energy and natural gas service.
Retail deliveries purchased from competitive electric generation and natural gas suppliers (as a percentage of kWh and mmcf sales,
respectively) at December 31, 2016, 2015 and 2014 consisted of the following:
Electric
Natural Gas
2016
For the Years Ended December 31,
2015
59%
57%
61%
56%
2014
60%
53%
The number of retail customers purchasing electric generation and natural gas from competitive electric generation and natural gas suppliers
at December 31, 2016, 2015 and 2014 consisted of the following:
Electric
Natural Gas
December 31, 2016
December 31, 2015
December 31, 2014
Number of
Customers
337,000
151,000
% of total retail
customers
27%
23%
Number of
Customers
343,000
154,000
148
% of total retail
customers
27%
23%
Number of
Customers
364,000
161,000
% of total retail
customers
29%
25%
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The changes in BGE’s Operating revenues net of purchased power and fuel expense for the year ended December 31, 2016 compared to the
same period in 2015 and for the year ended December 31, 2015 compared to the same period in 2014, respectively, consisted of the following:
Distribution rate increase
Regulatory required programs
Transmission revenue
Other, net
Total increase
2016
Increase (Decrease)
2015
Increase (Decrease)
Electric
24
$
15
30
19
88
$
Gas
$ 22
2
—
(3)
$ 21
Total
$ 46
17
30
16
$109
Electric
20
$
4
11
10
45
$
Gas
$ 35
2
—
—
$ 37
Total
$ 55
6
11
10
$ 82
Distribution Rate Increase. The increase in distribution revenues for the year ended December 31, 2016 was primarily due to the impact of the
new electric and natural gas distribution rates charged to customers that became effective in June 2016 in accordance with the MDPSC approved
electric and natural gas distribution rate case orders in June 2016 and July 2016. The increase in distribution revenue for the year ended
December 31, 2015 was primarily due to the impact of the new electric and natural gas distribution rates charged to customers that became effective
in December 2014 in accordance with the MDPSC approved electric and natural gas distribution rate case order. See Note 3—Regulatory Matters of
the Combined Notes to Consolidated Financial Statements for additional information.
Revenue Decoupling. The demand for electricity and natural gas is affected by weather and usage conditions. The MDPSC allows BGE to
record a monthly adjustment to its electric and natural gas distribution revenue from all residential customers, commercial electric customers, the
majority of large industrial electric customers, and all firm service natural gas customers to eliminate the effect of abnormal weather and usage
patterns per customer on BGE’s electric and natural gas distribution volumes, thereby recovering a specified dollar amount of distribution revenue
per customer, by customer class, regardless of changes in actual consumption levels. This allows BGE to recognize revenue at MDPSC-approved
levels per customer, regardless of what BGE’s actual distribution volumes were for a billing period. Therefore, while this revenue is affected by
customer growth (i.e., increase in the number of customers), it will not be affected by actual weather or usage conditions (i.e., changes in
consumption per customer). BGE bills or credits customers in subsequent months for the difference between approved revenue levels under
revenue decoupling and actual customer billings.
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 BGE’s service territory. The
changes in heating and cooling degree days in BGE’s service territory for the year ended December 31, 2016 compared to the same period in 2015
and for the year ended December 31, 2015 compared to the same period in 2014, respectively, and normal weather consisted of the following:
Heating and Cooling Degree-Days
Heating Degree-Days
Cooling Degree-Days
Heating and Cooling Degree-Days
Heating Degree-Days
Cooling Degree-Days
For the Year Ended
December 31,
2016
4,427
998
2015
4,666
924
Normal
4,684
876
2016 vs. 2015
2016 vs. Normal
% Change
(5.1)%
8.0%
(5.5)%
13.9%
For the Year Ended
December 31,
2015
4,666
924
2014
5,091
732
Normal
4,663
875
2015 vs. 2014
2015 vs. Normal
% Change
(8.3)%
26.2%
0.1%
5.6%
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Table of Contents
Regulatory Required Programs. This represents the change in revenue collected under approved riders to recover costs incurred for the
energy efficiency and demand response programs. The riders are designed to provide full 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
in BGE’s Consolidated Statements of Operations and Comprehensive Income.
Transmission Revenue. Under a FERC approved formula, transmission revenue varies from year to year based upon fluctuations in the
underlying costs, investments being recovered and other billing determinants. During the years ended December 31, 2016 and 2015, the increase in
transmission revenue was primarily due to increases in rates to reflect capital investment and operating and maintenance expense recoveries. See
Operating and Maintenance Expense below and Note 3—Regulatory Matters of the Combined Notes to Consolidated Financial Statements for
additional information.
Other, Net. Other net revenue, which can vary from period to period, includes commodity electric and gas revenue and other miscellaneous
revenue such as service application and late payment fees; partially offset by commodity electric and gas purchased fuel and energy.
Operating and Maintenance Expense
The changes in operating and maintenance expense for 2016 compared to 2015 and 2015 compared to 2014 consisted of the following:
Baseline
Impairment on long-lived assets and losses on regulatory assets (a)
Labor, other benefits, contracting and materials
Storm-related costs
Uncollectible accounts expense (b)
BSC costs (c)
Conduit lease settlement
Other
Increase (Decrease) in operating and maintenance expense
Increase
(Decrease)
2016 vs. 2015
Increase
(Decrease)
2015 vs. 2014
$
$
52
7
18
(14)
11
(15)
(5)
54
$
$
—
12
(21)
(49)
13
—
11
(34)
(a) See Note 3 — Regulatory Matters of the Combined Notes to Consolidated Financial Statements for additional information.
(b) Uncollectible accounts expense decreased primarily due to improved customer behavior and milder weather for the years ended December 31, 2016 and 2015.
(c) Primarily reflects increased information technology support services and other services from BSC for the year ended December 31, 2016 and increased information
technology support services for the year ended 2015.
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 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
have 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 credit to Operating and maintenance expense in the fourth quarter of
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approximately $28 million for the reversal of the previously higher fees accrued in the current year as well as the settlement of prior year disputed fee
true-up amounts. See Note 24—Commitments and Contingencies of the Combined Notes to Consolidated Financial Statements for additional
information on the financial impacts of the newly agreed upon six-year lease.
Depreciation and Amortization Expense
The changes in depreciation and amortization expense for 2016 compared to 2015 and 2015 compared to 2014 consisted of the following:
Depreciation expense (a)
Regulatory asset amortization (b)
Other
Increase (Decrease) in depreciation and amortization expense
Increase
(Decrease)
2016 vs. 2015
10
$
47
—
57
$
Increase
(Decrease)
2015 vs. 2014
2
$
(6)
(1)
(5)
$
(a) Depreciation expense increased due to ongoing capital expenditures.
(b) Regulatory asset amortization increased for the year ended December 31, 2016 compared to the same period in 2015 primarily due to an increase in regulatory asset
amortization related 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 3—Regulatory Matters of the Combined Notes to Consolidated Financial Statements for additional information.
Taxes Other Than Income
The change in taxes other than income for 2016 compared to 2015 and 2015 compared to 2014 consisted of the following:
Property tax
Franchise tax
Other
Increase in taxes other than income
Interest Expense, Net
Increase
(Decrease)
2016 vs. 2015
6
$
—
—
6
$
The decrease in Interest expense, net for 2016 compared to 2015 and 2015 compared to 2014 consisted of the following:
Interest expense on debt (including financing trusts)
Interest expense related to capitalization of interest / AFUDC
Interest expense related to uncertain tax positions
Interest Expense related to repayment of the rate stabilization bonds
Increase (Decrease) in interest expense, net
151
Increase
(Decrease)
2016 vs. 2015
5
$
3
—
(4)
4
$
Increase
(Decrease)
2015 vs. 2014
3
$
1
(1)
3
$
Increase
(Decrease)
2015 vs. 2014
(4)
$
(2)
(1)
—
(7)
$
Table of Contents
Effective Income Tax Rate
BGE’s effective income tax rates for the years ended December 31, 2016, 2015 and 2014 were 37.2%, 39.6% and 39.9%, respectively. See
Note 15—Income Taxes of the Combined Notes to Consolidated Financial Statements for additional information regarding the components of the
effective income tax rates.
BGE Electric Operating Statistics and Revenue Detail
Retail Deliveries to customers (in GWhs)
Retail Deliveries (a)
Residential
Small commercial & industrial
Large commercial & industrial
Public authorities & electric railroads
Total electric deliveries
Number of Electric Customers
Residential
Small commercial & industrial
Large commercial & industrial
Public authorities & electric railroads
Total
Electric Revenue
Retail Sales (a)
Residential
Small commercial & industrial
Large commercial & industrial
Public authorities & electric railroads
Total retail
Other revenue (b)
Total electric operating revenues
2016
2015
% Change
2016 vs. 2015
Weather-
Normal %
Change
2014
% Change
2015 vs. 2014
Weather-
Normal %
Change
12,740
3,040
13,957
283
30,020
12,598
3,119
14,293
294
30,304
1.1%
(2.5)%
(2.4)%
(3.7)%
(0.9)%
n.m.
n.m.
n.m.
n.m.
n.m.
12,974
3,086
14,191
311
30,562
(2.9)%
1.1%
0.7%
(5.5)%
(0.8)%
n.m.
n.m.
n.m.
n.m.
n.m.
2016
As of December 31,
2015
1,150,096
113,230
12,053
280
1,275,659
1,137,934
113,138
11,906
285
1,263,263
2014
1,125,369
112,972
11,730
290
1,250,361
2016
2015
% Change
2016 vs. 2015
$1,554
277
449
35
2,315
294
$2,609
$1,449
273
469
32
2,223
267
$2,490
7.2%
1.5%
(4.3)%
9.4%
4.1%
10.1%
4.8%
2014
$1,404
271
491
32
2,198
262
$2,460
% Change
2015 vs. 2014
3.2%
0.7%
(4.5)%
— %
1.1%
1.9%
1.2%
(a) Reflects delivery revenue and volumes from customers purchasing electricity directly from BGE and customers purchasing electricity from a competitive electric
generation supplier as all customers are assessed distribution charges. For customers purchasing electricity from BGE, revenue also reflects the cost of energy and
transmission.
Includes operating revenues from affiliates totaling $7 million for the year ended December 31, 2016 and less than $1 million in the years ended December 31, 2015 and
2014, respectively.
(b)
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BGE Natural Gas Operating Statistics and Revenue Detail
Deliveries to customers (in mmcf)
Retail Deliveries (a)
Retail sales
Transportation and other (b)
Total natural gas deliveries
Number of Gas Customers
Residential
Commercial & industrial
Total
Natural Gas revenue
Retail Sales (a)
Retail sales
Transportation and other (b)
Total natural gas revenues (c)
2016
2015
% Change
2016 vs. 2015
Weather-
Normal %
Change
2014
% Change
2015 vs. 2014
Weather-
Normal %
Change
96,808
5,977
102,785
96,618
6,238
102,856
0.2%
(4.2)%
(0.1)%
n.m.
n.m.
n.m.
99,194
9,242
108,436
(2.6)%
(32.5)%
(5.1)%
n.m.
n.m.
n.m.
As of December 31,
2015
2016
623,647
44,255
667,902
616,994
44,119
661,113
2014
609,626
44,200
653,826
2016
2015
$593
31
$624
$607
38
$645
% Change
2016 vs. 2015
(2.3)%
(18.4)%
(3.3)%
2014
$622
83
$705
% Change
2015 vs. 2014
(2.4)%
(54.2)%
(8.5)%
(a) Reflects delivery volumes and revenue from customers purchasing natural gas directly from BGE and customers purchasing natural gas from a competitive natural gas
supplier as all customers are assessed distribution charges. The cost of natural gas is charged to customers purchasing natural gas from BGE.
(b) Transportation and other gas revenue includes off-system revenue of 5,977 mmcfs ($23 million), 6,238 mmcfs ($35 million), and 9,242 mmcfs ($72 million) for the years
ended 2016, 2015 and 2014, respectively.
Includes operating revenues from affiliates totaling $14 million, $14 million, and $25 million for the years ended 2016, 2015 and 2014, respectively.
(c)
Results of Operations—PHI
PHI’s results of operations include the results of its three reportable segments, Pepco, DPL and ACE for all periods presented below. For
“Predecessor” reporting periods, PHI’s results of operations also include the results of PES and PCI. See Note 26—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. A separate specific discussion of the results of operations for Pepco, DPL and
ACE is presented elsewhere in this report.
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As a result of the PHI Merger, the following consolidated financial results 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 and the years ended December 31, 2015
and 2014. The “Successor” reporting period represents PHI’s results of operations for the period of March 24, 2016 to December 31, 2016. All
amounts presented below are before the impact of income taxes, except as noted.
Operating revenues
Purchased power and fuel
Revenues net of purchased power and fuel expense (a)
Other operating expenses
Operating and maintenance
Depreciation, amortization and accretion
Taxes other than income
Total other operating expenses
(Loss) gain on sales of assets
Operating income
Other income and (deductions)
Interest expense, net
Other, net
Total other income and (deductions)
(Loss) Income before income taxes
Income taxes
Net (loss) income from continuing operations
Net income from discontinued operations
Net (loss) income attributable to membership interest/common
shareholders
Successor
March 24 to
December 31,
2016
January 1 to
March 23,
2016
Predecessor
For the Years Ended December 31,
2015
2014
$
3,643 $
1,447
2,196
1,153 $
497
656
4,935 $
2,073
2,862
1,233
515
354
2,102
(1)
93
(195)
44
(151)
(58)
3
(61)
—
294
152
105
551
—
105
(65)
(4)
(69)
36
17
19
—
1,156
624
455
2,235
46
673
(280)
88
(192)
481
163
318
9
$
(61) $
19 $
327 $
4,808
2,057
2,751
1,183
526
437
2,146
—
605
(269)
44
(225)
380
138
242
—
242
(a) PHI evaluates its operating performance using the measure of revenue net of purchased power expense for electric sales. PHI believes revenue net of purchased power
expense is a useful measurement because it provides information that can be used to evaluate its operational performance. PHI has included the analysis below as a
complement to the financial information provided in accordance with GAAP. However, Revenue net of purchased power expense 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.
Successor Period of March 24, 2016 to December 31, 2016
PHI’s net loss attributable to membership interest 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,
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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. For more information on 2016 versus 2015 results please refer to Results of Operations for Pepco, DPL
and ACE.
PHI’s effective income tax rate for the period of March 24, 2016 to December 31, 2016 was (5.2)%. See Note 15—Income Taxes of the
Combined Notes to Consolidated Financial Statements for additional information regarding the components of the effective income tax rates.
Predecessor Period of January 1, 2016 to March 23, 2016
PHI’s net income attributable to membership interest 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.
PHI’s effective income tax rate for the period of January 1, 2016 to March 23, 2016 was 47.2%. See Note 15—Income Taxes of the Combined
Notes to Consolidated Financial Statements for additional information regarding the components of the effective income tax rates.
Predecessor Period Year Ended December 31, 2015 Compared to Year Ended December 31, 2014
PHI’s net income attributable to common shareholders was $327 million for the year ended December 31, 2015 as compared to $242 million
for the year ended December 31, 2014.
Revenues Net of Purchased Power and Fuel Expense
Operating revenues net of purchased power and fuel expense, which is a non-GAAP measure discussed above, increased by $111 million for
the year ended December 31, 2015 as compared to the year ended December 31, 2014. The increase is attributable to the following factors:
•
Increase of $90 million at Pepco primarily related to electric distribution revenue increases totaling $46 million due to electric distribution
base rate increases in the District of Columbia effective April 2014 and in Maryland effective July 2014 and customer growth, $34 million in
required regulatory programs primarily due to EmPower Maryland rate increases effective February 2015 and 2014, and $10 million higher
transmission revenue due to higher rates effective June 1, 2015 and June 1, 2014.
•
Increase of $26 million at DPL primarily related to electric distribution revenue increases totaling $7 million due to higher weather-related
sales and customer growth, $17 million in required regulatory programs primarily due to EmPower Maryland rate increases effective
February 2015 and 2014, and $7 million higher transmission revenue due to higher rates effective June 1, 2015 and June 1, 2014, partially
offset by lower natural gas distribution revenues totaling $5 million due to milder weather.
•
•
Increase of $41 million at ACE primarily related to electric distribution revenue increases totaling $26 million due to an electric distribution
rate increase effective September 2014 and higher weather-related sales and $15 million in required regulatory programs.
Decrease of $47 million at PES primarily related to lower energy efficiency construction activity in 2015.
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Operating and Maintenance Expense
Operating and maintenance expense decreased by $27 million for the year ended December 31, 2015 as compared to the year ended
December 31, 2014. The decrease is attributable to the following factors:
•
Increase of $107 million at Pepco, DPL and ACE primarily due to higher labor, contracting and material costs related to the
implementation of a new customer information system in 2015, increased bad debt expense, higher tree-trimming and system
maintenance costs, higher customer service costs, and higher environmental remediation costs.
•
•
Decrease of $118 million at PES primarily due to 2014 impairment losses associated with its combined heat and power thermal generating
facilities and operations in Atlantic City.
Decrease of $15 million at Corporate due primarily to lower Merger-related transaction and integration costs.
Depreciation, Amortization and Accretion Expense
Depreciation, amortization and accretion expense increased by $98 million primarily due to an increase of $48 million associated with
EmPower Maryland surcharge rate increases effective February 2015 and February 2014, higher depreciation of $23 million due to on-going capital
expenditures at Pepco, DPL, and ACE, an increase of $15 million in the amortization of stranded costs, primarily as the result of higher revenue due
to a rate increase effective October 2014 for the ACE Market Transition Tax and an increase of $10 million in amortization of software, primarily
related to the implementation of a new customer information system.
Taxes Other Than Income
Taxes other than income increased by $18 million primarily due to higher property taxes related to an increase in assets.
(Loss) gain on Sale of Assets
(Loss) gain on sale of assets increased by $46 million due to 2015 gains recorded at Pepco associated with the sale of unimproved land, held
as non-utility property.
Interest Expense, Net
Interest expense increased by $11 million due to higher long-term and short-term debt.
Other, Net
Other, net increased by $44 million due to $33 million of interest income on uncertain tax positions from the PHI Global Tax Settlement and an
increase in income of $15 million due to an increase in the fair value of the derivative related to preferred stock.
Effective Income Tax Rate
PHI’s effective income tax rates for the years ended December 31, 2015 and December 31, 2014 were 33.9% and 36.3%, respectively. See
Note 15—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—Pepco
Operating revenues
Purchased power expense
Revenues net of purchased power expense (a)
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 attributable to common shareholder
2016
$2,186
706
1,480
642
295
377
1,314
8
174
(127)
36
(91)
83
41
42
$
2015
$2,129
719
1,410
439
256
376
1,071
46
385
(124)
28
(96)
289
102
$ 187
Favorable
(unfavorable)
2016 vs. 2015
variance
$
$
57
13
70
(203)
(39)
(1)
(243)
(38)
(211)
(3)
8
5
(206)
61
(145)
2014
$2,055
735
1,320
390
212
369
971
—
349
(115)
30
(85)
264
93
$ 171
Favorable
(unfavorable)
2015 vs. 2014
variance
$
$
74
16
90
(49)
(44)
(7)
(100)
46
36
(9)
(2)
(11)
25
(9)
16
(a) Pepco evaluates its operating performance using the measure of revenue net of purchased power expense for electric sales. Pepco believes revenue net of purchased
power expense is a useful measurement because it provides information that can be used to evaluate its operational performance. Pepco has included the analysis below
as a complement to the financial information provided in accordance with GAAP. However, Revenue net of purchased power expense 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.
Net Income Attributable to Common Shareholder
Year Ended December 31, 2016 Compared to Year Ended December 31, 2015. Pepco’s net income attributable to common shareholder for
the year ended December 31, 2016, was lower than the same period in 2015, primarily due to an increase in Operating and maintenance expense
due to merger-related costs.
Year Ended December 31, 2015 Compared to Year Ended December 31, 2014. The increase in net income attributable to common
shareholder was driven primarily by an increase in gains recorded from the sale of certain Pepco properties in 2015 and higher Operating revenues
net of purchased power expense resulting from customer growth and electric distribution base rate increases in 2014 in the District of Columbia and
Maryland, partially offset by an increase in Operating and maintenance expense primarily due to the implementation of a new customer information
system and higher maintenance expense.
Revenues Net of Purchased Power Expense
Operating revenues include revenue from the distribution and supply of electricity to Pepco’s customers within its service territories at
regulated rates. Operating revenues also include transmission service revenue that Pepco receives as a transmission owner from PJM at rates
regulated by FERC. Transmission rates are updated annually based on a FERC-approved formula methodology.
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Electric revenues and purchased power expense are also affected by fluctuations in participation in the Customer Choice Program. All Pepco
customers have the choice to purchase electricity from competitive electric generation suppliers. The customers’ choice of supplier does not impact
the volume of deliveries, but affects revenue collected from customers related to supplied energy service.
Retail deliveries purchased from competitive electric generation suppliers (as a percentage of kWh sales) for the years ended December 31,
2016, 2015, and 2014 respectively , consisted of the following:
Electric
2016
For the Years Ended December 31,
2015
65%
65%
2014
65%
Retail customers purchasing electric generation from competitive electric generation suppliers at December 31, 2016, 2015, and 2014
consisted of the following:
Electric
December 31, 2016
December 31, 2015
December 31, 2014
Number of
customers
176,372
% of total
retail
customers
21%
Number of
customers
173,222
% of total
retail
customers
21%
Number of
customers
179,524
% of total
retail
customers
22%
Retail deliveries purchased from competitive electric generation suppliers represented 73% of Pepco’s retail kWh sales to the District of
Columbia customers and 59% of Pepco’s retail kWh sales to Maryland customers for the year ended December 31, 2016 ; 71% of Pepco’s retail
kWh sales to the District of Columbia customers and 60% of Pepco’s retail kWh sales to Maryland customers for the year ended December 31,
2015; and 73% of Pepco’s retail kWh sales to the District of Columbia customers and 59% of Pepco’s retail kWh sales to Maryland customers for
year ended December 31, 2014.
The costs related to default electricity supply are included in Purchased power expense. Operating revenues also include transmission
enhancement credits that Pepco receives as a transmission owner from PJM in consideration for approved regional transmission expansion plan
expenditures.
Operating revenues also include work and services performed on behalf of customers, including other utilities, which is generally not subject to
price regulation. Work and services includes mutual assistance to other utilities, highway relocation, rentals of pole attachments, late payment fees
and collection fees.
Purchased power expense consists of the cost of electricity purchased by Pepco to fulfill its default electricity supply obligation and, as such, is
recoverable from customers in accordance with the terms of public service commission orders.
The changes in Pepco’s operating revenues net of purchased power expense for the years ended December 31, 2016 and 2015 compared to
the same periods in 2015 and 2014, respectively, consisted of the following:
Volume
Pricing—distribution revenues
Regulatory required programs
Transmission revenues
Other
Total increase
158
Increase
(Decrease)
2016 vs. 2015
15
$
5
48
(1)
3
70
$
Increase
(Decrease)
2015 vs. 2014
24
$
20
34
10
2
90
$
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Revenue Decoupling. Pepco’s results historically have been seasonal, generally producing higher revenue and income in the warmest and
coldest periods of the year. For retail customers of Pepco in Maryland and in the District of Columbia, revenues are not affected by unseasonably
warmer or colder weather because a bill stabilization adjustment (BSA) for retail customers was implemented that provides for a fixed distribution
charge per customer. The BSA has the effect of decoupling the distribution revenue recognized in a reporting period from the amount of power
delivered during the period. As a result, the only factors that will cause distribution revenue from customers in Maryland and the District of Columbia
to fluctuate from period to period are changes in the number of customers and changes in the approved distribution charge per customer. Changes
in customer usage (due to weather conditions, energy prices, energy efficiency programs or other reasons) from period to period have no impact on
reported distribution revenue for customers to whom the BSA applies.
In accounting for the BSA in Maryland and the District of Columbia, a Revenue Decoupling Adjustment is recorded representing either (i) a
positive adjustment equal to the amount by which revenue from Maryland and the District of Columbia retail distribution sales falls short of the
revenue that Pepco is entitled to earn based on the approved distribution charge per customer or (ii) a negative adjustment equal to the amount by
which revenue from such distribution sales exceeds the revenue that Pepco is entitled to earn based on the approved distribution charge per
customer.
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 Pepco’s service territory. The
changes in heating and cooling degree days in Pepco’s service territory for the years ended December 31, 2016 and December 31, 2015 compared
to same periods in 2015 and 2014, respectively, and normal weather consisted of the following:
Heating and Cooling Degree-Days
Heating Degree-Days
Cooling Degree-Days
Heating and Cooling Degree-Days
Heating Degree-Days
Cooling Degree-Days
For the Years Ended
December 31,
2016
3,624
1,936
2015
3,657
1,936
For the Years Ended
December 31,
2015
2014
3,657
1,936
4,017
1,662
Normal
3,887
1,626
Normal
3,914
1,614
% Change
2016 vs. 2015
2016 vs. Normal
(0.9)%
— %
(6.8)%
19.1%
% Change
2015 vs. 2014
2015 vs. Normal
(9.0)%
16.5%
(6.6)%
20.0%
Volume. The increase in operating revenues net of purchased power and fuel expense related to delivery volume, exclusive of the effects of
weather, for the year ended December 31, 2016 compared to the same period in 2015 primarily reflects the impact of moderate economic and
customer growth. The increase in operating revenues net of purchased power and fuel expense related to delivery volume, exclusive of the effects of
weather, for the year ended December 31, 2015 compared to the same period in 2014 primarily reflects the impact of moderate economic and
customer growth.
Pricing—Distribution Revenues. The increase in electric operating revenues net of purchased power expense as a result of pricing for the year
ended December 31, 2016 compared to the same period in 2015 was primarily due to the impact of the new electric distribution rates charged to
customers in Maryland that became effective in November 2016. The increase in distribution revenue for the year ended December 31, 2015
compared to the same period in 2014 was primarily due to the impact of the new electric distribution rates charged to customers in the District of
Columbia effective April 2014 and in Maryland effective July 2014. See Note 3—Regulatory Matters of the Combined Notes to Consolidated
Financial Statements for additional information.
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Regulatory Required Programs. This represents the change in operating revenues collected under approved riders to recover costs incurred
for regulatory programs such as energy efficiency programs. 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. Refer
to the operating and maintenance expense discussion below for additional information on included programs.
Transmission Revenues . Under a FERC approved formula, transmission revenue varies from year to year based upon fluctuations in the
underlying costs, investments being recovered and other billing determinants. Transmission revenue decreased for the year ended December 31,
2016 compared to the same period in 2015 due to lower revenue related to the MAPP abandonment recovery period that ended in March 2016,
partially offset by higher rates effective June 1, 2016 and June 1, 2015 related to increases in transmission plant investment and operating
expenses. Transmission revenue increased for the year ended December 31, 2015 compared to the same period in 2014 due to higher rates
effective June 1, 2015 and June 1, 2014 related to increases in transmission plant investment and operating expenses, partially offset by the
establishment of a reserve related to the FERC ROE challenges in 2015.
Operating and Maintenance Expense
Operating and maintenance expense—baseline
Operating and maintenance expense—regulatory required programs (a)
Total operating and maintenance expense
Year Ended
December 31,
2016
$631
11
$642
2015
$427
12
$439
Increase
(Decrease)
2016 vs.
2015
$
$
204
(1)
203
Year Ended
December 31,
2015
$427
12
$439
2014
$379
11
$390
Increase
(Decrease)
2015 vs.
2014
$
$
48
1
49
(a) Operating and maintenance expenses for regulatory required programs are costs for various legislative and/or regulatory programs that are recoverable from customers
on a full and current basis through approved regulated rates. An equal and offsetting amount has been reflected in Operating revenues.
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The changes in operating and maintenance expense for 2016 compared to 2015 and 2015 compared to 2014 consisted of the following:
Baseline
Labor, other benefits, contracting and materials
Storm-related costs
Pension and non-pension postretirement benefits expense
Remeasurement of AMI—related regulatory asset
Deferral of billing system transition costs to regulatory asset
Deferral of merger-related costs to regulatory asset
Uncollectible accounts expense—provision
BSC and PHISCO allocations (a)
Merger commitments (b)
Write-off of construction work in progress (c)
Other
Regulatory required programs
Purchased power administrative costs
Total increase
Increase
(Decrease)
2016 vs. 2015
Increase
(Decrease)
2015 vs. 2014
$
$
7
6
—
7
(7)
(11)
8
53
126
13
2
204
(1)
(1)
203
$
$
26
(3)
4
—
—
—
4
15
—
—
2
48
1
1
49
(a) Primarily related to merger severance and compensation costs for the year ended December 31, 2016 compared to the same period in 2015.
(b) Primarily related to merger-related commitments for customer rate credits and charitable contributions.
(c) Primarily resulting from a review of capital projects during the fourth quarter of 2016.
Depreciation and Amortization Expense
The changes in depreciation and amortization expense for 2016 compared to 2015 and 2015 compared to 2014 consisted of the following:
Depreciation expense (a)
Regulatory asset amortization (b)
Total increase
Increase
(Decrease)
2016 vs. 2015
11
$
28
39
$
Increase
(Decrease)
2015 vs. 2014
10
$
34
44
$
(a) Depreciation expense increased primarily due to ongoing capital expenditures.
(b) Regulatory asset amortization increased for the year ended December 31, 2016 compared to the same period in 2015 primarily due to an EmPower Maryland surcharge
rate increase effective February 2016, partially offset by lower amortization of MAPP abandonment costs and for the year ended December 31, 2015 compared to the
same period in 2014 due to an EmPower Maryland surcharge rate increase effective February 2015.
Taxes Other Than Income
Taxes other than income for the year ended December 31, 2016 compared to the same period in 2015 increased primarily due to higher utility
taxes that are collected and passed through by Pepco, partially offset by lower property taxes in Maryland. Taxes other than income for the year
ended December 31, 2015 compared to the same period in 2014 increased primarily due to higher property taxes in Maryland.
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Gain on Sales of Assets
Gain on Sale of Assets for the year ended December 31, 2016 compared to the same period in 2015 decreased primarily due to higher gains
recorded in 2015 at Pepco associated with the sale of land held as non-utility property. Gain on sale of assets for the year ended December 31,
2015 compared to the same period in 2014 increased primarily due to 2015 gains recorded at Pepco associated with the sale of land.
Interest Expense, Net
Interest expense, net for the year ended December 31, 2016 compared to the same period in 2015 increased primarily due to the recording of
interest expense for an uncertain tax position in 2016, partially offset by an increase in capitalized AFUDC debt. Interest expense, net for the year
ended December 31, 2015 compared to the same period in 2014 increased primarily due to higher long-term debt interest expense.
Other, Net
Other, net for the year ended December 31, 2016 compared to the same period in 2015 increased primarily due to higher income from AFUDC
equity. Other, net for the year ended December 31, 2015 compared to the same period in 2014 decreased primarily due to gains recorded in 2014
associated with condemnation awards for certain transmission property, partially offset by higher income from AFUDC equity.
Effective Income Tax Rate
Pepco’s effective income tax rates for the years ended December 31, 2016, 2015, and 2014 were 49.4%, 35.3%, and 35.2%, respectively. See
Note 15—Income Taxes of the Combined Notes to Consolidated Financial Statements for additional information regarding the components of the
change in effective income tax rates. As a result of the merger, Pepco recorded an after-tax charge of $31 million during the year ended
December 31, 2016 as a result of the assessment and remeasurement of certain federal and state uncertain tax positions.
Pepco Electric Operating Statistics and Revenue Detail
Retail Deliveries to Customers (in GWhs)
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
Total
2016
2015
8,372
1,459
15,559
724
26,114
8,452
1,471
15,351
714
25,988
%
Change
2016 vs.
2015
Weather-
Normal
%
Change
%
Change
2015 vs.
2014
Weather-
Normal
%
Change
2014
(0.9)%
(0.8)%
1.4%
1.4%
0.5%
1.6%
0.8%
1.0%
— %
1.1%
7,854
1,747
15,410
740
25,751
7.6%
(15.8)%
(0.4)%
(3.5)%
0.9%
2.2%
1.4%
1.2%
— %
1.5%
As of December 31,
2015
2016
780,652
53,529
21,391
130
855,702
767,392
53,838
20,976
129
842,335
162
2014
740,102
54,176
20,649
124
815,051
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Electric Revenue
Retail Sales (a)
Residential
Small commercial & industrial
Large commercial & industrial
Public authorities & electric railroads
Total retail
Other revenue (b)
Total electric revenue (c)
2016
2015
$1,000
150
803
32
1,985
201
$2,186
$ 970
153
777
30
1,930
199
$2,129
%
Change
2016 vs.
2015
3.1%
(2)%
3.3%
6.7%
2.8%
1.0%
2.7%
%
Change
2015 vs.
2014
9.1%
(12.1)%
1.4%
— %
3.8%
1.5%
3.6%
2014
$ 889
174
766
30
1,859
196
$2,055
(a) Reflects delivery volumes and revenues from customers purchasing electricity directly from Pepco and customers purchasing electricity from a competitive electric
generation supplier as all customers are assessed distribution charges. For customers purchasing electricity from Pepco, revenue also reflects the cost of energy and
transmission.
(b) Other revenue includes transmission revenue from PJM and wholesale electric revenues.
(c)
Includes operating revenues from affiliates totaling $5 million for the years ended December 31, 2016, 2015 and 2014, respectively.
Results of Operations—DPL
Operating revenues
Purchased power and fuel
Revenues net of purchased power and fuel expense (a)
Other operating expenses
Operating and maintenance
Depreciation, amortization and accretion
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 (loss) income attributable to common shareholder
2016
$1,277
583
694
441
157
55
653
9
50
(50)
13
(37)
13
22
(9)
$
2015
$1,302
634
668
304
148
51
503
—
165
(50)
10
(40)
125
49
76
$
Favorable
(unfavorable)
2016 vs. 2015
variance
$
$
(25)
51
26
(137)
(9)
(4)
(150)
9
(115)
—
3
3
(112)
27
(85)
2014
$1,282
640
642
267
122
46
435
—
207
(48)
10
(38)
169
65
$ 104
Favorable
(unfavorable)
2015 vs. 2014
variance
$
$
20
6
26
(37)
(26)
(5)
(68)
—
(42)
(2)
—
(2)
(44)
16
(28)
(a) DPL evaluates its operating performance using the measure of revenue net of purchased power expense for electric sales and revenue net of fuel expense for gas sales.
DPL believes revenue net of purchased power expense and revenue net of fuel expense are useful measurements because they provide information that can be used to
evaluate its operational performance. DPL has included the analysis below as a complement to the financial information provided in accordance with GAAP. However,
Revenue net of purchased power expense and Revenue net of fuel expense is not a presentation defined under GAAP and may not be comparable to other companies’
presentations or deemed more useful than the GAAP information provided elsewhere in this report.
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Net Income Attributable to Common Shareholder
Year Ended December 31, 2016 Compared to Year Ended December 31, 2015. The decrease in net income attributable to common
shareholder was driven primarily by an increase in Operating and maintenance expense primarily due to merger-related costs.
Year Ended December 31, 2015 Compared to Year Ended December 31, 2014. The decrease in net income attributable to common
shareholder was driven primarily by an increase in Operating and maintenance expense primarily due to the implementation of a new customer
information system, higher bad debt expense and higher tree trimming and system maintenance costs, partially offset by higher Operating revenues
net of purchased power expense resulting from customer growth and higher transmission revenue.
Revenues Net of Purchased Power and Fuel Expense
Operating revenues include revenue from the distribution and supply of electricity to DPL’s customers within its service territories at regulated
rates. Operating revenues also include transmission service revenue that DPL receives as a transmission owner from PJM at rates regulated by
FERC. Transmission rates are updated annually based on a FERC-approved formula methodology.
Electric and gas revenues and purchased power and fuel expense are also affected by fluctuations in participation in the Customer Choice
Program. All DPL customers have the choice to purchase electricity and gas from competitive electric generation and natural gas suppliers,
respectively. The customers’ choice of suppliers does not impact the volume of deliveries, but affects revenue collected from customers related to
supplied energy and natural gas service.
Retail deliveries purchased from competitive electric generation and natural gas suppliers (as a percentage of kWh and mmcf sales,
respectively) for the years ended December 31, 2016, 2015, and 2014, consisted of the following:
Electric
Natural Gas
2016
For the Years Ended December 31,
2015
51%
28%
51%
31%
2014
53%
31%
Retail customers purchasing electric generation and natural gas from competitive electric generation and natural gas suppliers at
December 31, 2016, 2015, and 2014 consisted of the following:
Electric
Natural Gas
December 31, 2016
December 31, 2015
December 31, 2014
Number of
customers
78,994
156
% of total
retail
customers
15.2%
0.1%
Number of
customers
77,603
159
% of total
retail
customers
15.1%
0.1%
Number of
customers
78,153
157
% of total
retail
customers
15.3%
0.1%
Retail deliveries purchased from competitive electric generation suppliers represented 53% of DPL’s retail kWh sales to Delaware customers
and 48% of DPL retail kWh sales to Maryland customers for the year ended December 31, 2016; 53% of DPL’s retail kWh sales to Delaware
customers and 47% of DPL’s retail kWh sales to Maryland customers for the year ended December 31, 2015; and 56% of DPL’s retail kWh sales to
Delaware customers and 49% of DPL’s retail kWh sales to Maryland customers for the year ended December 31, 2014.
The costs related to default electricity supply are included in Purchased power and fuel. Operating revenues also include transmission
enhancement credits that DPL receives as a transmission owner from PJM in consideration for approved regional transmission expansion plan
expenditures.
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Operating revenues also include work and services performed on behalf of customers, including other utilities, which is generally not subject to
price regulation. Work and services includes mutual assistance to other utilities, highway relocation, rentals of pole attachments, late payment fees
and collection fees.
Natural Gas operating revenues includes sources that are subject to price regulation (Regulated Gas Revenue) and those that generally are
not subject to price regulation (Other Gas Revenue). Regulated gas revenue includes the revenue DPL receives from on-system natural gas
delivered sales and the transportation of natural gas for customers within its service territory at regulated rates. Other gas revenue consists of
off-system natural gas sales and the short-term release of interstate pipeline transportation and storage capacity not needed to serve customers.
Off-system sales are made possible when low demand for natural gas by regulated customers creates excess pipeline capacity.
Purchased power consists of the cost of electricity purchased by DPL to fulfill its default electricity supply obligation and, as such, is
recoverable from customers in accordance with the terms of public service commission orders. Purchased fuel consists of the cost of gas purchased
by DPL to fulfill its obligation to regulated gas customers and, as such, is recoverable from customers in accordance with the terms of public service
commission orders. It also includes the cost of gas purchased for off-system sales.
The changes in DPL’s operating revenues net of purchased power and fuel expense for the years ended December 31, 2016 and 2015
compared to the same periods in 2015 and 2014, respectively, consisted of the following:
2016 vs. 2015
Increase (Decrease)
2015 vs. 2014
Increase (Decrease)
Weather
Volume
Pricing—distribution revenues
Regulatory required programs
Transmission revenues
Other
Increase (Decrease) in revenue net of purchased power expense
Electric Gas Total Electric Gas
$ — $ — $ — $
2
1
—
—
—
2
2
12
8
(1)
23 $
4
3
12
8
(1)
$
3 $ 26 $
Total
3 $ (5) $ (2)
3
3
—
—
—
—
17
17
—
7
7
—
—
1
1
31 $ (5) $ 26
Revenue Decoupling. DPL’s results historically have been seasonal, generally producing higher revenue and income in the warmest and
coldest periods of the year. For retail customers of DPL in Maryland, revenues are not affected by unseasonably warmer or colder weather because
a bill stabilization adjustment (BSA) for retail customers was implemented that provides for a fixed distribution charge per customer. The BSA has
the effect of decoupling the distribution revenue recognized in a reporting period from the amount of power delivered during the period. As a result,
the only factors that will cause distribution revenue from customers in Maryland to fluctuate from period to period are changes in the number of
customers and changes in the approved distribution charge per customer. A modified fixed variable rate design, which would provide for a charge
not tied to a customer’s volumetric consumption of electricity or natural gas, has been proposed for DPL electricity and natural gas customers in
Delaware. Changes in customer usage (due to weather conditions, energy prices, energy efficiency programs or other reasons) from period to period
have no impact on reported distribution revenue for customers to whom the BSA applies.
In accounting for the BSA in Maryland, a Revenue Decoupling Adjustment is recorded representing either (i) a positive adjustment equal to the
amount by which revenue from Maryland retail
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distribution sales falls short of the revenue that DPL is entitled to earn based on the approved distribution charge per customer or (ii) a negative
adjustment equal to the amount by which revenue from such distribution sales exceeds the revenue that DPL is entitled to earn based on the
approved distribution charge per customer.
Weather. The demand for electricity and gas in areas not subject to the BSA is affected by weather conditions. With respect to the electric
business, very warm weather in summer months and, with respect to the electric and 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 gas. Conversely, mild
weather reduces demand. During the year ended December 31, 2016 compared to the same period in 2015, weather was not a significant impact.
During the year ended December 31, 2015 compared to the same period in 2014, operating revenues net of purchased power and fuel expense was
higher due to the impact of favorable spring and summer weather conditions in DPL’s Delaware electric service territory and lower due to the impact
of warmer weather during the fourth quarter of 2015, as compared to 2014, in DPL’s natural gas 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 electric service territory
and a 30-year period in DPL’s gas service territory. The changes in heating and cooling degree days in DPL’s service territory for the years ended
December 31, 2016 and December 31, 2015 compared to same periods in 2015 and 2014, respectively, and normal weather consisted of the
following:
Heating and Cooling Degree-Days
Heating Degree-Days
Cooling Degree-Days
Heating and Cooling Degree-Days
Heating Degree-Days
Cooling Degree-Days
For the Years Ended
December 31,
2016
4,319
1,453
2015
4,421
1,328
For the Years Ended
December 31,
2015
4,421
1,328
2014
4,724
1,139
Normal
4,572
1,188
Normal
4,592
1,184
2016 vs. 2015
2016 vs. Normal
% Change
(2.3)%
9.4%
(5.5)%
22.3%
2015 vs. 2014
2015 vs. Normal
% Change
(6.4)%
16.6%
(3.7)%
12.2%
Volume. The increase in operating revenues net of purchased power and fuel expense related to delivery volume, exclusive of the effects of
weather, for the year ended December 31, 2016 compared to the same period in 2015, primarily reflects the impact of moderate economic and
customer growth. The increase in operating revenues net of purchased power and fuel expense related to delivery volume, exclusive of the effects of
weather, for the year ended December 31, 2015 compared to the same period in 2014, primarily reflects the impact of moderate economic and
customer growth.
Pricing—Distribution Revenues. The increase in electric operating revenues net of purchased power expense as a result of pricing for the year
ended December 31, 2016 compared to the same period in 2015 was primarily due to the impact of the new electric distribution and natural gas
rates charged to customers that became effective in July 2016. See Note 3—Regulatory Matters of the Combined Notes to Consolidated Financial
Statements for additional information.
Regulatory Required Programs. This represents the change in operating revenues collected under approved riders to recover costs incurred
for regulatory programs such as energy efficiency programs. 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. Refer
to the operating and maintenance expense discussion below for additional information on included programs.
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Transmission Revenues. Under a FERC approved formula, transmission revenue varies from year to year based upon fluctuations in the
underlying costs, investments being recovered and other billing determinants. Transmission revenue increased for the year ended December 31,
2016 compared to the same period in 2015 due to higher rates effective June 1, 2016 and June 1, 2015 related to increases in transmission plant
investment and operating expenses, partially offset by lower revenue related to the MAPP abandonment recovery period that ended in March 2016.
Transmission revenue increased for the year ended December 31, 2015 compared to the same period in 2014 due to higher rates effective June 1,
2015 and June 1, 2014 related to increases in transmission plant investment and operating expenses, partially offset by the establishment of a
reserve related to the FERC ROE challenges in 2015.
Operating and Maintenance Expense
Operating and maintenance expense—baseline
Operating and maintenance expense—regulatory required programs (a)
Total operating and maintenance expense
Year Ended
December 31,
2016
$425
16
$441
2015
$289
15
$304
Increase
(Decrease)
$
136
1
137
$
Year Ended
December 31,
2015
$289
15
$304
2014
$256
11
$267
Increase
(Decrease)
33
$
4
37
$
(a) Operating and maintenance expenses for regulatory required programs are costs for various legislative and/or regulatory programs that are recoverable from customers
on a full and current basis through approved regulated rates. An equal and offsetting amount has been reflected in Operating revenues.
The changes in operating and maintenance expense for 2016 compared to 2015 and 2015 compared to 2014 consisted of the following:
Baseline
Labor, other benefits, contracting and materials
Pension and non-pension postretirement benefits expense
Storm-related costs
Remeasurement of AMI-related regulatory asset
Deferral of billing system transition costs to regulatory asset
Deferral of merger-related costs to regulatory asset
Uncollectible accounts expense—provision
BSC and PHISCO allocations (a)
Merger commitments (b)
Write-off of construction work in progress
Other
Regulatory required programs
Purchased power administrative costs
Total increase
Increase
(Decrease)
2016 vs. 2015
Increase
(Decrease)
2015 vs. 2014
$
$
1
1
5
1
(2)
(4)
3
34
86
4
7
136
1
137
$
$
5
3
1
—
—
—
6
13
—
2
3
33
4
37
(a) Primarily related to merger severance and compensation costs for the year ended December 31, 2016 compared to the same period in 2015.
(b) Primarily related to merger-related commitments for energy efficiency programs, customer rate credits and charitable contributions.
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Depreciation, Amortization and Accretion Expense
The changes in depreciation, amortization and accretion expense for 2016 compared to 2015 and 2015 compared to 2014 consisted of the
following:
Depreciation expense (a)
Regulatory asset amortization (b)
Delaware renewable energy portfolio standards deferral
Total increase
Increase
(Decrease)
2016 vs. 2015
7
$
3
(1)
9
$
Increase
(Decrease)
2015 vs. 2014
9
$
14
3
26
$
(a) Depreciation expense increased due to ongoing capital expenditures.
(b) Regulatory asset amortization increased for the year ended December 31, 2016 compared to the same period in 2015 primarily due to an EmPower Maryland surcharge
rate increase effective February 2016, partially offset by lower amortization of MAPP abandonment costs and for the year ended December 31, 2015 compared to the
same period in 2014 due to an EmPower Maryland surcharge rate increase effective February 2015.
Taxes Other Than Income
Taxes other than income for the year ended December 31, 2016 compared to the same period in 2015 increased primarily due to higher
property taxes in Maryland related to higher property assessments and rate increases. Taxes other than income for the year ended December 31,
2015 compared to the same period in 2014 increased primarily due to higher property taxes related to an increase in assets.
Gain on Sales of Assets
Gain on Sale of Assets for the year ended December 31, 2016 compared to the same period in 2015 increased primarily due to gains recorded
in 2016 at DPL associated with the sale of land held as non-utility property.
Interest Expense, Net
Interest expense, net for the year ended December 31, 2016 compared to the same period in 2015 remained constant. Interest expense, net
for the year ended December 31, 2015 compared to the same period in 2014 increased primarily due to higher long-term debt interest expense.
Other, Net
Other, net for the year ended December 31, 2016, compared to the same period in 2015 increased primarily due to higher income from
AFUDC equity. Other, net for the year ended December 31, 2015, compared to the same period in 2014 remained constant.
Effective Income Tax Rate
DPL’s effective income tax rates for the years ended December 31, 2016, 2015, and 2014 were 169.2%, 39.2%, and 38.5%, respectively. See
Note 15—Income Taxes of the Combined Notes to Consolidated Financial Statements for additional information regarding the components of the
change in effective income tax rates As a result of the merger, DPL recorded an after-tax charge of $23 million during the year ended December 31,
2016 as a result of the assessment and remeasurement of certain federal and state uncertain tax positions.
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DPL Electric Operating Statistics and Revenue Detail
Retail Deliveries to Customers (in GWhs)
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
Total
Electric Revenue
Retail Sales (a)
Residential
Small commercial & industrial
Large commercial & industrial
Public authorities & electric railroads
Total retail
Other revenue (b)
Total electric revenue (c)
2016
2015
5,181
2,290
4,623
46
12,140
5,337
2,311
4,781
45
12,474
%
Change
2016 vs.
2015
Weather-
Normal
%
Change
%
Change
2015 vs.
2014
Weather-
Normal
%
Change
2014
(2.9)%
(0.9)%
(3.3)%
2.2%
(2.7)%
1.0%
0.7%
1.0%
— %
0.9%
5,188
2,147
5,030
47
12,412
2.9%
7.6%
(5.0)%
(4.3)%
0.5%
0.9%
0.5%
0.5%
— %
0.7%
As of December 31,
2015
2016
456,181
60,173
1,411
643
518,408
453,145
59,714
1,410
643
514,912
2014
448,615
39,246
21,388
642
509,891
2016
2015
$ 668
187
98
13
966
163
$1,129
$ 681
192
101
12
986
152
$1,138
%
Change
2016 vs.
2015
(1.9)%
(2.6)%
(3.0)%
8.3%
(2.0)%
7.2%
(0.8)%
%
Change
2015 vs.
2014
4.3%
20.0%
(6.5)%
— %
5.7%
(1.9)%
4.6%
2014
$ 653
160
108
12
933
155
$1,088
(a) Reflects delivery volumes and revenues from customers purchasing electricity directly from DPL and customers purchasing electricity from a competitive electric
generation supplier as all customers are assessed distribution charges. For customers purchasing electricity from DPL, revenue also reflects the cost of energy and
transmission.
(b) Other revenue includes transmission revenue from PJM and wholesale electric revenues.
(c)
Includes operating revenues from affiliates totaling $7 million, $6 million and $7 million for the years ended December 31, 2016, 2015 and 2014, respectively.
DPL Gas Operating Statistics and Revenue Detail
Retail Deliveries to Customers (in mmcf)
Retail Deliveries
Residential
Transportation & other
Total gas deliveries
2016
2015
%
Change
2016 vs.
2015
Weather
Normal
%
change
%
Change
2015 vs.
2014
Weather
Normal
%
change
2014
14,087
5,455
19,542
13,816
6,193
20,009
2.0%
(11.9)%
(2.3)%
(5.0)%
(1.4)%
(4.1)%
14,613
6,418
21,031
(5.5)%
(3.5)%
(4.9)%
(2.4)%
— %
(1.6)%
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Table of Contents
Number of Gas Customers
Residential
Commercial & industrial
Transportation & other
Total
Gas Revenue
Retail Sales (a)
Retail sales
Transportation & other (b)
Total gas revenues
As of December 31,
2015
2016
120,951
9,801
156
130,908
119,771
9,712
159
129,642
2014
117,880
9,615
157
127,652
2016
2015
%
Change
2016 vs.
2015
$127
21
$148
$143
21
$164
(11.2)%
— %
(9.8)%
%
Change
2015 vs.
2014
(13.3)%
(27.6)%
(15.5)%
2014
$165
29
$194
(a) Reflects delivery volumes and revenues from customers purchasing natural gas directly from DPL and customers purchasing natural gas from a competitive natural gas
supplier as all customers are assessed distribution charges. For customers purchasing natural gas from DPL, revenue also reflects the cost of natural gas.
(b) Transportation and other revenue includes off-system natural gas sales and the short-term release of interstate pipeline transportation and storage capacity not needed to
serve customers.
Results of Operations—ACE
Operating revenues
Purchased power expense
Revenues net of purchased power expense (a)
Other operating expenses
Operating and maintenance
Depreciation, amortization and accretion
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)
(Loss) income before income taxes
Income taxes
Net (loss) income attributable to common shareholder
2016
$1,257
651
606
428
165
7
600
1
7
(62)
9
(53)
(46)
(4)
(42)
$
2015
$1,295
708
587
271
175
7
453
—
134
(64)
3
(61)
73
33
40
$
Favorable
(unfavorable)
2016 vs. 2015
variance
$
$
(38)
57
19
(157)
10
—
(147)
1
(127)
2
6
8
(119)
37
(82)
2014
$1,210
664
546
250
155
4
409
—
137
(64)
3
(61)
76
30
46
$
Favorable
(unfavorable)
2015 vs. 2014
variance
$
$
85
(44)
41
(21)
(20)
(3)
(44)
—
(3)
—
—
—
(3)
(3)
(6)
(a) ACE evaluates its operating performance using the measure of revenue net of purchased power expense for electric sales. ACE believes Revenue net of purchased
power expense is a useful measurement of its performance because it provides
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information that can be used to evaluate its operational performance. ACE has included the analysis below as a complement to the financial information provided in
accordance with GAAP. However, Revenue net of purchased power expense 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.
Net Income Attributable to Common Shareholder
Year Ended December 31, 2016 Compared to Year Ended December 31, 2015. The decrease in net income attributable to common
shareholder was driven primarily by an increase in Operating and maintenance expense primarily due to merger-related costs.
Year Ended December 31, 2015 Compared to Year Ended December 31, 2014. The decrease in net income attributable to common
shareholder was driven primarily by an increase in Operating and maintenance expense primarily due to the implementation of a new customer
information system and higher storm restoration costs, partially offset by higher Operating revenues net of purchased power expense resulting from
an electric distribution base rate increase in 2014 in New Jersey.
Revenues Net of Purchased Power Expense
Operating revenues include revenue from the distribution and supply of electricity to ACE’s customers within its service territories at regulated
rates. Operating revenues also include transmission service revenue that ACE receives as a transmission owner from PJM at rates regulated by
FERC. Transmission rates are updated annually based on a FERC-approved formula methodology.
Electric revenues and purchased power expense are also affected by fluctuations in participation in the Customer Choice Program. All ACE
customers have the choice to purchase electricity from competitive electric generation suppliers. The customer’s choice of supplier does not impact
the volume of deliveries, but affects revenue collected from customers related to supplied energy service.
Retail deliveries purchased from competitive electric generation suppliers (as a percentage of kWh sales) for the years ended December 31,
2016, 2015, and 2014, consisted of the following:
Electric
2016
For the Years Ended December 31,
2015
47%
45%
2014
51%
Retail customers purchasing electric generation from competitive electric generation suppliers at December 31, 2016, 2015, and 2014
consisted of the following:
Electric
December 31, 2016
December 31, 2015
December 31, 2014
Number of
customers
94,562
% of total retail
customers
17%
Number of
customers
78,299
% of total retail
customers
14%
Number of
customers
86,780
% of total retail
customers
16%
The costs related to default electricity supply are included in Purchased power expense. Operating revenues also include revenue from
Transition Bond Charges that ACE receives, and pays to ACE Funding, to fund the principal and interest payments on Transition Bonds, revenue
from the resale in the PJM RTO market of energy and capacity purchased under contacts with unaffiliated NUGs, and revenue from transmission
enhancement credits.
Operating revenues also include work and services performed on behalf of customers, including other utilities, which is generally not subject to
price regulation. Work and services includes mutual assistance to other utilities, highway relocation, rentals of pole attachments, late payment fees
and collection fees.
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Purchased power expense consists of the cost of electricity purchased by ACE to fulfill its default electricity supply obligation and, as such, is
recoverable from customers in accordance with the terms of public service commission orders.
The changes in ACE’s operating revenues net of purchased power expense for the years ended December 31, 2016 and 2015 compared to
the same periods in 2015 and 2014, respectively, consisted of the following:
Weather
Volume
Pricing—distribution revenues
Regulatory required programs
Transmission revenues
Other
Increase in revenue net of purchased power expense
Increase
(Decrease)
2016 vs. 2015
(3)
$
1
14
(15)
23
(1)
19
$
Increase
(Decrease)
2015 vs. 2014
9
$
2
18
15
—
(3)
41
$
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, 2016 compared to the same
period in 2015, operating revenues net of purchased power and fuel expense was lower due to the impact of unfavorable winter weather conditions
in ACE’s service territory. During the year ended December 31, 2015 compared to the same period in 2014, operating revenues net of purchased
power and fuel expense was higher due to the impact of favorable spring and summer weather conditions in ACE’s service territory.
For retail customers of ACE, distribution revenues are not decoupled for the distribution of electricity by ACE, and thus are subject to variability
due to changes in customer consumption. Therefore, changes in customer usage (due to weather conditions, energy prices, energy savings
programs or other reasons) from period to period have a direct impact on reported distribution revenue for customers in ACE’s service territory.
Heating and cooling degree days are quantitative indices that reflect the demand for energy needed to heat or cool a home or business.
Normal weather is determined based on historical average heating and cooling degree days for a 20-year period in ACE’s service territory. The
changes in heating and cooling degree days in ACE’s service territory for the years ended December 31, 2016 and December 31, 2015 compared to
same periods in 2015 and 2014, respectively, and normal weather consisted of the following:
Heating and Cooling Degree-Days
Heating Degree-Days
Cooling Degree-Days
Heating and Cooling Degree-Days
Heating Degree-Days
Cooling Degree-Days
For the Years Ended
December 31,
2016
4,487
1,303
2015
4,671
1,259
Normal
4,768
1,093
% Change
2016 vs. 2015
2016 vs. Normal
(3.9)%
3.5%
(5.9)%
19.2%
For the Years Ended
December 31,
2015
4,671
1,259
2014
5,192
819
Normal
4,795
1,076
% Change
2015 vs. 2014
2015 vs. Normal
(10.0)%
53.7%
(2.6)%
17.0%
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Volume. The decrease in operating revenues net of purchased power and fuel expense related to delivery volume, exclusive of the effects of
weather, for the year ended December 31, 2016 compared to the same period in 2015, primarily reflects lower average customer usage, partially
offset by the impact of moderate economic and customer growth. The increase in operating revenues net of purchased power and fuel expense
related to delivery volume, exclusive of the effects of weather, for the year ended December 31, 2015 compared to the same period in 2014,
primarily reflects the impact of moderate economic and customer growth.
Pricing—Distribution Revenues. The increase in electric operating revenues net of purchased power expense as a result of pricing for the year
ended December 31, 2016 compared to the same period in 2015 was primarily due to the impact of the new electric distribution rates charged to
customers that became effective in August 2016. The increase in distribution revenue for the year ended December 31, 2015 compared to the same
period in 2014 was primarily due to the impact of the new electric distribution rates charged to customers that became effective September 2014.
See Note 3—Regulatory Matters of the Combined Notes to Consolidated Financial Statements for additional information.
Regulatory Required Programs. This represents the change in operating revenues collected under approved riders to recover costs incurred
for regulatory programs such as energy efficiency programs. 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. Refer
to the depreciation and amortization expense discussion below for additional information on included programs.
Transmission Revenues. Under a FERC approved formula, transmission revenue varies from year to year based upon fluctuations in the
underlying costs, investments being recovered and other billing determinants. Transmission revenue increased for the year ended December 31,
2016 compared to the same period in 2015 due to higher rates effective June 1, 2016 and June 1, 2015 related to increases in transmission plant
investment and operating expenses. Transmission revenue remained constant for the year ended December 31, 2015 compared to the same period
in 2014 due to higher rates effective June 1, 2015 and June 1, 2014 related to increases in transmission plant investment and operating expenses,
offset by the establishment of a reserve related to the FERC ROE challenges in 2015.
Operating and Maintenance Expense
Operating and maintenance expense—baseline
Operating and maintenance expense—regulatory required programs (a)
Total operating and maintenance expense
Year Ended
December 31,
2016
$424
4
$428
2015
$267
4
$271
Increase
(Decrease)
2016 vs. 2015
157
$
—
157
$
Year Ended
December 31,
2015
$267
4
$271
2014
$243
7
$250
Increase
(Decrease)
2015 vs. 2014
24
$
(3)
21
$
(a) Operating and maintenance expenses for regulatory required programs are costs for various legislative and/or regulatory programs that are recoverable from customers
on a full and current basis through approved regulated rates. An equal and offsetting amount has been reflected in Operating revenues.
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The changes in operating and maintenance expense for 2016 compared to 2015 and 2015 compared to 2014 consisted of the following:
Baseline
Labor, other benefits, contracting and materials
Pension and non-pension postretirement benefits expense
Storm-related costs
BSC and PHISCO allocations (a)
Uncollectible accounts expense
Merger commitments (b)
Other
Regulatory required programs
Purchased power administrative costs
Total increase
Increase
(Decrease)
2016 vs. 2015
Increase
(Decrease)
2015 vs. 2014
$
$
6
—
1
26
2
111
11
157
—
—
157
$
$
5
1
6
17
—
—
(5)
24
(3)
(3)
21
(a) Primarily related to merger severance and compensation costs for the year ended December 31, 2016 compared to the same period in 2015.
(b) Primarily related to merger-related commitments for customer rate credits and charitable contributions.
Depreciation, Amortization and Accretion Expense
The changes in depreciation, amortization and accretion expense for 2016 compared to 2015 and 2015 compared to 2014 consisted of the
following:
Depreciation expense (a)
Regulatory asset amortization (b)
Total (decrease) increase
Increase
(Decrease)
2016 vs. 2015
6
$
(16)
(10)
$
Increase
(Decrease)
2015 vs. 2014
4
$
16
20
$
(a) Depreciation expense increased due to ongoing capital expenditures.
(b) Regulatory asset amortization decreased for the year ended December 31, 2016 compared to the same period in 2015 primarily as a result of lower revenue due to a rate
decrease effective October 2015 for the ACE Market Transition charge tax. Regulatory asset amortization increased for the year ended December 31, 2015 compared to
the same period in 2014 as a result of higher revenue due to a rate increase effective October 2014 for the ACE Market Transition charge tax.
Taxes Other Than Income
Taxes other than income for the year ended December 31, 2016 compared to the same period in 2015, remained constant. Taxes other than
income for the year ended December 31, 2015 compared to the same period in 2014 increased primarily due to an increase in the New Jersey use
tax.
Interest Expense, Net
Interest expense, net remained relatively consistent for the year ended December 31, 2016, compared to the same period in 2015, and the
year ended December 31, 2015, compared to the same period in 2014.
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Gain on Sales of Assets
Gain on Sale of Assets for the year ended December 31, 2016 compared to the same period in 2015 increased primarily due to gains recorded
in 2016 at ACE associated with the sale of property.
Other, Net
Other, net for the year ended December 31, 2016 compared to the same period in 2015 increased primarily due to higher income from AFUDC
equity. Other, net for the year ended December 31, 2015 compared to the same period in 2014 remained relatively consistent.
Effective Income Tax Rate
ACE’s effective income tax rates for the years ended December 31, 2016, 2015, and 2014 were 8.7%, 45.2%, and 39.5%, respectively. See
Note 15—Income Taxes of the Combined Notes to Consolidated Financial Statements for additional information regarding the components of the
change in effective income tax rates As a result of the merger, ACE recorded an after-tax charge of $22 million during the year ended December 31,
2016 as a result of the assessment and remeasurement of certain federal and state uncertain tax positions.
ACE Electric Operating Statistics and Revenue Detail
Retail Deliveries to Customers (in GWhs)
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
Total
Electric Revenue
Retail Sales (a)
Residential
Small commercial & industrial
Large commercial & industrial
Public authorities & electric railroads
Total retail
Other revenue (b)
Total electric revenue (c)
2016
2015
% Change
2016 vs. 2015
Weather-
Normal %
Change
2014
% Change
2015 vs. 2014
Weather-
Normal %
Change
4,153
1,455
3,402
49
9,059
4,322
1,288
3,594
45
9,249
(3.9)%
13.0%
(5.3)%
8.9%
(2.1)%
1.1%
0.5%
0.7%
— %
0.8%
4,087
1,217
3,699
48
9,051
5.7%
5.8%
(2.8)%
(6.3)%
2.2%
2.7%
1.4%
1.4%
— %
2.0%
As of December 31,
2015
2016
484,240
61,008
3,763
610
549,621
482,000
60,745
3,871
529
547,145
2014
479,140
61,734
3,877
526
545,277
2016
2015
% Change
2016 vs. 2015
$ 690
175
213
12
1,090
205
$1,295
$ 664
183
201
13
1,061
196
$1,257
175
(3.8)%
4.6%
(5.6)%
8.3%
(2.7)%
(4.4)%
(2.9)%
2014
$ 582
152
190
12
936
274
$1,210
% Change
2015 vs. 2014
18.6%
15.1%
12.1%
— %
16.5%
(25.2)%
7.0%
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(a) Reflects delivery volumes and revenues from customers purchasing electricity directly from ACE and customers purchasing electricity from a competitive electric
generation supplier as all customers are assessed distribution charges. For customers purchasing electricity from ACE, revenue also reflects the cost of energy and
transmission.
(b) Other revenue includes transmission revenue from PJM and wholesale electric revenues.
(c)
Includes operating revenues from affiliates totaling $3 million, $4 million and $4 million for the years ended December 31, 2016, 2015 and 2014, respectively.
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, 2016. Exelon prior year activity is unadjusted for the effects of the 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, 2016, 2015 and 2014. Exelon’s and Generation’s activity presented below
includes the activity of CENG, from the integration date effective April 1, 2014. 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 $500 million in bilateral facilities with banks which have various expirations between
January 2017 and January 2019. 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 further discussion. 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 14—Debt and Credit Agreements of the Combined Notes to
Consolidated Financial Statements for further discussion 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
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making additional cash contributions to the NDT fund to ensure sufficient funds are available. See Note 16—Asset Retirement Obligations to 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 fund investments could appreciate in value. A shortfall
could require Exelon to post parental guarantees for Generation’s share of the obligations. However, the amount of any required guarantees will
ultimately depend on the decommissioning approach adopted at each site, the associated level of costs, and the decommissioning trust 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. When Generation files its biennial
decommissioning funding status report with the NRC on March 31, 2017, as compared to previous estimates prior to the reversal of the early
retirement decision, it is currently estimated that given the later commencement of decommissioning activities and a longer time period over which
the NDT fund investments can appreciate in value, Quad Cities will meet the NRC minimum funding requirements. It is currently estimated that
Clinton will fall below the NRC minimum funding requirements by only a small amount. As of December 31, 2016, TMI passes the NRC minimum
funding test based on its current license life. However, in the event of an early retirement of TMI, the most costly estimates could require parental
guarantees of up to $60 million.
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
greatly and could be reduced by alternate decommissioning scenarios and/or reimbursement of certain costs under the United States Department of
Energy reimbursement agreements or future litigation, across the three alternative decommissioning approaches available, if an early retirement
decision is made and TMI were to fail the exemption test, Generation could incur spent fuel management and site restoration costs over the next ten
years of up to $145 million, net of taxes.
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 Notes 3—Regulatory Matters and 24—Commitments and Contingencies of the Combined Notes to Consolidated Financial Statements for
further discussion 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,
2016, 2015 and 2014:
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
Net cash flows provided by operations
2016
$1,204
2015
$2,250
2016 vs. 2015
Variance
$
(1,046)
7,722
(397)
(674)
(275)
(66)
931
$8,445
5,630
(502)
97
(264)
58
347
$7,616
$
2,092
105
(771)
(11)
(124)
584
829
2014 (c)
1,820
5,884
(617)
(143)
(806)
38
(1,719)
$ 4,457
2015 vs. 2014
Variance
$
430
(254)
115
240
542
20
2,066
3,159
$
(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, and other non-cash charges. See Note 25—Supplemental Financial Information of the Combined Notes to
Consolidated Financial Statements for further detail 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.
(c) On April 1, 2014, Generation assumed operational control of CENG’s nuclear fleet. As a result, beginning on April 1, 2014, CENG’s revenues net of purchased power and
fuel expenses are included on a fully consolidated basis.
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,
management of the pension obligation and regulatory implications. On July 6, 2012, President Obama signed into law the Moving Ahead for
Progress in the Twenty-first Century Act, which contains a pension funding provision that results in lower pension contributions in the near term while
increasing the premiums pension plans pay to the Pension Benefit Guaranty Corporation. On August 8, 2014, this funding relief was extended for
five years. On November 2, 2015 the funding relief was extended for an additional three years and premiums pension plans pay to the Pension
Benefit Guaranty Corporation were further increased. The estimated impacts of the law are reflected in the projected pension contributions below.
Exelon expects to make qualified pension plan contributions of $310 million to its qualified pension plans in 2017, of which Generation,
ComEd, PECO, BGE and Pepco expect to contribute $127 million, $33 million, $23 million, $38 million and $60 million, respectively. Exelon’s and
Generation’s expected qualified pension plan contributions above include $21 million related to the legacy CENG plans that will be funded by CENG
as provided in an Employee Matters Agreement (EMA) between Exelon and CENG. Exelon’s non-qualified pension plans are not funded. Exelon
expects to make non-qualified pension plan benefit payments of $23 million in 2017, of which Generation, ComEd, PECO, BGE and Pepco will make
payments of $6 million, $1 million, $1 million, $2 million and $1 million, respectively. See Note 17—Retirement Benefits of the Combined Notes to
Consolidated Financial Statements for the Registrants’ 2016 and 2015 pension contributions.
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To the extent interest rates decline significantly or the pension plans do not earn the expected asset return rates, annual pension contribution
requirements in future years could increase. Additionally, expected contributions could change if Exelon changes its pension or OPEB funding
strategy.
Unlike qualified pension plans, other postretirement benefit plans are not subject to statutory minimum contribution requirements and certain
plans are not funded. OPEB funding generally follows accounting cost; however, Exelon’s management has historically considered several factors in
determining the level of contributions to its funded other postretirement benefit plans, including liabilities management, levels of benefit claims paid
and regulatory implications (amounts deemed prudent to meet regulator expectations and best assure continued recovery). Exelon expects to make
other postretirement benefit plan contributions, including benefit payments related to unfunded plans, of approximately $44 million in 2017, of which
Generation, ComEd, BGE and Pepco expect to contribute $12 million, $2 million, $16 million and $10 million, respectively. See Note 17—Retirement
Benefits of the Combined Notes to Consolidated Financial Statements for the Registrants’ 2016 and 2015 other postretirement benefit contributions.
See the “Contractual Obligations” section for management’s estimated future pension and other postretirement benefits contributions.
Tax Matters
The Registrants’ future cash flows from operating activities may be affected by the following tax matters:
•
•
•
In order to appeal the Tax Court’s like-kind exchange decision, Exelon is required to pay the tax, penalty and interest at the time Exelon
files its appeal (expected in the second quarter of 2017). While the final calculation of tax, penalty and interest has not yet been finalized
by the IRS, Exelon estimates that a payment of approximately $1.4 billion related to the like-kind exchange will be due, including
$300 million from ComEd, in the second quarter of 2017. While Exelon will receive a tax benefit of approximately $400 million associated
with the deduction for the interest, Exelon currently expects to have a net operating loss carryforward and thus does not expect to realize
the cash benefit until 2018. Exelon’s total estimated cash outflow for the like-kind exchange is $1.0 billion, of which approximately
$300 million would be attributable to ComEd after giving consideration to Exelon’s agreement to hold ComEd harmless from any
unfavorable impacts of the after-tax interest and penalty amounts on ComEd’s equity. ComEd will fund the $300 million with a combination
of debt and equity in a manner to maintain its current capital structure. Upon a final appellate decision, which could take up to several
years, Exelon expects to receive $80 million related to final interest computations.
Of the above amounts payable, Exelon deposited with the IRS approximately $1.25 billion in October of 2016. The remaining amount will
be paid in the second quarter of 2017 at the time Exelon files its appeal of the Tax Court decision. Exelon funded the $1.25 billion deposit
with a combination of cash on hand and short-term borrowings. The deposit is reflected as a current asset and the related liabilities for the
tax, penalty, and interest are included on Exelon’s balance sheet as current obligations.
In April of 2016, Exelon received tax refunds of approximately $460 million related to IRS positions settled in prior tax years. Of this
amount, approximately $195 million of the refund is attributable to Generation and the remaining $265 million is attributable to ComEd.
State and local governments continue to face increasing financial challenges, which may increase the risk of additional income tax levies,
property taxes and other taxes or the imposition, extension or permanence of temporary tax levies.
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Cash flows provided by operations for the year ended December 31, 2016, 2015 and 2014 by Registrant were as follows:
Exelon (a)
Generation (a)
ComEd
PECO
BGE
Pepco
DPL
ACE
PHI
2016
$8,445
4,444
2,505
829
945
651
310
385
2015
$7,616
4,199
1,896
770
782
373
266
256
2014
$4,457
1,826
1,326
712
740
386
268
259
Successor
March 24,
2016 to
December 31,
2016
January 1,
2016 to
March 23,
2016
Predecessor
For the Year
Ended
December 31,
2015
For the Year
Ended
December 31,
2014
$
888
$
264 $
939 $
854
(a) On April 1, 2014, Generation assumed operational control of CENG’s nuclear fleet. As a result, beginning on April 1, 2014, CENG’s revenues net of purchased power and
fuel expenses are included on a fully consolidated basis.
Changes in Registrants’ cash flows from operations were generally consistent with changes in each Registrant’s respective results of
operations, as adjusted by changes in working capital in the normal course of business, except as discussed below. In addition, significant operating
cash flow impacts for the Registrants for 2016, 2015 and 2014 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 markets. During 2016, 2015 and 2014, Generation had net collections/(payments) of
counterparty cash collateral of $923 million, $407 million and $(1,748) million, respectively, primarily due to market conditions that resulted
in changes to Generation’s net mark-to-market position, as well as Exelon’s decision to post more cash collateral in 2014 compared to
using letters of credit in 2015 to support the PHI merger financing.
•
During 2016, 2015 and 2014, Generation had net (payments)/collections of approximately $(66) million, $58 million, and $38 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.
ComEd
•
During 2016 and 2015, ComEd received a return of approximately $7 million of cash collateral from PJM and posted $31 million of cash
collateral to PJM, respectively. During 2014, ComEd posted no cash collateral to PJM. During 2016, ComEd’s collateral posted with PJM
has decreased due to lower PJM billings. During 2015 ComEd’s collateral posted with PJM has increased primarily due to higher RPM
credit requirements and higher PJM billings resulting from increased load being served by ComEd as a result of City of Chicago customers
switching back to ComEd.
For further discussion regarding changes in non-cash operating activities, please refer to Note 25—Supplemental Financial Information of the
Combined Notes to the Financial Statements.
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Cash Flows from Investing Activities
Cash flows used in investing activities for the year ended December 31, 2016, 2015, and 2014 by Registrant were as follows:
Exelon (a)
Generation (a)
ComEd
PECO
BGE
Pepco
DPL
ACE
2016
$ (15,503)
(3,851)
(2,685)
(798)
(910)
(647)
(336)
(309)
2015
$(7,822)
(4,069)
(2,362)
(588)
(675)
(477)
(345)
(306)
2014
$(4,599)
(1,767)
(1,655)
(649)
(622)
(560)
(358)
(224)
(a) On April 1, 2014, Generation assumed operational control of CENG’s nuclear fleet. As a result, beginning on April 1, 2014, CENG’s revenues net of purchased power and
fuel expenses are included on a fully consolidated basis.
PHI
Successor
March 24,
2016 to
December 31,
2016
January 1,
2016 to
March 23,
2016
Predecessor
For the Year
Ended
December 31,
2015
For the Year
Ended
December 31,
2014
$
(1,030)
$
(343) $
(1,161) $
(1,226)
Significant investing cash flow impacts for the Registrants for 2016, 2015 and 2014 were as follows:
Exelon
•
•
•
During 2016, Exelon had expenditures of $6.6 billion, $235 million and $58 million relating to the acquisitions of PHI, ConEdison Solutions
and the pending acquisition of the FitzPatrick facility, respectively.
During 2016 and 2014, Exelon had proceeds of $360 million and $335 million as a result of early termination of direct financing leases.
During 2014, Exelon had proceeds of $1.7 billion from the sale of certain long lived assets in order to finance a portion of the merger with
PHI.
Generation
•
•
During 2016, Generation had expenditures of, $235 million and $58 million relating to the acquisitions of ConEdison Solutions and the
pending acquisition of the FitzPatrick facility, respectively.
During 2014, Generation had proceeds of $1.7 billion from the sale of certain long lived assets in order to finance a portion of the merger
with PHI.
Capital Expenditure Spending
Generation
Generation has entered into several agreements to acquire equity interests in privately held development stage entities which develop energy-
related technology. The agreements contain a series of scheduled investment commitments, including in-kind services contributions. There are
approximately $39 million of anticipated expenditures remaining through 2018 to fund anticipated planned capital and operating needs of the
associated companies. See Note 24—Commitments and Contingencies of the Combined Notes to Consolidated Financial Statements for further
details of Generation’s equity interests.
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Capital expenditures by Registrant for the year ended December 31, 2016, 2015, and 2014 and projected amounts for 2017 are as follows:
Exelon (b)(d)
Generation (b)
ComEd (c)
PECO
BGE
Pepco
DPL
ACE
PHI (e)
Projected
2017 (a)
$ 8,250
2,650
2,200
775
925
625
375
300
2016
$8,553
3,078
2,734
686
934
586
349
311
2015
$7,624
3,841
2,398
601
719
544
352
300
2014
$6,077
3,012
1,689
661
620
567
352
225
Successor
March 24,
2016 to
December 31,
2016
$
1,008
Projected
2017 (a)
$ 1,375
January 1,
2016 to
March 23,
2016
Predecessor
For the Year
Ended
December 31,
2015
For the Year
Ended
December 31,
2014
$
273
$
1,230
$
1,223
(a) Total projected capital expenditures do not include adjustments for non-cash activity.
(b) On April 1, 2014, Generation assumed operational control of CENG’s nuclear fleet. As a result, beginning on April 1, 2014, CENG’s revenues net of purchased power and
fuel expenses are included on a fully consolidated basis.
(c) The capital expenditures and 2017 projections include $281 million of expected incremental spending pursuant to EIMA, ComEd has committed to invest approximately
$2.6 billion over a ten year period to modernize and storm-harden its distribution system and to implement smart grid technology.
Includes corporate operations, BSC, and PHISCO rounded to the nearest $25 million.
Includes PHISCO rounded to the nearest $25 million.
(d)
(e)
Projected capital expenditures and other investments are subject to periodic review and revision to reflect changes in economic conditions and
other factors.
Generation
Approximately 35% and 23% of the projected 2017 capital expenditures at Generation are for the acquisition of nuclear fuel and the
construction of new natural gas plants, 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 they will fund
capital expenditures with internally generated funds and borrowings.
ComEd, PECO, BGE, Pepco, DPL and ACE
Approximately 89% of the projected 2017 capital expenditures at ComEd and 100% of the projected 2017 capital expenditures at PECO, BGE,
Pepco, DPL, and ACE are for continuing projects to maintain and improve operations, including enhancing reliability and adding capacity to the
transmission and distribution systems such as ComEd’s reliability related investments required under EIMA, and the Utility Registrants’ construction
commitments under PJM’s RTEP. In addition to the capital expenditure for continuing projects, ComEd’s total expenditures include smart grid/smart
meter technology required under EIMA.
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
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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, PECO and BGE 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, PECO’s and BGE’s forecasted 2017 capital expenditures above reflect capital spending for remediation
to be completed through 2018. Pepco, DPL and ACE have substantially completed their assessments and thus do not expect significant capital
expenditures related to this guidance in 2017.
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, including ComEd’s capital expenditures associated with EIMA as further discussed in Note 3—
Regulatory Matters of the Combined Notes to Consolidated Financial Statements.
Cash Flows from Financing Activities
Cash flows provided by (used in) financing activities for the year ended December 31, 2016, 2015, and 2014 by Registrant were as follows:
Exelon (a)
Generation (a)
ComEd
PECO
BGE
Pepco
DPL
ACE
2016
$1,191
(734)
169
(263)
(21)
—
67
22
2015
$4,830
(479)
467
83
(162)
103
80
51
2014
$ 411
(537)
359
(250)
(85)
171
92
(36)
(a) On April 1, 2014, Generation assumed operational control of CENG’s nuclear fleet. As a result, beginning on April 1, 2014, CENG’s revenues net of purchased power and
fuel expenses are included on a fully consolidated basis.
PHI
Successor
March 24,
2016 to
December 31,
2016
January 1,
2016 to
March 23,
2016
Predecessor
For the Year
Ended
December 31,
2015
For the Year
Ended
December 31,
2014
$
(7)
$
372 $
233 $
363
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Debt
See Note 14—Debt and Credit Agreements of the Combined Notes to Consolidated Financial Statements for further details of the Registrants’
debt issuances and retirements. Debt activity for 2016, 2015 and 2014 by Registrant was as follows:
During the year ended December 31, 2016, the following long term debt was issued:
Company
Exelon
Corporate
Exelon
Corporate
Exelon
Corporate
Senior Unsecured Notes
Type
Interest Rate
2.45%
Maturity
April 15, 2021
Amount
300
$
Senior Unsecured Notes
3.40%
April 15, 2026
$
750
Senior Unsecured Notes
4.45%
April 15, 2046
$
750
Generation
Renewable Power Generation
Nonrecourse Debt (a)
4.11%
March 31, 2035
$
150
Generation
Albany Green Energy Project
Financing (b)
LIBOR +
1.25%
November 17,
2017
Generation
Energy Efficiency Project Financing (b)
3.17%
Generation
Energy Efficiency Project Financing (b)
3.90%
December 31,
2017
January 31,
2018
Generation
Energy Efficiency Project Financing (b)
3.52%
April 30, 2018
Generation
SolGen Nonrecourse Debt (a)
3.93%
Generation
Energy Efficiency Project Financing (b)
3.46%
September 30,
2036
October 1,
2018
184
$
$
$
$
$
$
98
16
19
14
Use of Proceeds
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
Funding to install energy
conservation measures or the
Marine Corps Logistics Base
project
Table of Contents
Company
Generation
Type
Energy Efficiency Project Financing
(b)
Interest Rate
2.61%
Maturity
September 30,
2018
Amount
4
$
ComEd
First Mortgage Bonds, Series 120
2.55%
June 15, 2026
$ 500
ComEd
First Mortgage Bonds, Series 121
3.65%
June 15, 2046
$ 700
PECO
First Mortgage Bonds
BGE
Notes
BGE
Notes
1.70%
2.40%
3.50%
September 15,
2021
August 15,
2026
$ 300
$ 350
August 15,
2046
$ 500
Pepco
Energy Efficiency Project Financing
(b)
3.30%
December 15,
2017
$
4
DPL
First Mortgage Bonds
4.15%
May 15, 2045
$ 175
Use of Proceeds
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
Refinance maturing mortgage
bonds
Redeem the $190M of
outstanding preference shares
and for general corporate
purposes
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 general corporate purposes
(a) See Note 14—Debt and Credit Agreements of the Combined Notes to Consolidated Financial Statements for discussion 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.
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During the year ended December 31, 2015, the following long term debt was issued:
Company
Exelon
Corporate
Exelon
Corporate
Exelon
Corporate
Exelon
Corporate
Exelon
Corporate
Exelon
Corporate
Senior Unsecured Notes
Type
Interest Rate
1.55%
Maturity
June 9, 2017
Amount
$
550
Senior Unsecured Notes
2.85%
June 15, 2020
$
900
Senior Unsecured Notes
3.95%
June 15, 2025
$ 1,250
Senior Unsecured Notes
4.95%
June 15, 2035
$
500
Senior Unsecured Notes
5.10%
June 15, 2045
$ 1,000
Use of Proceeds
Finance a portion of the pending
merger with PHI and related costs and
expenses, and for general corporate
purposes
Finance a portion of the pending
merger with PHI and related costs and
expenses, and for general corporate
purposes
Finance a portion of the pending
merger with PHI and related costs and
expenses, and for general corporate
purposes
Finance a portion of the pending
merger with PHI and related costs and
expenses, and for general corporate
purposes
Finance a portion of the pending
merger with PHI and related costs and
expenses, and for general corporate
purposes
Long Term Software License Agreement
3.95%
May 1, 2024
Generation
Senior Unsecured Notes
2.95%
Generation
AVSR DOE Nonrecourse Debt
2.29 - 2.96%
January 15,
2020
January 5,
2037
Generation
Energy Efficiency Project Financing
3.71%
July 31, 2017
186
$
$
$
$
111
Procurement of software licenses
750
Fund the optional redemption of
Exelon’s $550 million, 4.550% Senior
Notes and for general corporate
purposes
39
Antelope Valley solar development
42
Funding to install energy conservation
measures in Coleman, Florida
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Company
Generation
Generation
Energy Efficiency Project Financing
Type
Tax Exempt Pollution Control Revenue
Bonds
Generation
Albany Green Energy Project Financing
Interest Rate
3.55%
Maturity
November 15,
2016
2.50 - 2.70%
2019 - 2020
LIBOR +
1.25%
November 17,
2017
Generation
Nuclear Fuel Purchase Contract
3.15%
September 30,
2020
ComEd
First Mortgage Bonds, Series 118
3.70%
March 1, 2045
$
$
$
$
$
Amount
19
Use of Proceeds
Funding to install energy conservation
measures in Frederick, Maryland
435
General corporate purposes
100
Albany Green Energy biomass
generation development
57
Procurement of uranium
400
Refinance maturing mortgage bonds,
repay a portion of ComEd’s
outstanding commercial paper
obligations and for general corporate
purposes
Repay a portion of ComEd’s
outstanding commercial paper
obligations and for general corporate
purposes
ComEd
First Mortgage Bonds, Series 119
4.35%
November 15,
2045
$
450
PECO
First and Refunding Mortgage Bonds
3.15%
Pepco
First Mortgage Bonds
4.15%
October 15,
2025
March 15,
2043
$
$
350
General corporate purposes
200
Repay outstanding commercial paper
obligations and general corporate
purposes
DPL
First Mortgage Bonds
4.15%
May 15, 2045
$
200
ACE
First Mortgage Bonds
3.50%
December 1,
2025
$
150
Repay outstanding commercial paper
obligations and general corporate
purposes
Repay outstanding commercial paper
obligations and general corporate
purposes
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During the year ended December 31, 2014, the following long term debt was issued:
Company
Exelon
Junior Subordinated Notes
Type
Interest
Rate
2.50%
Maturity
June 1,
2024
Amount
$ 1,150
Use of Proceeds
Finance a portion of the pending
merger with PHI and for general
corporate purposes
Generation
Nuclear Fuel Purchase Contract
3.25 - 3.35%
Generation
ExGen Renewables I Nonrecourse
Debt
Generation
ExGen Texas Power Nonrecourse Debt
Generation
Energy Efficiency Project Financing
LIBOR +
4.25%
LIBOR +
4.75%
4.12%
Generation
AVSR DOE Nonrecourse Debt
3.06 - 3.14%
ComEd
First Mortgage Bonds, Series 115
ComEd
First Mortgage Bonds, Series 116
ComEd
First Mortgage Bonds, Series 117
2.15%
4.70%
3.10%
PECO
First and Refunding Mortgage Bonds
4.15%
PHI (a)
Energy Efficiency Project Financing
4.68%
June 30,
2018
February 6,
2021
September 18,
2021
December 31,
2015
January 5,
2037
January 15,
2019
January 15,
2044
November 1,
2024
October 1,
2044
February 10,
2015
$
$
$
$
$
$
$
$
$
$
Pepco
First Mortgage Bonds
3.60%
March 15,
2024
$
400
188
70
Procurement of uranium
300
General corporate purposes
675
General corporate purposes
12
Funding to install energy
conservation measures in
Washington, DC
126
Antelope Valley solar development
300
350
250
300
6
Refinance maturing mortgage bonds
and general corporate purposes
Refinance maturing mortgage bonds
and general corporate purposes
Repay commercial paper obligations
and general corporate purposes
Refinance existing mortgage bonds
and general corporate purposes
Funding to install energy
conservation measures for the
Natick Project
Repay $175M of 4.65% Senior
Notes, repay outstanding
commercial paper obligations, and
general corporate purposes
Table of Contents
Company
Pepco
Energy Efficiency Project Financing
Type
DPL
First Mortgage Bonds
ACE
First Mortgage Bonds
Interest
Rate
3.12%
Maturity
February 20,
2015
Amount
12
$
3.50%
November 15,
2023
$ 200
3.375%
September 1,
2024
$ 150
Use of Proceeds
Funding to install energy conservation
measures for the State Department
project
Repay outstanding commercial paper
obligations and general corporate
purposes
Repay $7M of 7.63% medium term
notes, repay commercial paper issued
to repay $100M term loan, and general
commercial purposes
(a) Represents Pepco Energy Services energy efficiency project financing. As of the date of the merger, PES financing was included with Generation.
During the year ended December 31, 2016, the following long term debt was retired and/or redeemed:
Company
Exelon Corporate
Long Term Software License Agreement
Type
Interest Rate
3.95%
Maturity
May 1, 2024
Amount
8
$
Exelon Corporate
Senior Notes
Generation
Generation
Generation
Generation
Generation
Generation
Generation
Generation
Generation
Generation
Generation
Generation
AVSR DOE Nonrecourse Debt (a)
Kennett Square Capital Lease
Continental Wind Nonrecourse Debt (a)
CEU Upstream Nonrecourse Debt (a)
4.95%
June 15, 2035
2.29% - 3.56%
January 5, 2037
$
$
7.83%
6.00%
September 20, 2020 $
February 28, 2033
1mL + 2.25%
January 14, 2019
$
$
ExGen Texas Power Nonrecourse Debt (a)
5.00%
September 18, 2021 $
Sacramento Solar Nonrecourse Debt (a)
1mL + 2.25% December 31, 2030 $
Clean Horizons Nonrecourse Debt (a)
1mL + 2.25%
September 7, 2030
ExGen Renewables Nonrecourse Debt (a)
3mL + 4.25%
February 6, 2021
PES—PGOV Notes Payable
6.70 - 7.46%
2017 - 2018
NUKEM
NUKEM
Renewable Power Generation Nonrecourse Debt (a)
189
3.35%
3.25%
4.11%
June 30, 2018
July 1, 2018
March 31, 2035
$
$
$
$
$
$
1
22
4
29
46
7
33
32
24
1
12
10
9
Table of Contents
Company
Generation
ComEd
ComEd
PECO
BGE
BGE
BGE
BGE
PHI
DPL
ACE
ACE
ACE
Type
SolGen Nonrecourse Debt (a)
First Mortgage Bonds, Series 104
First Mortgage Bonds, Series 111
Interest Rate
3.93%
Maturity
September 30, 2036
Amount
2
$
5.95%
August 15, 2016
$ 415
1.95%
August 1, 2016
$ 250
First and Refunding Mortgage Bonds
1.20%
October 15, 2016
$ 300
Rate Stabilization Bonds
Rate Stabilization Bonds
Notes
Securitization Bonds
Senior Unsecured Notes
First Mortgage Bonds
Transition Bonds
Transition Bonds
First Mortgage Bonds
5.72%
5.82%
April 1, 2016
April 1, 2017
$
$
1
38
5.90%
October 1, 2016
$ 300
5.82%
April 1, 2017
$
40
5.90%
December 12, 2016
$ 190
5.22%
December 30, 2016
$ 100
5.05%
October 20, 2020
5.55%
October 20, 2023
7.68%
August 23, 2016
$
$
$
12
34
2
(a) See Note 14—Debt and Credit Agreements of the Combined Notes to Consolidated Financial Statements for discussion of nonrecourse debt.
During the year ended December 31, 2015, the following long term debt was retired and/or redeemed:
Company
Exelon Corporate
Senior Unsecured Notes
Type
Exelon Corporate
Senior Notes
Exelon Corporate
Senior Unsecured Notes
Exelon Corporate
Senior Unsecured Notes
Exelon Corporate
Senior Unsecured Notes
Exelon Corporate
Long Term Software License Agreement
Senior Unsecured Notes
Interest Rate
4.55%
4.90%
3.95%
4.95%
5.10%
3.95%
4.55%
Maturity
June 15, 2015
June 15, 2015
June 15, 2025
June 15, 2035
June 15, 2045
May 1, 2024
June 15, 2015
Generation
Generation
Generation
Generation
Generation
Generation
Generation
Generation
CEU Upstream Nonrecourse Debt
LIBOR + 2.25%
January 14, 2019
AVSR DOE Nonrecourse Debt
Kennett Square Capital Lease
Continental Wind Nonrecourse Debt
2.29% - 3.56%
January 5, 2037
7.83%
6.00%
September 20, 2020 $
February 28, 2033
ExGen Texas Power Nonrecourse Debt
LIBOR + 4.75%
September 8, 2021
ExGen Renewables I Nonrecourse Debt
LIBOR + 4.25%
February 6, 2021
Constellation Solar Horizons Nonrecourse Debt
2.56%
September 7, 2030
190
Amount
550
$
$
$
$
$
$
$
$
$
$
$
$
$
800
443
167
259
1
550
9
23
3
20
5
24
2
Table of Contents
Company
Generation
Generation
ComEd
BGE
PHI
PHI (a)
PHI (a)
PHI (a)
PHI (a)
Pepco
DPL
ACE
ACE
ACE
Sacramento PV Energy Nonrecourse Debt
Type
Interest Rate
2.58%
Maturity
December 31, 2030
Amount
2
$
Energy Efficiency Project
First Mortgage Bonds, Series 101
Rate Stabilization Bonds
Senior Unsecured Notes
Energy Efficiency Project Financing
Energy Efficiency Project Financing
Energy Efficiency Project Financing
PES-PGOV Notes Payable
3.55%
November 15, 2016
$
19
4.70%
5.72%
2.70%
April 15, 2015
April 1, 2016
$ 260
$
75
October 1, 2015
$ 250
4.68%
February 10, 2015
8.87%
7.61%
June 1, 2021
August 1, 2015
6.70 - 7.46%
2017-2018
Energy Efficiency Project Financing
3.12%
February 20, 2015
Senior Unsecured Notes
Secured Medium-Term Notes Series C
5.00%
7.68%
June 1, 2015
$ 100
August 24, 2015
Transition Bonds
Transition Bonds
5.05%
October 20, 2020
5.55%
October 20, 2023
(a) Represents Pepco Energy Services energy efficiency project financing. As of the date of the merger, PES financing was included with Generation.
During the year ended December 31, 2014, the following long term debt was retired and/or redeemed:
Company
Generation
Senior Unsecured Notes
Type
Generation
Pollution Control Notes
Generation
Continental Wind Nonrecourse Debt
Generation
Kennett Square Capital Lease
Interest Rate
5.35%
Maturity
January 15, 2014
Amount
500
$
4.10%
6.00%
7.83%
July 1, 2014
February 28, 2033
$
$
September 20, 2020 $
Generation
ExGen Renewables I Nonrecourse Debt
LIBOR + 4.25%
February 6, 2021
$
Generation
ExGen Texas Power Nonrecourse Debt
LIBOR + 4.75%
September 18, 2021 $
Generation
AVSR DOE Nonrecourse Debt
2.33% - 3.55%
January 5, 2037
$
Generation
Clean Horizons Solar Nonrecourse Debt
Generation
Sacramento Solar Nonrecourse Debt
Generation
Energy Efficiency Project Financing
ComEd
ComEd
PECO
First Mortgage Bonds, Series 110
Pollution Control Series 1994C
First and Refunding Mortgage Bonds
2.56%
2.56%
4.12%
1.63%
5.85%
5.00%
191
September 7, 2030
$
December 31, 2030
$
December 31, 2015
$
12
January 15, 2014
January 15, 2014
October 1, 2014
$
$
$
600
17
250
$
$
$
$
$
7
5
1
1
12
$
$
$
15
12
32
20
20
3
18
2
15
2
2
Table of Contents
Company
BGE
BGE
PHI (a)
Pepco
DPL
ACE
ACE
ACE
ACE
ACE
Type
Interest Rate
Maturity
Amount
Rate Stabilization Bonds
Rate Stabilization Bonds
PES-PGOV Notes Payable
Senior Notes
Senior Unsecured Notes
Term Loan
Variable Rate Demand Bonds
Transition Bonds
Transition Bonds
Secured Medium-Term Notes
5.72%
5.72%
April 1, 2017
October 1, 2014
6.70 - 7.46%
2017-2018
4.65%
5.00%
April 15, 2014
June 1, 2015
LIBOR + 0.75%
November 10, 2014
variable
5.05%
5.55%
7.63%
April 15, 2014
October 20, 2020
October 20, 2023
August 29, 2014
$
$
$
35
35
1
$ 175
$ 100
$ 100
$
$
$
$
18
11
30
7
(a) Represents Pepco Energy Services energy efficiency project financing. As of the date of the merger, PES debt was included with Generation.
From time to time and as market conditions warrant, the Registrants may engage in long-term debt retirements via tender offers, open market
repurchases or other viable options to reduce debt on their respective balance sheets.
Dividends
Cash dividend payments and distributions for the year ended December 31, 2016, 2015 and 2014 by Registrant were as follows:
Exelon (a)
Generation (a)
ComEd
PECO
BGE (b)
Pepco
DPL
ACE
PHI
2016
$1,166
922
369
277
187
136
54
63
2015
$1,105
2,474
299
279
171
146
92
12
2014
$1,486
1,066
307
320
13
86
100
26
Successor
March 24, 2016
to December 31,
2016
$
273
January 1, 2016
to March 23,
2016
Predecessor
For the Year
Ended
December 31,
2015
For the Year
Ended
December 31,
2014
$
—
$
275
$
272
(a) On April 1, 2014, Generation assumed operational control of CENG’s nuclear fleet. As a result, the 2016, 2015, and 2014 activity includes CENG on a fully consolidated
basis beginning April 1, 2014.
Includes dividends paid on BGE’s preference stock.
(b)
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Quarterly dividends declared by the Exelon Board of Directors during the year ended December 31, 2016 and for the first quarter of 2017 were
as follows:
Period
First Quarter 2016
Second Quarter 2016
Third Quarter 2016
Fourth Quarter 2016
First Quarter 2017
Declaration Date
January 26, 2016
April 26, 2016
July 26, 2016
October 25, 2016
January 31, 2017
Shareholder of Record
Date
February 12, 2016
May 13, 2016
August 15, 2016
November 15, 2016
February 15, 2017
Dividend Payable Date
March 10, 2016
June 10, 2016
September 9, 2016
December 9, 2016
March 10, 2017
Cash per Share (a)
0.310
$
0.318
$
0.318
$
0.318
$
0.3275
$
(a) Exelon’s Board of Directors has approved a dividend policy providing a raise of 2.5% each year for three years, beginning with the June 2016 dividend.
Short-Term Borrowings
Short-term borrowings incurred (repaid) during 2016, 2015 and 2014 by Registrant were as follows:
Exelon (a)
Generation (a)
ComEd
BGE
Pepco
DPL
ACE
PHI
2016
$(353)
620
(294)
(165)
(41)
(105)
(5)
2015
$ 80
—
(10)
90
(40)
(1)
(122)
2014
$122
17
120
(15)
(47)
(41)
7
Successor
March 24, 2016
to December 31,
2016
$
(515)
January 1, 2016
to March 23,
2016
Predecessor
For the Year
Ended
December 31,
2015
For the Year
Ended
December 31,
2014
$
(121)
$
34
$
183
(a) On April 1, 2014, Generation assumed operational control of CENG’s nuclear fleet. As a result, beginning on April 1, 2014, CENG’s revenues net of purchased power and
fuel expenses are included on a fully consolidated basis.
Retirement of Long-Term Debt to Financing Affiliates
There were no retirements of long-term debt to financing affiliates during 2016, 2015 and 2014 by the Registrants.
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Contributions from Parent/Member.
Contributions from Parent/Member (Exelon) during 2016, 2015 and 2014 by Registrant were as follows:
Generation
ComEd (a)(b)
PECO (b)
BGE (b)
Pepco (c)
DPL (c)
ACE (c)
PHI (b)
2016
$142
473
18
61
187
152
139
2015
$ 47
209
16
7
112
75
95
2014
$ 53
278
24
—
80
130
—
Successor
March 24, 2016
to December 31,
2016
$
1,251
January 1, 2016
to March 23,
2016
Predecessor
For the Year
Ended
December 31,
2015
For the Year
Ended
December 31,
2014
$
—
$
—
$
—
(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.
(b) Contribution paid by Exelon.
(c) Contribution paid by PHI.
Pursuant to the orders approving the 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, 2016, BGE no longer has any preferred stock
outstanding. See Note 22—Earnings Per Share of the Combined Notes to Consolidated Financial Statements for further details.
Other
For the year ended December 31, 2016, other financing activities primarily consists of debt issuance costs. See Note 14—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
$9.5 billion in aggregate total commitments of which $7.9 billion was available as of December 31, 2016, and of which no financial institution has
more than 7% of the aggregate commitments for Exelon, Generation, ComEd, PECO, BGE, Pepco, DPL and ACE. The Registrants had access to
the commercial paper market during 2016 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 further 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, 2016, it would have been required to provide incremental collateral of
$1.9 billion to meet collateral obligations for derivatives, non-derivatives, normal purchase normal sales contracts and applicable payables and
receivables, net of the contractual right of offset under master netting agreements, which is well within its current available credit facility capacities of
$4.2 billion.
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, 2016 and available credit facility capacity prior to any incremental collateral at
December 31, 2016:
ComEd
PECO
BGE
Pepco
DPL
ACE
PJM Credit
Policy
Collateral
19
$
2
2
—
3
—
Other Incremental
Collateral Required (a)
—
$
31
62
—
10
—
Available Credit Facility
Capacity Prior to Any
Incremental Collateral
$
998
598
600
300
300
299
(a) Represents incremental collateral related to natural gas procurement contracts.
Exelon Credit Facilities
Exelon, ComEd and BGE meet their short-term liquidity requirements primarily through the issuance of commercial paper. Generation and
PECO meet their short-term liquidity requirements primarily through the issuance of commercial paper and borrowings from the intercompany money
pool. PHI meets its short-term liquidity requirements primarily through the issuance of short-term notes and the Exelon intercompany money pool.
Pepco, DPL and ACE meet their short-term liquidity requirements primarily through the issuance of commercial paper and short-term notes. 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 14—Debt and Credit Agreements of the Combined Notes to Consolidated Financial Statements for discussion of the Registrants’
credit facilities and short term borrowing activity.
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Other Credit Matters
Capital Structure . At December 31, 2016, the capital structures of the Registrants consisted of the following:
Long-term debt
Long-term debt to affiliates (a)
Common equity
Member’s equity
Preference Stock
Commercial paper and notes payable
Exelon
Generation
ComEd
PECO
BGE
54%
1%
43%
— %
— %
2%
36%
4%
— %
57%
— %
3%
44%
1%
55%
— %
— %
—
42%
3%
55%
— %
— %
— %
42%
5%
52%
— %
—
1%
PHI
41%
— %
—
55%
— %
4%
Pepco
DPL
ACE
50%
— %
50%
—
— %
— %
50%
— %
50%
—
— %
— %
53%
— %
47%
—
— %
— %
(a)
Includes approximately $641 million, $205 million, $184 million and $252 million owed to unconsolidated affiliates of Exelon, ComEd, PECO and BGE respectively. These
special purpose entities were created for the sole purposes of issuing mandatorily redeemable trust preferred securities of ComEd, PECO and BGE. 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 13—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, 2016, are presented in the following tables:
Exelon Intercompany Money Pool
Contributed (borrowed)
Exelon Corporate
Generation
PECO
BSC
PHI Corporate (a)
PCI (a)
For the Year Ended
December 31, 2016
Maximum
Contributed
1,534
$
—
395
—
—
63
Maximum
Borrowed
—
$
1,292
—
387
53
—
(a) As a result of the merger, PHI Corporate and PCI began to participate in the Exelon Intercompany Money Pool effective March 24, 2016.
PHI Intercompany Money Pool
Contributed (borrowed)
PHI Corporate
Pepco
DPL
ACE
PHISCO
For the Year Ended
December 31, 2016
Maximum
Contributed
152
$
—
—
—
26
Maximum
Borrowed
—
$
—
—
—
152
As of
December 31,
2016
Contributed
(Borrowed)
$
88
(55)
131
(219)
—
55
As of
December 31,
2016
Contributed
(Borrowed)
$
—
—
—
—
—
Investments in Nuclear Decommissioning Trust 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 16—Asset Retirement
Obligations of the Combined Notes to Consolidated Financial Statements for further information regarding the trust funds, the NRC’s minimum
funding requirements and related liquidity ramifications.
Shelf Registration Statements. Exelon, Generation, ComEd, PECO, BGE, Pepco and DPL 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.
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Regulatory Authorizations. Generation, 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
Amount
ComEd (b)
PECO
BGE (c)
Pepco
DPL
ACE
Commission
FERC
FERC
FERC
Expiration Date
December 31, 2017 $
December 31, 2017
December 31, 2017
(in millions)
2,500
1,500
700
FERC
June 30, 2018
FERC
NJBPU
June 30, 2018
January 1, 2018
500
500
350
Commission
ICC
PAPUC
MDPSC
MDPSC /
DCPSC
MDPSC /
DPSC
NJBPU
Expiration Date
2019
$
December 31, 2018
N/A
September 25, 2017
December 31, 2017
December 31, 2017
Amount
(in millions)
2,383
1,600
—
550
125
300
(a) Generation currently has blanket financing authority it received from FERC in connection with its market-based rate authority.
(b) ComEd had $1,565 million available in long-term debt refinancing authority and $818 million available in new money long term debt financing authority from the ICC as of
December 31, 2016 and has an expiration date of June 1, 2019 and March 1, 2019, respectively.
In December 2016, BGE filed an application for $1 billion of long term financing authority with the MDPSC.
(c)
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. The
Federal Power Act declares it to be unlawful for any officer or director of any public utility “to participate in the making or paying of any dividends of
such public utility from any funds properly included in capital account.” In addition, under Illinois law, ComEd may not pay any dividend on its stock,
unless, among other things, its earnings and earned surplus are sufficient to declare and pay a dividend after provision is made for reasonable and
proper reserves, or unless ComEd has specific authorization from the ICC. BGE is subject to certain dividend restrictions established by the
MDPSC. First, BGE was prohibited from paying a dividend on its common shares through the end of 2014. Second, BGE is prohibited 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.
Finally, BGE must notify the MDPSC that it intends to declare a dividend on its common shares at least 30 days before such a dividend is paid.
There are no other limitations on BGE paying common stock dividends unless BGE elects to defer interest payments on the 6.20% Deferrable
Interest Subordinated Debentures due 2043, and any deferred interest remains unpaid. Pepco, DPL and ACE are subject to certain dividend
restrictions established by settlements approved in NJ, DE, MD and the DC. 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 Commissions and the Board 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. At December 31, 2016, Exelon had retained earnings of $12,030 million, including
Generation’s undistributed earnings of $2,275 million, ComEd’s retained earnings of $987 million consisting of retained earnings appropriated for
future dividends of $2,626 million partially offset by $1,639 million of unappropriated retained deficit, PECO’s retained earnings of $941 million and
BGE’s retained earnings $1,427 million. At December 31, 2016, Pepco had retained earnings of $991 million, DPL had retained earnings of
$562 million and ACE had retained earnings of $122 million. See Note 24—Commitments and Contingencies of the Combined Notes to
Consolidated Financial Statements for additional information regarding fund transfer restrictions.
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Contractual Obligations
The following tables summarize the Registrants’ future estimated cash payments as of December 31, 2016 under existing contractual
obligations, including payments due by period. See Note 24—Commitments and Contingencies of the Combined Notes to Consolidated Financial
Statements for information regarding the Registrants’ commercial and other commitments, representing commitments potentially triggered by future
events.
Exelon
Long-term debt (a)
Interest payments on long-term debt (b)
Liability and interest for uncertain tax positions (c)
Capital leases
Operating leases (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)
Construction commitments (i)
PJM regional transmission expansion commitments (j)
SNF obligation (k)
Pension minimum funding requirement (l)
Total contractual obligations
Total
$33,959
16,368
150
69
1,726
1,502
7,693
3,632
6
148
1,517
7,739
317
617
1,024
3,899
$80,366
Payment due within
2018-
2019
$ 2,751
2,680
—
38
302
626
2,165
1,357
3
80
213
1,292
41
301
—
1,073
$12,922
2017
$ 2,430
1,432
150
17
183
508
1,297
2,261
1
61
107
5,426
276
280
—
596
$15,025
2020-
2021
$ 5,705
2,361
—
6
273
148
1,501
14
2
7
225
517
—
36
—
899
$11,694
Due 2022
and beyond
23,073
$
9,895
—
8
968
220
2,730
—
—
—
972
504
—
—
1,024
1,331
40,725
$
(a)
(b)
Includes $648 million due after 2022 to ComEd, PECO and BGE financing trusts.
Interest payments are estimated based on final maturity dates of debt securities outstanding at December 31, 2016 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, 2016. Includes estimated interest payments due to
ComEd, PECO, BGE, PHI, Pepco, DPL and ACE financing trusts.
(c) While the final calculation of tax, penalties and interest has not yet been finalized by the IRS, Exelon estimates that a payment of approximately $1.4 billion related to the
like-kind exchange will be due in the second quarter of 2017. Exelon deposited with the IRS approximately $1.25 billion in October of 2016 and expects that the
approximately $150 million remaining will be paid in the second quarter of 2017.
(d) Excludes Generation’s contingent operating lease payments associated with contracted generation agreements. These amounts are included within purchase power
obligations. Includes estimated cash payments for service fees related to PECO’s meter reading operating lease.
(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, 2016, including those related to CENG. 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.
(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 maximum settlements with suppliers for renewable energy and RECs under the existing
contract terms. See Note 3—Regulatory Matters of Combined Notes to Consolidated Financial Statements for additional information.
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(h) Represents the future estimated value at December 31, 2016 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.
(i) Represents commitments for Generation’s ongoing investments in new natural gas and biomass generation construction. Amount includes $139 million of remaining
commitments related to the construction of new combined-cycle gas turbine units in Texas. Achievement of commercial operations related to this project is expected in
2017.
(j) Under their operating agreements with PJM, ComEd, PECO, BGE, Pepco, DPL and ACE are committed to the construction of transmission facilities to maintain system
reliability. These amounts represent ComEd, PECO, BGE, Pepco, DPL and ACE’s expected portion of the costs to pay for the completion of the required construction
projects. See Note 3—Regulatory Matters of Combined Notes to Consolidated Financial Statements for additional information.
(k) See Note 24—Commitments and Contingencies of the Combined Notes to Consolidated Financial Statements for further information regarding SNF obligations.
(l)
These amounts represent Exelon’s expected contributions to its qualified pension plans. The projected contributions reflect a funding strategy for the legacy Exelon, CEG
and CENG plans of contributing the greater of $250 million until the qualified plans are fully funded on an accumulated benefit obligation basis, and the minimum amounts
under ERISA to avoid benefit restrictions and at-risk status thereafter. The remaining qualified pension plans’ contributions are generally based on the estimated minimum
pension contributions required under ERISA and the Pension Protection Act of 2006, as well as contributions necessary to avoid benefit restrictions and at-risk status.
These amounts represent estimates that are based on assumptions that are subject to change. The minimum required contributions for years after 2022 are not included.
See Note 17—Retirement Benefits of the Combined Notes to Consolidated Financial Statements for further information regarding estimated future pension benefit
payments.
Generation
Long-term debt
Interest payments on long-term debt (a)
Capital leases
Operating leases (b)
Purchase power obligations (c)
Fuel purchase agreements (d)
Other purchase obligations (e)
Construction commitments (f)
SNF obligation (g)
Total contractual obligations
Total
$ 9,208
5,086
22
914
1,502
6,510
1,828
317
1,024
$26,411
Payment due within
2018-
2019
$ 710
752
11
105
626
1,825
296
41
—
$4,366
2017
$1,117
383
5
70
508
1,057
1,111
276
—
$4,527
2020-
2021
$2,800
574
6
95
148
1,296
115
—
—
$5,034
Due 2022
and beyond
4,581
$
3,377
—
644
220
2,332
306
—
1,024
12,484
$
(a)
Interest payments are estimated based on final maturity dates of debt securities outstanding at December 31, 2016 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, 2016.
(b) Excludes Generation’s contingent operating lease payments associated with contracted generation agreements. These amounts are included within purchase power
obligations.
(c) 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, 2016, including those related to CENG. 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.
(d) Represents commitments to purchase fuel supplies for nuclear and fossil generation.
(e) Represents the future estimated value at December 31, 2016 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) Represents commitments for Generation’s ongoing investments in new natural gas and biomass generation construction. Amount includes $139 million of remaining
commitments related to the construction of new combined-cycle gas turbine units in Texas. Achievement of commercial operations related to this project is expected in
2017.
(g) See Note 24—Commitments and Contingencies of the Combined Notes to Consolidated Financial Statements for further information regarding SNF obligations.
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ComEd
Long-term debt (a)
Interest payments on long-term debt (b)
Liability and interest for uncertain tax positions (c)
Capital leases
Operating leases
Electric supply procurement
Long-term renewable energy and REC commitments (d)
Other purchase obligations (e)
PJM regional transmission expansion commitments (f)
Total contractual obligations
Payment due within
2018-
2019
2017
2020-
2021
Total
$ 7,307 $ 425 $1,140 $ 850 $
4,400
300
8
29
733
1,375
830
97
283
300
—
11
461
80
692
64
473
—
—
12
272
156
102
33
421
—
—
6
—
167
32
—
$15,079 $2,316 $2,188 $1,476 $
Due 2022
and beyond
4,892
3,223
—
8
—
—
972
4
—
9,099
(a)
(b)
Includes $206 million due after 2022 to a ComEd financing trust.
Interest payments are estimated based on final maturity dates of debt securities outstanding at December 31, 2016 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, 2016. Includes estimated interest payments due to the
ComEd financing trust.
(c) While the final calculation of tax, penalties and interest has not yet been finalized by the IRS, Exelon estimates that a payment of approximately $1.4 billion related to the
like-kind exchange will be due, including $300 million from ComEd, in the second quarter of 2017.
(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 settlements with suppliers for renewable energy and RECs under the existing
contract terms. See Note 3—Regulatory Matters of Combined Notes to Consolidated Financial Statements for additional information.
(e) Represents the future estimated value at December 31, 2016 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. See Note 3—Regulatory Matters of Combined Notes to
Consolidated Financial Statements for additional information.
PECO
Long-term debt (a)
Interest payments on long-term debt (b)
Operating leases (c)
Fuel purchase agreements (d)
Electric supply procurement (d)
AEC purchase commitments (d)
Other purchase obligations (e)
PJM regional transmission expansion commitments (f)
Total contractual obligations
Total
$2,784
1,679
18
327
481
8
418
34
$5,749
Payment due within
2018-
2019
$ 500
190
7
144
84
4
126
17
$1,072
2017
$ —
120
3
99
397
2
216
14
$851
2020-
2021
$ 300
185
8
37
—
2
73
3
$ 608
Due 2022
and beyond
1,984
$
1,184
—
47
—
—
3
—
3,218
$
(a)
(b)
(c)
Includes $184 million due after 2022 to PECO financing trusts.
Interest payments are estimated based on final maturity dates of debt securities outstanding at December 31, 2016 and do not reflect anticipated future refinancing, early
redemptions or debt issuances.
Includes estimated cash payments for service fees related to PECO’s meter reading operating lease.
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(d) Represents commitments to purchase natural gas and related transportation, storage capacity and services, procure electric supply, and purchase AECs.
(e) Represents the future estimated value at December 31, 2016 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, 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. See Note 3—Regulatory Matters of Combined Notes to Consolidated
Financial Statements for additional information.
BGE
Long-term debt (a)
Interest payments on long-term debt (b)
Operating leases
Fuel purchase agreements (c)
Electric supply procurement (c)
Curtailment services commitments (c)
Other purchase obligations (d)
PJM regional transmission expansion commitments (e)
Total contractual obligations
Total
$2,599
2,247
199
599
1,228
63
851
226
$8,012
$
Payment due within
2018-
2019
$ —
235
68
139
470
31
132
99
$1,174
2017
41
118
32
114
758
30
633
113
$1,839
2020-
2021
$ 300
234
66
110
—
2
85
14
$ 811
Due 2022
and beyond
2,258
$
1,660
33
236
—
—
1
—
4,188
$
(a)
(b)
Includes $258 million due after 2022 to the BGE financing trusts.
Interest payments are estimated based on final maturity dates of debt securities outstanding at December 31, 2016 and do not reflect anticipated future refinancing, early
redemptions or debt issuances.
(c) Represents commitments to purchase natural gas and related transportation, storage capacity and services, procure electric supply, and curtailment services.
(d) Represents the future estimated value at December 31, 2016 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, 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. See Note 3—Regulatory Matters of the Combined Notes to Consolidated
Financial Statements.
PHI
Long-term debt
Interest payments on long-term debt (a)
Capital leases
Operating leases
Fuel purchase agreements (b)
Long-term renewable energy and REC commitments (b)
Electric supply procurement (b)
Curtailment services commitments (b)
Other purchase obligations (c)
PJM regional transmission expansion commitments (d)
Total contractual obligations
202
Payment due within
2018-
2019
2017
2020-
2021
Total
$ 5,157 $ 251 $ 403 $255 $
1,329
39
418
257
143
2,017
85
3,017
260
244
12
50
27
28
1,171
31
2,394
89
461
27
85
57
57
832
49
441
152
424
—
72
58
58
14
5
84
19
$12,722 $4,297 $2,564 $989 $
Due 2022
and beyond
4,248
200
—
211
115
—
—
—
98
—
4,872
Table of Contents
(a)
Interest payments are estimated based on final maturity dates of debt securities outstanding at December 31, 2016 and do not reflect anticipated future refinancing, early
redemptions or debt issuances.
(b) Represents commitments to purchase natural gas and related transportation, storage capacity and services, procure electric supply, and curtailment services.
(c) Represents the future estimated value at December 31, 2016 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.
(d) 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. See Note 3—Regulatory Matters of the Combined Notes to Consolidated
Financial Statements.
Pepco
Long-term debt
Interest payments on long-term debt (a)
Capital leases
Operating leases
Electric supply procurement (b)
Curtailment services commitments (b)
Other purchase obligations (c)
PJM regional transmission expansion commitments (d)
Total contractual obligations
Total
$2,381
695
39
32
838
36
1,345
104
$5,470
$
Payment due within
2018-
2019
$ 137
237
27
11
328
17
164
79
$1,000
2017
16
121
12
7
510
19
1,165
6
$1,856
2020-
2021
$
2
228
—
7
—
—
8
19
$264
Due 2022
and beyond
2,226
$
109
—
7
—
—
8
—
2,350
$
(a)
Interest payments are estimated based on final maturity dates of debt securities outstanding at December 31, 2016 and do not reflect anticipated future refinancing, early
redemptions or debt issuances.
(b) Represents commitments to purchase procure electric supply and curtailment services.
(c) Represents the future estimated value at December 31, 2016 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.
(d) Under its operating agreement with PJM, Pepco is committed to the construction of transmission facilities to maintain system reliability. These amounts represent Pepco’s
expected portion of the costs to pay for the completion of the required construction projects. See Note 3—Regulatory Matters of the Combined Notes to Consolidated
Financial Statements.
DPL
Long-term debt
Interest payments on long-term debt (a)
Operating leases
Fuel purchase agreements (b)
Long-term renewable energy and associated REC commitments (b)
Electric supply procurement (b)
Curtailment services commitments (b)
Other purchase obligations (c)
PJM regional transmission expansion commitments (d)
Total contractual obligations
203
Payment due within
Total
$1,348
291
110
257
143
627
40
897
63
$3,776
2017
$ 119
49
13
27
28
334
10
568
47
$1,195
2018-
2019
$ 16
98
24
57
57
279
26
175
16
$748
2020-
2021
$ —
96
19
58
58
14
4
69
—
$318
Due 2022
and beyond
1,213
$
48
54
115
—
—
—
85
—
1,515
$
Table of Contents
(a)
Interest payments are estimated based on final maturity dates of debt securities outstanding at December 31, 2016 and do not reflect anticipated future refinancing, early
redemptions or debt issuances.
(b) Represents commitments to purchase natural gas and related transportation, storage capacity and services, procure electric renewable energy and RECs, procure electric
supply, and curtailment services.
(c) Represents the future estimated value at December 31, 2016 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.
(d) 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. See Note 3—Regulatory Matters of the Combined Notes to Consolidated
Financial Statements.
ACE
Long-term debt
Interest payments on long-term debt (a)
Operating leases
Electric supply procurement (b)
Curtailment services commitments (b)
Other purchase obligations (c)
PJM regional transmission expansion commitments (d)
Total contractual obligations
Total
$1,162
259
54
552
9
514
93
$2,643
Payment due within
2018-
2019
$250
98
15
225
6
76
57
$727
2017
$ 35
60
8
327
2
432
36
$900
2020-
2021
$253
72
11
—
1
3
—
$340
Due 2022
and beyond
624
$
29
20
—
—
3
—
676
$
(a)
Interest payments are estimated based on final maturity dates of debt securities outstanding at December 31, 2016 and do not reflect anticipated future refinancing, early
redemptions or debt issuances.
(b) Represents commitments to procure electric supply and curtailment services.
(c) Represents the future estimated value at December 31, 2016 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.
(d) 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 3—Regulatory Matters of the Combined Notes to Consolidated
Financial Statements.
See Note 24—Commitments and Contingencies of the Combined Notes to Consolidated Financial Statements for discussion of the
Registrants’ other commitments potentially triggered by future events.
For additional information regarding:
•
•
•
•
•
commercial paper, see Note 14—Debt and Credit Agreements of the Combined Notes to Consolidated Financial Statements.
long-term debt, see Note 14—Debt and Credit Agreements of the Combined Notes to Consolidated Financial Statements.
liabilities related to uncertain tax positions, see Note 15—Income Taxes of the Combined Notes to Consolidated Financial Statements.
capital lease obligations, see Note 14—Debt and Credit Agreements of the Combined Notes to Consolidated Financial Statements.
operating leases and rate relief commitments, see Note 24—Commitments and Contingencies of the Combined Notes to Consolidated
Financial Statements.
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•
•
•
•
•
the nuclear decommissioning and SNF obligations, see Notes 16—Asset Retirement Obligations and 24—Commitments and
Contingencies of the Combined Notes to Consolidated Financial Statements.
regulatory commitments, see Note 3—Regulatory Matters of the Combined Notes to Consolidated Financial Statements.
variable interest entities, see Note 2—Variable Interest Entities of the Combined Notes to Consolidated Financial Statements.
nuclear insurance, see Note 24—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 amount of energy Exelon generates differs from
the amount of energy it has contracted to sell, Exelon has price risk from commodity price movements. Exelon seeks to mitigate its commodity price
risk through the sale and purchase of electricity, fossil fuel and other commodities.
Generation
Normal Operations and Hedging Activities. 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 price risk
caused by market fluctuations, Generation enters into non-derivative contracts as well as derivative contracts, including forwards, futures, swaps,
and options, with approved counterparties to hedge anticipated exposures. Generation believes these instruments represent economic hedges that
mitigate exposure to fluctuations in commodity prices. Generation expects the settlement of the majority of its economic hedges will occur during
2017 through 2019.
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 risk for Exelon’s
expected generation, typically on a ratable basis over a three-year period. As of December 31, 2016, the proportion of expected generation hedged
is 91%-94%, 56%-59% and 28%-31% for 2017, 2018 and 2019, 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
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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
the Utility Registrants 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 non-proprietary trading portfolio associated with a $5 reduction in the annual average
around-the-clock energy price based on December 31, 2016 market conditions and hedged position would be decreases in pre-tax net income of
approximately $65 million, $410 million and $685 million, respectively, for 2017, 2018 and 2019. Power price sensitivities are derived by adjusting
power price assumptions while keeping all other price inputs constant. Generation expects to actively manage its portfolio to mitigate market price
risk exposure for its unhedged position. Actual results could differ depending on the specific timing of, and markets affected by, price changes, as
well as future changes in Generation’s portfolio.
Proprietary Trading Activities. Generation also enters into certain energy-related derivatives for proprietary trading purposes. Proprietary
trading includes all contracts entered into with the intent of benefiting from shifts or changes in market prices as opposed to those entered into 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, including volume, stop loss and Value-at-Risk (VaR)
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, which included physical volumes of 6,179 GWh, 7,310 GWh, and 10,571 GWh for the
years ended December 31, 2016, 2015 and 2014 respectively, are a complement to Generation’s energy marketing portfolio, but represent a small
portion of Generation’s overall revenue from energy marketing activities. Proprietary trading portfolio activity for the year ended December 31, 2016,
resulted in pre-tax gains of $15 million due to net mark-to-market gains of $1 million and realized gains of $14 million. Generation uses a 95%
confidence interval, assuming standard normal distribution, one day holding period, and one-tailed statistical measure in calculating its VaR. The
daily VaR on proprietary trading activity averaged $0.2 million of exposure during the year. 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
purchase power and fuel expense for the year ended December 31, 2016 of $8,921 million.
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 39% of Generation’s uranium concentrate requirements from 2017 through 2021 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 results of operations, cash flows and financial positions.
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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. See Note 3—Regulatory Matters and Note 13—Derivative Financial Instruments of
the Combined Notes to Consolidated Financial Statements for additional information regarding energy procurement and derivatives. ComEd does
not enter into derivatives for speculative or proprietary trading purposes.
PECO
PECO has contracts to procure electric supply that were executed through the competitive procurement process outlined in its PAPUC-
approved DSP Programs, which are further discussed in Note 3—Regulatory Matters of the Combined Notes to Consolidated Financial Statements.
PECO has 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. Under the DSP
Programs, PECO is permitted to recover its electric supply procurement costs from retail customers with no mark-up.
PECO has also entered into 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 its long-term price risk in the natural gas market. PECO’s hedging
program for natural gas procurement has no direct impact on its financial position or results of operations as natural gas costs are fully recovered
from customers under the PGC.
PECO does not enter into derivatives for speculative or proprietary trading purposes. For additional information on these contracts, see Note
13—Derivative Financial Instruments of the Combined Notes to Consolidated Financial Statements.
BGE
BGE procures electric supply for default service customers through full requirements contracts pursuant to BGE’s MDPSC-approved SOS
program. BGE’s full requirements contracts that are considered derivatives 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. Under the SOS program, BGE is
permitted to recover its electricity procurement costs from retail customers, plus an administrative fee which includes a shareholder return
component and an incremental cost component. However, through December 2016, BGE provides all residential electric customers a credit for the
residential shareholder return component of the administrative charge.
BGE has also entered into natural gas contracts, which qualify for the normal purchases and normal sales scope exception, to hedge its price
risk in the natural gas market. The hedging program for natural gas procurement has no direct impact on BGE’s financial position. However, under
BGE’s market-based rates incentive 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 does not enter into derivatives for speculative or proprietary trading purposes. For additional information on these contracts, see Note 13
—Derivative Financial Instruments of the Combined Notes to Consolidated Financial Statements.
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Pepco
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 price risk related
to electric supply procurement is limited. Pepco locks in fixed prices for all of 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.
Pepco does not enter into derivatives for speculative or proprietary trading purposes. For additional information on these contracts, see Note
13—Derivative Financial Instruments of the Combined Notes to Consolidated Financial Statements.
DPL
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 costs. DPL
locks in fixed prices for all of its SOS requirements through full requirements contracts. DPL’s 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 a GCR mechanism approved by the DPSC. 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.
DPL does not enter into derivatives for speculative or proprietary trading purposes. See Note 13—Derivative Financial Instruments of the
Combined Notes to Consolidated Financial Statements for additional information regarding energy procurement and derivatives.
ACE
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 price risk related to electric supply procurement is limited. ACE locks in fixed prices for all of its BGS
requirements through full requirements contracts. 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.
ACE does not enter into derivatives for speculative or proprietary trading purposes. For additional information on these contracts, see Note 13
—Derivative Financial Instruments of the Combined Notes to Consolidated Financial Statements.
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Trading and Non-Trading Marketing Activities
The following detailed presentation of Exelon’s, Generation’s, ComEd’s, PHI’s and DPL’s trading and non-trading marketing activities is
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, ComEd’s, PHI’s and DPL’s commodity mark-to-market net asset or
liability balance sheet position from January 1, 2015 to December 31, 2016. 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 normal purchase and normal
sales contracts and does not segregate proprietary trading activity. See Note 13—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, 2016 and December 31, 2015.
Total mark-to-market energy contract net assets (liabilities) at January 1,
2015 (a)
Total change in fair value during 2015 of contracts recorded in result of
operations
Reclassification to realized at settlement of contracts recorded in results of
operations
Reclassification to realized at settlement from accumulated OCI
Changes in fair value—recorded through regulatory assets and liabilities (b)
Changes in allocated collateral
Changes in net option premium paid/(received)
Option premium amortization
Upfront payments and amortizations (c)
Total mark-to-market energy contract net assets (liabilities) at December 31,
Exelon
Generation
ComEd
DPL
Predecessor
PHI
$1,505
$
1,712
$ (207)
$ —
$
—
412
(168)
(2)
(40)
(172)
(58)
(21)
50
412
—
—
(168)
(2)
—
(172)
(58)
(21)
50
—
—
(40)
—
—
—
—
—
—
2
(2)
—
—
—
—
—
—
2
(2)
—
—
—
2015 (a)
$1,506
$
1,753
$ (247)
$ —
$
—
(a) Amounts are shown net of collateral paid to and received from counterparties.
(b) For ComEd and DPL, the changes in fair value are recorded as a change in regulatory assets or liabilities. As of December 31, 2015, ComEd recorded a regulatory liability
of $247 million, respectively, related to its mark-to-market derivative liabilities with Generation and unaffiliated suppliers. ComEd recorded $55 million of decreases in fair
value and an increase for realized losses due to settlements of $(15) million in purchased power expense associated with floating-to-fixed energy swap suppliers for the
year ended December 31, 2015.
Includes derivative contracts acquired or sold by Generation through upfront payments or receipts of cash, excluding option premiums, and the associated amortizations.
(c)
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Exelon Generation ComEd DPL
PHI
Successor
March 24 to
December 31,
Predecessor
January 1 to
March 23,
PHI
Total mark-to-market energy contract net assets (liabilities) at
December 31,
2015 (a)
$1,506 $
1,753 $ (247) $ — $
—
$
Total change in fair value during 2016 of contracts recorded in result
of operations
236
236
—
—
Reclassification to realized at settlement of contracts recorded in
results of operations
Contracts received at acquisition date (b)
Changes in fair value—recorded through regulatory assets and
liabilities (c)
Changes in allocated collateral
Changes in net option premium paid/(received)
Option premium amortization
Upfront payments and amortizations (d)
Total mark-to-market energy contract net assets (liabilities) at
December 31, 2016 (a)
(265)
(59)
(8)
(908)
66
11
140
(265)
(59)
—
—
—
—
—
(905)
66
11
140
(11)
—
—
—
—
4
(4)
—
—
—
$ 719 $
977 $ (258) $ — $
—
$
—
Includes fair value from contracts received at acquisition of ConEdison Solutions of $(59) million.
(a) Amounts are shown net of collateral paid to and received from counterparties.
(b)
(c) For ComEd and DPL, the changes in fair value are recorded as a change in regulatory assets or liabilities. As of December 31, 2016 ComEd recorded a regulatory liability
of $258 million, related to its mark-to-market derivative liabilities with Generation and unaffiliated suppliers. For the year ended December 31, 2016, ComEd also recorded
$29 million of decreases in fair value and realized losses due to settlements of $18 million recorded in purchased power expense associated with floating-to-fixed energy
swap contracts with unaffiliated suppliers for the year ended December 31, 2016.
Includes derivative contracts acquired or sold by Generation through upfront payments or receipts of cash, excluding option premiums, and the associated amortizations.
(d)
Fair Values
The following tables present maturity and source of fair value for Exelon, Generation and ComEd mark-to-market commodity contract net
assets (liabilities). The tables provide two fundamental pieces of information. First, the tables provide the source of fair value used in determining the
carrying amount of the Registrants’ total mark-to-market net assets (liabilities), net of allocated collateral. Second, the tables show the maturity, by
year, of the Registrants’ commodity contract net assets (liabilities) net of allocated collateral, giving an indication of when these
mark-to-market amounts will settle and either generate or require cash. See Note 12—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.
210
—
—
—
3
(3)
—
—
—
—
—
—
—
1
(1)
—
—
—
Table of Contents
Exelon
Normal Operations, Commodity derivative contracts (a)(b) :
Actively quoted prices (Level 1)
Prices provided by external sources (Level 2)
Prices based on model or other valuation methods (Level 3) (c)
Total
Maturities Within
2017
2018 2019
2020
2021
2022 and
Beyond
Total Fair
Value
$205 $
273
162
8 $(38) $ (14) $ (1) $ — $
2
49
$640 $180 $ 13 $ (6) $ (22) $
49
123
—
8
—
(21)
—
(86)
(86) $
160
324
235
719
(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 $329 million at December 31,
2016.
Includes ComEd’s net assets (liabilities) associated with the floating-to-fixed energy swap contracts with unaffiliated suppliers.
(c)
Generation
Normal Operations, Commodity derivative contracts (a)(b) :
Actively quoted prices (Level 1)
Prices provided by external sources (Level 2)
Prices based on model or other valuation methods (Level 3)
Total
Maturities Within
2017
2018 2019
2020
2021
2022 and
Beyond
Total Fair
Value
$205 $
273
181
8 $(38) $ (14) $ (1) $ — $
2
69
$659 $199 $ 33 $ 14 $ (2) $
49
142
—
(1)
—
28
—
74
74 $
160
324
493
977
(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 $329 million at December 31,
2016.
ComEd
Prices based on model or other valuation methods (Level 3) (a)
Maturities Within
2017
2019
$(19) $(19) $(20) $(20) $(20) $
2018
2020
2021
2022 and
Beyond
Fair
Value
(160) $(258)
(a) Represents ComEd’s net liabilities associated with the floating-to-fixed energy swap contracts with unaffiliated suppliers.
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 enter into derivative
instruments. The credit exposure of derivative contracts, before
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collateral, is represented by the fair value of contracts at the reporting date. See Note 13—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 purchase normal sales
agreements, and applicable payables and receivables, net of collateral and instruments that are subject to master netting agreements, as of
December 31, 2016. 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,
NYMEX, ICE, and Nodal 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 $14 million, $33 million, $26 million, $44 million, $16 million
and $9 million respectively. See Note 27—Related Party Transactions of the Combined Notes to Consolidated Financial Statements for additional
information.
Rating as of December 31, 2016
Investment grade
Non-investment grade
No external ratings
Internally rated—investment grade
Internally rated—non-investment grade
Total
Rating as of December 31, 2016
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
Total
Exposure
Before Credit
Collateral
$
$
995
118
352
72
1,537
Credit
Collateral (a)
—
$
16
1
8
25
$
Net
Exposure
995
$
102
351
64
$ 1,512
Number of
Counterparties
Greater than 10%
of Net Exposure
1
—
Net Exposure of
Counterparties
Greater than 10%
of Net Exposure
328
$
—
—
—
1
$
—
—
328
Maturity of Credit Risk Exposure
Less than
$
2 Years
782
73
292
53
1,200
$
2-5
Years
$207
45
39
19
$310
Exposure
Greater than
5 Years
Total Exposure
Before Credit
Collateral
$
$
6
—
21
—
27
$
$
995
118
352
72
1,537
As of
December 31,
2016
$
$
116
689
636
71
1,512
(a) As of December 31, 2016, credit collateral held from counterparties where Generation had credit exposure included $9 million of cash and $16 million of letters of credit.
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ComEd
Credit risk for ComEd is governed by credit and collection policies, which are aligned with state regulatory requirements. ComEd is currently
obligated to provide service to all electric customers within its franchised territory. ComEd records a provision for uncollectible accounts, based upon
historical experience, to provide for the potential loss from nonpayment by these customers. See Note 1—Significant Accounting Policies of the
Combined Notes to Consolidated Financial Statements for the allowance for uncollectible accounts policy. ComEd will monitor nonpayment from
customers and will make any necessary adjustments to the provision for uncollectible accounts. The Illinois Public Utilities Act prohibits utilities,
including ComEd, from terminating electric service to a residential electric space heat customer due to nonpayment between December 1 of any
year through March 31 of the following year. ComEd’s ability to disconnect non space-heating residential customers is also impacted by certain
weather restrictions, at any time of year, under the Illinois Public Utilities Act. ComEd will monitor the impact of its disconnection practices and will
make any necessary adjustments to the provision for uncollectible accounts. ComEd did not have any customers representing over 10% of its
revenues as of December 31, 2016. See Note 3—Regulatory Matters of the Combined Notes to Consolidated Financial Statements for additional
information regarding ComEd’s recently approved tariffs to adjust rates annually through a rider mechanism to reflect increases or decreases in
annual uncollectible accounts expense.
ComEd’s power procurement contracts provide suppliers with a certain amount of unsecured credit. The credit position is based on 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, the suppliers are required to 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. ComEd’s counterparty credit risk is mitigated by its ability to recover realized
energy costs through customer rates. As of December 31, 2016, ComEd’s credit exposure to energy suppliers was approximately $1 million.
PECO
Credit risk for PECO is managed by credit and collection policies, which are consistent with state regulatory requirements. PECO is currently
obligated to provide service to all retail electric customers within its franchised territory. PECO records a provision for uncollectible accounts to
provide for the potential loss from nonpayment by these customers. See Note 1—Significant Accounting Policies of the Combined Notes to
Consolidated Financial Statements for the allowance for uncollectible accounts policy. In accordance with PAPUC regulations, after November 30
and before April 1, an electric distribution utility or natural gas distribution utility shall not terminate service to customers with household incomes at
or below 250% of the Federal poverty level. PECO’s provision for uncollectible accounts will continue to be affected by changes in prices as well as
changes in PAPUC regulations. PECO did not have any customers representing over 10% of its revenues as of December 31, 2016.
PECO’s supplier master agreements that govern the terms of its DSP Program contracts, which define a supplier’s performance assurance
requirements, allow a supplier to meet its credit requirements 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. As of December 31, 2016, PECO had no net credit exposure with
suppliers.
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PECO does not obtain cash collateral from suppliers under its natural gas supply and asset management agreements. As of December 31,
2016, PECO’s credit exposure under its natural gas supply and asset management agreements with investment grade suppliers was immaterial.
BGE
Credit risk for BGE is managed by credit and collection policies, which are consistent with state regulatory requirements. BGE is currently
obligated to provide service to all electric customers within its franchised territory. BGE records a provision for uncollectible accounts to provide for
the potential loss from nonpayment by these customers. BGE 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 uncollectible accounts policy. MDPSC regulations prohibit BGE from terminating service to residential customers due to nonpayment from
November 1 through March 31 if the forecasted temperature is 32 degrees or below for the subsequent 72 hour period. BGE is also prohibited by the
Public Utilities Article of the Annotated Code of Maryland and MDPSC regulations from terminating service to residential customers due to
nonpayment if the forecasted temperature is 95 degrees or above for the subsequent 72 hour period. BGE did not have any customers representing
over 10% of its revenues as of December 31, 2016.
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. 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, subject to an unsecured credit cap. 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 BGE’s net credit exposure. The seller’s credit exposure is calculated
each business day. As of December 31, 2016, BGE had no net credit exposure with suppliers.
BGE’s regulated gas business is exposed to market-price risk. This market-price risk is mitigated by BGE’s recovery of its costs to procure
natural gas through a gas cost adjustment clause approved by the MDPSC. BGE does make off-system sales after BGE has satisfied its customers’
demands, which are not covered by the gas cost adjustment clause. At December 31, 2016, BGE had credit exposure of $8 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
Credit risk for Pepco is managed by credit and collection policies, which are consistent with state regulatory requirements. Pepco is currently
obligated to provide service to all retail electric customers within its franchised territory. Pepco records a provision for uncollectible accounts to
provide for the potential loss from nonpayment by these customers. See Note 1—Significant Accounting Policies of the Combined Notes to
Consolidated Financial Statements for the allowance for uncollectible accounts policy. In accordance with MDPSC and DCPSC regulations,
applicable weather regulatory provisions are in effect January through December, the utility will not terminate service to any residential customer
when weather conditions prohibit termination. Additional MDPSC cold weather requirements are in effect after November 1 and before April 1.
Pepco’s provision for uncollectible accounts will continue to be affected by changes in prices as well as changes in MDPSC and DCPSC regulations.
Pepco did not have any customers representing over 10% of its revenues as of December 31, 2016.
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Pepco’s full requirement wholesale electric power agreements in Maryland and the District of Columbia, that govern the terms of its electric
supply procurement contracts, which define a supplier’s performance assurance requirements, allow a supplier to meet its credit requirements 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, subject to an unsecured cap. The credit position is based on the initial market price, which is
the forward price of energy on the day. A similar agreement in the District of Columbia requires a supplier to meet its credit requirements with a
specified amount equal to fifteen percent (15%) of the total purchase amount. As of December 31, 2016, Pepco had no net credit exposure with
suppliers.
DPL
Credit risk for DPL is managed by credit and collection policies, which are consistent with state regulatory requirements. DPL is currently
obligated to provide service to all retail electric customers within its franchised territory. DPL records a provision for uncollectible accounts to provide
for the potential loss from nonpayment by these customers. See Note 1—Significant Accounting Policies of the Combined Notes to Consolidated
Financial Statements for the allowance for uncollectible accounts policy. In accordance with DPSC and MDPSC regulations, applicable weather
regulatory provisions are in effect January through December, the utility will not terminate service to any residential customer when weather
conditions prohibit termination. Additional cold weather regulatory requirements are in effect after November 1 and before April 1. DPL’s provision for
uncollectible accounts will continue to be affected by changes in prices as well as changes in DPSC and MDPSC regulations. DPL did not have any
customers representing over 10% of its revenues as of December 31, 2016.
DPL’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 to meet its credit requirements 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. As of December 31, 2016,
DPL had no net credit exposure with suppliers.
DPL conducts margining under it natural gas supply contracts. As of December 31, 2016, DPL’s credit exposure under its natural gas supply
and asset management agreements was immaterial.
ACE
Credit risk for ACE is managed by credit and collection policies, which are consistent with state regulatory requirements. ACE is currently
obligated to provide service to all retail electric customers within its franchised territory. ACE records a provision for uncollectible accounts to provide
for the potential loss from nonpayment by these customers. See Note 1—Significant Accounting Policies of the Combined Notes to Consolidated
Financial Statements for the allowance for uncollectible accounts policy. In accordance with NJBPU regulations, applicable weather regulatory
provisions are in effect January through December, the utility will not terminate service to any residential customer when weather conditions prohibit
termination. Additional cold weather regulatory requirements are in effect after November 15 and through March 15. ACE’s provision for uncollectible
accounts will continue to be affected by changes in prices as well as changes in NJBPU regulations. ACE did not have any customers representing
over 10% of its revenues as of December 31, 2016.
ACE’s supplier master agreements that govern the terms of its electric supply procurement contracts, which define a supplier’s
creditworthiness requirements, require a supplier to partially meet its credit requirements with an independent credit requirement in an amount equal
to $2.4 million per
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tranche and allow a supplier to meet its additional credit requirements 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. As of December 31, 2016, ACE had no net credit exposure with
suppliers.
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. These contracts either contain express provisions or otherwise permit Generation and its counterparties to
demand adequate assurance of future performance when there are reasonable grounds for doing so. 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. 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.
See Note 13—Derivative Financial Instruments of the Combined Notes to Consolidated Financial Statements for information regarding collateral
requirements.
Generation transacts output through bilateral contracts. The bilateral contracts are subject to credit risk, which relates to the ability of
counterparties to meet their contractual payment obligations. Any failure to collect these payments from counterparties could have a material impact
on Exelon’s and Generation’s results of operations, cash flows and financial position. 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. In order 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.
As of December 31, 2016, Generation had cash collateral of $347 million posted and cash collateral held of $24 million for external
counterparties with derivative positions, of which $329 million and $2 million in net cash collateral deposits were offset against energy derivative and
interest rate and foreign exchange derivative related to underlying energy contracts, respectively. As of December 31, 2016, $8 million of cash
collateral held was not offset against net derivative positions because it was not associated with energy-related derivatives or as of the balance
sheet date there were no positions to offset. As of December 31, 2015, Generation had cash collateral posted of $1,267 million and cash collateral
held of $21 million for external counterparties with derivative positions, of which $1,234 million and $9 million in net cash collateral deposits were
offset against energy derivatives and interest rate and foreign exchange derivatives related to underlying energy contracts, respectively. As of
December 31, 2015, $3 million of cash collateral posted was not offset against net derivative positions because it was not associated with energy-
related derivatives or as the balance sheet date there were no positions to offset. See Note 24—Commitments and Contingencies of the Combined
Notes to Consolidated Financial Statements for information regarding the letters of credit supporting the cash collateral.
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ComEd
As of December 31, 2016, ComEd held $3 million in collateral from suppliers in association with standard block energy procurement contracts
and held approximately $19 million in the form of cash and letters of credit for renewable energy contracts. See Note 3—Regulatory Matters and
Note 13—Derivative Financial Instruments of the Combined Notes to Consolidated Financial Statements for additional information.
PECO
As of December 31, 2016, PECO was not required to post collateral under its energy and natural gas procurement contracts. See Note 13—
Derivative Financial Instruments of the Combined Notes to Consolidated Financial Statements for additional information.
BGE
BGE is not required to post collateral under its electric supply contracts. As of December 31, 2016, BGE was not required to post collateral
under its natural gas procurement contracts, nor was it holding collateral under its electric supply contracts, but was holding $1 million in collateral
under its natural gas procurement contracts. See Note 13—Derivative Financial Instruments of the Combined Notes to Consolidated Financial
Statements for additional information.
Pepco
Pepco is not required to post collateral under its energy procurement contracts. See Note 13—Derivative Financial Instruments of the
Combined Notes to Consolidated Financial Statements for additional information.
DPL
DPL is not required to post collateral under its energy procurement contracts. As of December 31, 2016, DPL was not required to post
collateral under its natural gas procurement contracts. See Note 13—Derivative Financial Instruments of the Combined Notes to Consolidated
Financial Statements for additional information.
ACE
ACE is not required to post collateral under its energy procurement contracts. See Note 13—Derivative Financial Instruments of the Combined
Notes to Consolidated Financial Statements for additional information.
RTOs and ISOs (All Registrants)
Generation, ComEd, PECO, BGE, Pepco, DPL and ACE participate in all, or some, of the established, real-time energy markets that are
administered by PJM, ISO-NE, ISO-NY, CAISO, MISO, SPP, AESO, OIESO and ERCOT. In these areas, power is traded through bilateral
agreements between buyers and sellers and on the spot markets that are operated by the RTOs or ISOs, as applicable. In areas where there is no
spot 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 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’
results of operations, cash flows and financial positions.
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Exchange Traded Transactions (Exelon, Generation, PHI and DPL)
Generation enters into commodity transactions on NYMEX, ICE and the Nodal exchange. DPL enters into commodity transactions on ICE. The
NYMEX, ICE and Nodal exchange clearinghouses act as the counterparty to each trade. Transactions on the NYMEX, ICE and Nodal exchange
must adhere to comprehensive collateral and margining requirements. As a result, transactions on NYMEX, ICE and Nodal exchange 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
fixed-to-floating interest rate swaps, which are typically designated as fair value hedges, as a means to manage their interest rate exposure. In
addition, the Registrants may utilize interest rate derivatives to lock in rate levels in anticipation of future financings, which are typically designated as
cash flow hedges. These strategies are employed to manage interest rate risks. At December 31, 2016, Exelon had $800 million of notional amounts
of fixed-to-floating hedges outstanding and Exelon and Generation had $659 million of notional amounts of floating-to-fixed hedges outstanding.
Assuming the fair value and cash flow interest rate hedges are 100% effective, a hypothetical 50 bps increase in the interest rates associated with
unhedged variable-rate debt (excluding Commercial Paper) and fixed-to-floating swaps would result in approximately a $7 million decrease in Exelon
Consolidated pre-tax income for the year ended December 31, 2016. 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.
Equity Price Risk (Exelon and Generation)
Exelon and Generation maintain trust funds, as required by the NRC, to fund certain costs of decommissioning Generation’s nuclear plants. As
of December 31, 2016, Generation’s decommissioning trust funds are reflected at fair value on 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 $535 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 further discussion 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, and engages in natural gas and oil exploration and production activities.
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, 2016 Compared To Year Ended December 31, 2015 and Year Ended December 31, 2015 Compared to Year
Ended December 31, 2014
A discussion of Generation’s results of operations for 2016 compared to 2015 and 2015 compared to 2014 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 access to credit
facilities in the aggregate of $5.8 billion that Generation currently utilizes to support its commercial paper program and to issue letters of credit.
See “EXELON CORPORATION—Liquidity and Capital Resources” and Note 14—Debt and Credit Agreements of the Combined Notes to
Consolidated Financial Statements of this Form 10-K for further discussion.
Capital resources are used primarily to fund Generation’s capital requirements, including construction, retirement of debt, the payment of
distributions to Exelon, contributions to Exelon’s pension plans and investments in new and existing ventures. Future acquisitions could require
external financing or borrowings or capital contributions from Exelon.
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.
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Cash Flows from Investing Activities
A discussion of items pertinent to Generation’s cash flows from investing activities is set forth under “Cash Flows from Investing Activities” in
“EXELON CORPORATION—Liquidity and Capital Resources” of this Form 10-K.
Cash Flows from Financing Activities
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, 2016 Compared to Year Ended December 31, 2015 and Year Ended December 31, 2015 Compared to Year Ended
December 31, 2014
A discussion of ComEd’s results of operations for 2016 compared to 2015 and for 2015 compared to 2014 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, 2016, ComEd had access to a revolving credit facility
with aggregate bank commitments of $1 billion.
See “EXELON CORPORATION—Liquidity and Capital Resources” and Note 14—Debt and Credit Agreements of the Combined Notes to
Consolidated Financial Statements of this Form 10-K for further discussion.
Capital resources are used primarily to fund ComEd’s capital requirements, including construction, retirement of debt, and contributions to
Exelon’s pension plans. 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.
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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.
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, 2016 Compared to Year Ended December 31, 2015 and Year Ended December 31, 2015 Compared to Year Ended
December 31, 2014
A discussion of PECO’s results of operations for 2016 compared to 2015 and for 2015 compared to 2014 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, 2016, PECO had
access to a revolving credit facility with aggregate bank commitments of $600 million.
See “EXELON CORPORATION—Liquidity and Capital Resources” and Note 14—Debt and Credit Agreements of the Combined Notes to
Consolidated Financial Statements of this Form 10-K for further discussion.
Capital resources are used primarily to fund PECO’s capital requirements, including construction, retirement of debt, the payment of dividends
and contributions to Exelon’s pension plans. 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.
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Cash Flows from Investing Activities
A discussion of items pertinent to PECO’s cash flows from investing activities is set forth under “Cash Flows from Investing Activities” in
“EXELON CORPORATION—Liquidity and Capital Resources” of this Form 10-K.
Cash Flows from Financing Activities
A discussion of items pertinent to PECO’s cash flows from financing activities is set forth under “Cash Flows from Financing Activities” in
“EXELON CORPORATION—Liquidity and Capital Resources” of this Form 10-K.
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, 2016 Compared to Year Ended December 31, 2015 and Year Ended December 31, 2015 Compared to Year Ended
December 31, 2014
A discussion of BGE’s results of operations for 2016 compared to 2015 and for 2015 compared to 2014 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, 2016, BGE had access to a revolving credit facility with aggregate bank commitments of
$600 million.
See “EXELON CORPORATION—Liquidity and Capital Resources” and Note 14—Debt and Credit Agreements of the Combined Notes to
Consolidated Financial Statements of this Form 10-K for further discussion.
Capital resources are used primarily to fund BGE’s capital requirements, including construction, retirement of debt, the payment of dividends
and contributions to Exelon’s pension plans. 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.
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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.
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 of March 24, 2016 to December 31, 2016, Predecessor Period of January 1, 2016 to March 23, 2016, and Predecessor
Period Year Ended December 31, 2015 Compared to Year Ended December 31, 2014
A discussion of PHI’s results of operations for March 24, 2016 to December 31, 2016 and January 1, 2016 to March 23, 2016 and 2015
compared to 2014 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 14—Debt and Credit Agreements of the Combined Notes to
Consolidated Financial Statements of this Form 10-K for further discussion.
Capital resources are used primarily to fund PHI’s capital requirements, including construction, retirement of debt, the payment of dividends
and contributions to Exelon’s pension plans. Additionally, PHI 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 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.
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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.
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, 2016 Compared to Year Ended December 31, 2015 and Year Ended December 31, 2015 Compared to Year Ended
December 31, 2014
A discussion of Pepco’s results of operations for 2016 compared to 2015 and for 2015 compared to 2014 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, 2016, Pepco had access to a revolving credit facility
with aggregate bank commitments of $300 million.
See “EXELON CORPORATION—Liquidity and Capital Resources” and Note 14—Debt and Credit Agreements of the Combined Notes to
Consolidated Financial Statements of this Form 10-K for further discussion.
Capital resources are used primarily to fund Pepco’s capital requirements, including construction, retirement of debt, and contributions to
Exelon’s pension plans. 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.
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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.
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, 2016 Compared to Year Ended December 31, 2015 and Year Ended December 31, 2015 Compared to Year Ended
December 31, 2014
A discussion of DPL’s results of operations for 2016 compared to 2015 and for 2015 compared to 2014 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, 2016, DPL had access to a revolving credit facility with aggregate bank commitments of
$300 million.
See “EXELON CORPORATION—Liquidity and Capital Resources” and Note 14—Debt and Credit Agreements of the Combined Notes to
Consolidated Financial Statements of this Form 10-K for further discussion.
Capital resources are used primarily to fund DPL’s capital requirements, including construction, retirement of debt, the payment of dividends
and contributions to Exelon’s pension plans. 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.
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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.
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, 2016 Compared to Year Ended December 31, 2015 and Year Ended December 31, 2015 Compared to Year Ended
December 31, 2014
A discussion of ACE’s results of operations for 2016 compared to 2015 and for 2015 compared to 2014 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, 2016, ACE had access to a revolving credit facility with aggregate bank
commitments of $300 million.
See “EXELON CORPORATION—Liquidity and Capital Resources” and Note 14—Debt and Credit Agreements of the Combined Notes to
Consolidated Financial Statements of this Form 10-K for further discussion.
Capital resources are used primarily to fund ACE’s capital requirements, including construction, retirement of debt, and contributions to
Exelon’s pension plans. 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.
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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.
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,
2016. 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,
2016, Exelon’s internal control over financial reporting was effective.
We excluded ConEdison Solutions from our assessment of internal control over financial reporting as of December 31, 2016 because it was
acquired by the Company in a purchase business combination on September 1, 2016. The total assets and total operating revenues related to
ConEdison Solutions, a wholly-owned subsidiary, represent less than 1% and 1%, respectively, of the related consolidated financial statement
amounts as of and for the year ended December 31, 2016.
The effectiveness of Exelon’s internal control over financial reporting as of December 31, 2016, has been audited by PricewaterhouseCoopers
LLP, an independent registered public accounting firm, as stated in their report which appears herein.
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Management’s Report on Internal Control Over Financial Reporting
The management of Exelon Generation Company, LLC (Generation) is responsible for establishing and maintaining adequate internal control
over financial reporting, as such term is defined in Exchange Act Rule 13a-15(f). Internal control over financial reporting is a process designed to
provide reasonable assurance regarding the reliability of financial reporting and the preparation of financial statements for external purposes in
accordance with generally accepted accounting principles.
Because of its inherent limitations, internal control over financial reporting may not prevent or detect misstatements. Also, projections of any
evaluation of effectiveness to future periods are subject to the risk that controls may become inadequate because of changes in conditions, or that
the degree of compliance with the policies or procedures may deteriorate.
Generation’s management conducted an assessment of the effectiveness of Generation’s internal control over financial reporting as of
December 31, 2016. 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, 2016, Generation’s internal control over financial reporting was effective.
We excluded ConEdison Solutions from our assessment of internal control over financial reporting as of December 31, 2016 because it was
acquired by the Company in a purchase business combination on September 1, 2016. The total assets and total operating revenues related to
ConEdison Solutions, a wholly-owned subsidiary, represent less than 1% and 2%, respectively, of the related consolidated financial statement
amounts as of and for the year ended December 31, 2016.
The effectiveness of Generation’s internal control over financial reporting as of December 31, 2016, has been audited by
PricewaterhouseCoopers LLP, an independent registered public accounting firm, as stated in their report which appears herein.
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Management’s Report on Internal Control Over Financial Reporting
The management of 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,
2016. 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,
2016, ComEd’s internal control over financial reporting was effective.
The effectiveness of ComEd’s internal control over financial reporting as of December 31, 2016, has been audited by PricewaterhouseCoopers
LLP, an independent registered public accounting firm, as stated in their report which appears herein.
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Management’s Report on Internal Control Over Financial Reporting
The management of 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,
2016. 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,
2016, PECO’s internal control over financial reporting was effective.
The effectiveness of PECO’s internal control over financial reporting as of December 31, 2016, has been audited by PricewaterhouseCoopers
LLP, an independent registered public accounting firm, as stated in their report which appears herein.
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Management’s Report on Internal Control Over Financial Reporting
The management of 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, 2016.
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, 2016, BGE’s
internal control over financial reporting was effective.
The effectiveness of BGE’s internal control over financial reporting as of December 31, 2016, has been audited by PricewaterhouseCoopers
LLP, an independent registered public accounting firm, as stated in their report which appears herein.
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Management’s Report on Internal Control Over Financial Reporting
The management of 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, 2016.
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, 2016, PHI’s internal
control over financial reporting was effective.
The effectiveness of PHI’s internal control over financial reporting as of December 31, 2016, has been audited by PricewaterhouseCoopers
LLP, an independent registered public accounting firm, as stated in their report which appears herein.
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Management’s Report on Internal Control Over Financial Reporting
The management of 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,
2016. 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,
2016, Pepco’s internal control over financial reporting was effective.
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Management’s Report on Internal Control Over Financial Reporting
The management of Delmarva Power & Light Company (DPL) is responsible for establishing and maintaining adequate internal control over
financial reporting, as such term is defined in Exchange Act Rule 13a-15(f). Internal control over financial reporting is a process designed to provide
reasonable assurance regarding the reliability of financial reporting and the preparation of financial statements for external purposes in accordance
with generally accepted accounting principles.
Because of its inherent limitations, internal control over financial reporting may not prevent or detect misstatements. Also, projections of any
evaluation of effectiveness to future periods are subject to the risk that controls may become inadequate because of changes in conditions, or that
the degree of compliance with the policies or procedures may deteriorate.
DPL’s management conducted an assessment of the effectiveness of DPL’s internal control over financial reporting as of December 31, 2016.
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, 2016, DPL’s
internal control over financial reporting was effective.
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Management’s Report on Internal Control Over Financial Reporting
The management of Atlantic City Electric Company (ACE) is responsible for establishing and maintaining adequate internal control over
financial reporting, as such term is defined in Exchange Act Rule 13a-15(f). Internal control over financial reporting is a process designed to provide
reasonable assurance regarding the reliability of financial reporting and the preparation of financial statements for external purposes in accordance
with generally accepted accounting principles.
Because of its inherent limitations, internal control over financial reporting may not prevent or detect misstatements. Also, projections of any
evaluation of effectiveness to future periods are subject to the risk that controls may become inadequate because of changes in conditions, or that
the degree of compliance with the policies or procedures may deteriorate.
ACE’s management conducted an assessment of the effectiveness of ACE’s internal control over financial reporting as of December 31, 2016.
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, 2016, ACE’s
internal control over financial reporting was effective.
February 13, 2017
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Report of Independent Registered Public Accounting Firm
To the Board of Directors and Shareholders of Exelon Corporation:
In our opinion, the consolidated financial statements listed in the index appearing under Item 15(a)(1) present fairly, in all material respects, the
financial position of Exelon Corporation and its subsidiaries at December 31, 2016 and 2015, and the results of their operations and their cash flows
for each of the three years in the period ended December 31, 2016 in conformity with accounting principles generally accepted in the United States
of America. In addition, in our opinion, the financial statement schedules listed in the index appearing under Item 15(a)(2) present fairly, in all
material respects, the information set forth therein when read in conjunction with the related consolidated financial statements. Also in our opinion,
the Company maintained, in all material respects, effective internal control over financial reporting as of December 31, 2016, based on criteria
established in Internal Control—Integrated Framework (2013) issued by the Committee of Sponsoring Organizations of the Treadway Commission
(COSO). The Company’s management is responsible for these financial statements and financial statement schedules, 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 these
financial statements, on the financial statement schedules, and on the Company’s internal control over financial reporting based on our integrated
audits. We conducted our audits in accordance with the standards of the Public Company Accounting Oversight Board (United States). Those
standards require that we plan and perform the audits to obtain reasonable assurance about whether the financial statements are free of material
misstatement and whether effective internal control over financial reporting was maintained in all material respects. Our audits of the financial
statements included 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. 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.
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 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.
As described in Management’s Report on Internal Control Over Financial Reporting, management has excluded Consolidated Edison
Solutions, Inc. from its assessment of internal control over financial reporting as of December 31, 2016 because it was acquired by the Company in a
purchase business combination on September 1, 2016. We have also excluded Consolidated Edison Solutions, Inc. from our audit of internal control
over financial reporting. Consolidated Edison Solutions, Inc. is a wholly-owned subsidiary whose total assets and total operating revenues represent
less than 1% and 1%, respectively, of the related consolidated financial statement amounts as of and for the year ended December 31, 2016.
/s/ PricewaterhouseCoopers LLP
Chicago, Illinois
February 13, 2017
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Report of Independent Registered Public Accounting Firm
To the Board of Directors and Member of Exelon Generation Company, LLC:
In our opinion, the consolidated financial statements listed in the index appearing under Item 15(a)(1) present fairly, in all material respects, the
financial position of Exelon Generation Company, LLC (the “Company”) and its subsidiaries at December 31, 2016 and 2015, and the results of their
operations and their cash flows for each of the three years in the period ended December 31, 2016 in conformity with accounting principles generally
accepted in the United States of America. In addition, in our opinion, the financial statement schedule listed in the index appearing under Item 15(a)
(2) presents fairly, in all material respects, the information set forth therein when read in conjunction with the related consolidated financial
statements. Also in our opinion, the Company maintained, in all material respects, effective internal control over financial reporting as of
December 31, 2016, based on criteria established in Internal Control—Integrated Framework (2013) issued by the Committee of Sponsoring
Organizations of the Treadway Commission (COSO). The Company’s management is responsible for these financial statements and financial
statement schedule, 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 these financial statements, on the financial statement schedule, and on the Company’s internal control over financial
reporting based on our integrated audits. We conducted our audits in accordance with the standards of the Public Company Accounting Oversight
Board (United States). Those standards require that we plan and perform the audits to obtain reasonable assurance about whether the financial
statements are free of material misstatement and whether effective internal control over financial reporting was maintained in all material respects.
Our audits of the financial statements included 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. 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.
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 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.
As described in Management’s Report on Internal Control Over Financial Reporting, management has excluded Consolidated Edison
Solutions, Inc. from its assessment of internal control over financial reporting as of December 31, 2016 because it was acquired by the Company in a
purchase business combination on September 1, 2016. We have also excluded Consolidated Edison Solutions, Inc. from our audit of internal control
over financial reporting. Consolidated Edison Solutions, Inc. is a wholly-owned subsidiary whose total assets and total operating revenues represent
less than 1% and 2%, respectively, of the related consolidated financial statement amounts as of and for the year ended December 31, 2016.
/s/ PricewaterhouseCoopers LLP
Baltimore, Maryland
February 13, 2017
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Report of Independent Registered Public Accounting Firm
To the Board of Directors and Shareholders of Commonwealth Edison Company:
In our opinion, the consolidated financial statements listed in the index appearing under Item 15(a)(1) present fairly, in all material respects, the
financial position of Commonwealth Edison Company and its subsidiaries at December 31, 2016 and 2015, and the results of their operations and
their cash flows for each of the three years in the period ended December 31, 2016 in conformity with accounting principles generally accepted in the
United States of America. In addition, in our opinion, the financial statement schedule listed in the index appearing under Item 15(a)(2) presents
fairly, in all material respects, the information set forth therein when read in conjunction with the related consolidated financial statements. Also in our
opinion, the Company maintained, in all material respects, effective internal control over financial reporting as of December 31, 2016, based on
criteria established in Internal Control—Integrated Framework (2013) issued by the Committee of Sponsoring Organizations of the Treadway
Commission (COSO). The Company’s management is responsible for these financial statements and financial statement schedule, 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 these
financial statements, on the financial statement schedule, and on the Company’s internal control over financial reporting based on our integrated
audits. We conducted our audits in accordance with the standards of the Public Company Accounting Oversight Board (United States). Those
standards require that we plan and perform the audits to obtain reasonable assurance about whether the financial statements are free of material
misstatement and whether effective internal control over financial reporting was maintained in all material respects. Our audits of the financial
statements included 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. 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.
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 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 13, 2017
246
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Report of Independent Registered Public Accounting Firm
To the Board of Directors and Shareholders of PECO Energy Company:
In our opinion, the consolidated financial statements listed in the index appearing under Item 15(a)(1) present fairly, in all material respects, the
financial position of PECO Energy Company and its subsidiaries at December 31, 2016 and 2015, and the results of their operations and their cash
flows for each of the three years in the period ended December 31, 2016 in conformity with accounting principles generally accepted in the United
States of America. In addition, in our opinion, the financial statement schedule listed in the index appearing under Item 15(a)(2) presents fairly, in all
material respects, the information set forth therein when read in conjunction with the related consolidated financial statements. Also in our opinion,
the Company maintained, in all material respects, effective internal control over financial reporting as of December 31, 2016, based on criteria
established in Internal Control—Integrated Framework (2013) issued by the Committee of Sponsoring Organizations of the Treadway Commission
(COSO). The Company’s management is responsible for these financial statements and financial statement schedule, 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 these
financial statements, on the financial statement schedule, and on the Company’s internal control over financial reporting based on our integrated
audits. We conducted our audits in accordance with the standards of the Public Company Accounting Oversight Board (United States). Those
standards require that we plan and perform the audits to obtain reasonable assurance about whether the financial statements are free of material
misstatement and whether effective internal control over financial reporting was maintained in all material respects. Our audits of the financial
statements included 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. 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.
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 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 13, 2017
247
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Report of Independent Registered Public Accounting Firm
To the Board of Directors and Shareholders of Baltimore Gas and Electric Company:
In our opinion, the consolidated financial statements listed in the index appearing under Item 15(a)(1) present fairly, in all material respects, the
financial position of Baltimore Gas and Electric Company and its subsidiaries at December 31, 2016 and 2015, and the results of their operations
and their cash flows for each of the three years in the period ended December 31, 2016 in conformity with accounting principles generally accepted
in the United States of America. In addition, in our opinion, the financial statement schedule listed in the index appearing under Item 15(a)(2)
presents fairly, in all material respects, the information set forth therein when read in conjunction with the related consolidated financial statements.
Also in our opinion, the Company maintained, in all material respects, effective internal control over financial reporting as of December 31, 2016,
based on criteria established in Internal Control—Integrated Framework (2013) issued by the Committee of Sponsoring Organizations of the
Treadway Commission (COSO). The Company’s management is responsible for these financial statements and financial statement schedule, 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
these financial statements, on the financial statement schedule, and on the Company’s internal control over financial reporting based on our
integrated audits. We conducted our audits in accordance with the standards of the Public Company Accounting Oversight Board (United States).
Those standards require that we plan and perform the audits to obtain reasonable assurance about whether the financial statements are free of
material misstatement and whether effective internal control over financial reporting was maintained in all material respects. Our audits of the
financial statements included 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. 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.
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 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 13, 2017
248
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Report of Independent Registered Public Accounting Firm
To the Board of Directors and Member of Pepco Holdings LLC:
In our opinion, the consolidated financial statements listed in the index appearing under Item 15(a)(1) present fairly, in all material respects, the
financial position of Pepco Holdings LLC and its subsidiaries (Successor) at December 31, 2016, and the results of their operations and their cash
flows for the period from March 24, 2016 to December 31, 2016 in conformity with accounting principles generally accepted in the United States of
America. In addition, in our opinion, the financial statement schedule listed in the accompanying index appearing under Item 15(a)(2) presents fairly,
in all material respects, the information set forth therein when read in conjunction with the related consolidated financial statements. Also in our
opinion, the Company maintained, in all material respects, effective internal control over financial reporting as of December 31, 2016, based on
criteria established in Internal Control—Integrated Framework (2013) issued by the Committee of Sponsoring Organizations of the Treadway
Commission (COSO). The Company’s management is responsible for these financial statements and financial statement schedule, for maintaining
effective internal control over financial reporting and for its assessment of the effectiveness of internal control over financial reporting, included in the
accompanying Management’s Report on Internal Control Over Financial Reporting. Our responsibility is to express opinions on these financial
statements, on the financial statement schedule, and on the Company’s internal control over financial reporting based on our integrated audits. We
conducted our audits in accordance with the standards of the Public Company Accounting Oversight Board (United States). Those standards require
that we plan and perform the audits to obtain reasonable assurance about whether the financial statements are free of material misstatement and
whether effective internal control over financial reporting was maintained in all material respects. Our audits of the financial statements included
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. 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.
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 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, D.C.
February 13, 2017
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Report of Independent Registered Public Accounting Firm
To the Board of Directors and Member of Pepco Holdings LLC:
In our opinion, the financial statements listed in the index appearing under Item 15(a)(1) present fairly, in all material respects, the financial
position of Pepco Holdings LLC and its subsidiaries (formerly Pepco Holdings, Inc.) (Predecessor) at December 31, 2015, and the results of their
operations and their cash flows for the period January 1, 2016 to March 23, 2016 and for each of the two years in the period ended December 31,
2015 in conformity with accounting principles generally accepted in the United States of America. In addition, in our opinion, the financial statement
schedule listed in the index appearing under Item 15(a)(2) presents fairly, in all material respects, the information set forth therein when read in
conjunction with the related 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
audits. We conducted our audits 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 audits provide a reasonable basis for our opinion.
As discussed in Note 1 to the financial statements, the Company changed the manner in which it accounts for interest on uncertain tax
positions in 2016.
/s/ PricewaterhouseCoopers LLP
Washington, D.C.
February 13, 2017
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Report of Independent Registered Public Accounting Firm
To the Board of Directors and Shareholder of Potomac Electric Power Company:
In our opinion, the financial statements listed in the index appearing under Item 15(a)(1) present fairly, in all material respects, the financial
position of Potomac Electric Power Company at December 31, 2016 and 2015, and the results of its operations and its cash flows for each of the
three years in the period ended December 31, 2016 in conformity with accounting principles generally accepted in the United States of America. In
addition, in our opinion, the financial statement schedule listed in the index appearing under Item 15(a)(2) present fairly, in all material respects, the
information set forth therein when read in conjunction with the related 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 audits. We conducted our audits 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 audits provide a reasonable basis for our opinion.
/s/ PricewaterhouseCoopers LLP
Washington, D.C.
February 13, 2017
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Report of Independent Registered Public Accounting Firm
To the Board of Directors and Shareholder of Delmarva Power & Light Company:
In our opinion, the financial statements listed in the index appearing under Item 15(a)(1) present fairly, in all material respects, the financial
position of Delmarva Power & Light Company at December 31, 2016 and 2015, and the results of its operations and its cash flows for each of the
three years in the period ended December 31, 2016 in conformity with accounting principles generally accepted in the United States of America. In
addition, in our opinion, the financial statement schedule listed in the index appearing under Item 15(a)(2) present fairly, in all material respects, the
information set forth therein when read in conjunction with the related 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 audits. We conducted our audits 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 audits provide a reasonable basis for our opinion.
/s/ PricewaterhouseCoopers LLP
Washington, D.C.
February 13, 2017
252
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Report of Independent Registered Public Accounting Firm
To the Board of Directors and Shareholder of Atlantic City Electric Company:
In our opinion, the consolidated financial statements listed in the index appearing under Item 15(a)(1) present fairly, in all material respects, the
financial position of Atlantic City Electric Company and its subsidiary at December 31, 2016 and 2015, and the results of their operations and their
cash flows for each of the three years in the period ended December 31, 2016 in conformity with accounting principles generally accepted in the
United States of America. In addition, in our opinion, the financial statement schedule listed in the index appearing under Item 15(a)(2) present 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 audits. We conducted our audits 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 audits provide a
reasonable basis for our opinion.
As discussed in Note 1 to the consolidated financial statements, the Company changed the manner in which it accounts for its regulatory
recovery mechanism for purchased power costs associated with Basic Generation Service in 2016.
/s/ PricewaterhouseCoopers LLP
Washington, D.C.
February 13, 2017
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Exelon Corporation and Subsidiary Companies
Consolidated Statements of Operations and Comprehensive Income
(In millions, except per share data)
Operating revenues
Competitive businesses revenues
Rate-regulated utility revenues
Total operating revenues
Operating expenses
Competitive businesses purchased power and fuel
Rate-regulated utility purchased power and fuel
Purchased power and fuel from affiliates
Operating and maintenance
Depreciation and amortization
Taxes other than income
Total operating expenses
Equity in losses of unconsolidated affiliates
Gain (Loss) on sales of assets
Gain on consolidation and acquisition of businesses
Operating income
Other income and (deductions)
Interest expense, net
Interest expense to affiliates
Other, net
Total other income and (deductions)
Income before income taxes
Income taxes
Equity in losses of unconsolidated affiliates
Net income
Net income (loss) 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 (loss) on cash flow hedges
Unrealized gain on marketable securities
Unrealized (loss) gain on equity investments
Unrealized gain (loss) on foreign currency translation
Reversal of CENG equity method AOCI
Other comprehensive (loss) income
Comprehensive income
Comprehensive income (loss) 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
Dividends per common share
See the Combined Notes to Consolidated Financial Statements
255
For the Years Ended
December 31,
2015
2016
2014
$ 16,324
15,036
31,360
$ 18,395
11,052
29,447
$ 16,637
10,792
27,429
8,817
3,823
—
10,048
3,936
1,576
28,200
—
(48)
—
3,112
(1,495)
(41)
413
(1,123)
1,989
761
(24)
1,204
70
$ 1,134
10,007
3,077
—
8,322
2,450
1,200
25,056
—
18
—
4,409
(992)
(41)
(46)
(1,079)
3,330
1,073
(7)
2,250
(19)
$ 2,269
9,369
3,103
531
8,568
2,314
1,154
25,039
(20)
437
289
3,096
(1,024)
(41)
455
(610)
2,486
666
—
1,820
197
$ 1,623
$ 1,204
$ 2,250
$ 1,820
(48)
184
(181)
2
1
(4)
10
—
(36)
1,168
70
$ 1,098
924
927
1.23
1.22
1.26
$
$
$
(46)
220
(99)
9
—
(3)
(21)
—
60
2,310
(19)
$ 2,329
890
893
2.55
2.54
1.24
$
$
$
(30)
147
(497)
(148)
1
8
(9)
(116)
(644)
1,176
197
979
$
860
864
1.89
1.88
1.24
$
$
$
Table of Contents
Exelon Corporation and Subsidiary Companies
Consolidated Statements of Cash Flows
(In millions)
Cash flows from operating activities
Net income
Adjustments to reconcile net income to net cash flows provided by operating activities:
Depreciation, amortization, and accretion, including nuclear fuel and energy contract amortization
Impairments of long-lived assets
Gain on consolidation and acquisition of businesses
(Gain) Loss on sales of assets
Deferred income taxes and amortization of investment tax credits
Net fair value changes related to derivatives
Net realized and unrealized (gains) losses on nuclear decommissioning trust fund investments
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 nuclear decommissioning trust fund sales
Investment in nuclear decommissioning trust funds
Cash and restricted cash acquired from consolidations and acquisitions
Acquisitions of businesses, net
Proceeds from sales of long-lived assets
Proceeds from sales of investments
Purchases of investments
Change in restricted cash
Distribution from CENG
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
Issuance of common stock
Redemption of preference stock
Distributions to noncontrolling interests of consolidated VIE
Dividends paid on common stock
Proceeds from employee stock plans
Sale of noncontrolling interests
Other financing activities
Net cash flows provided by financing activities
(Decrease) Increase in cash and cash equivalents
Cash and cash equivalents at beginning of period
Cash and cash equivalents at end of period
See the Combined Notes to Consolidated Financial Statements
256
For the Years Ended
December 31,
2015
2016
2014
$ 1,204
$ 2,250
$ 1,820
5,576
306
—
48
664
24
(229)
1,333
(432)
7
771
(66)
931
576
(397)
(1,250)
(621)
8,445
(8,553)
360
9,496
(9,738)
—
(6,934)
61
—
—
(42)
—
(153)
(15,503)
(353)
240
(462)
4,716
(1,936)
—
(190)
—
(1,166)
55
372
(85)
1,191
(5,867)
6,502
635
$
3,987
36
—
(18)
752
(367)
131
1,109
240
4
(121)
58
347
97
(502)
—
(387)
7,616
(7,624)
—
6,895
(7,147)
—
(40)
147
—
—
66
—
(119)
(7,822)
80
—
—
6,709
(2,687)
1,868
—
—
(1,105)
32
32
(99)
4,830
4,624
1,878
$ 6,502
3,868
687
(296)
(437)
502
716
(210)
1,054
(318)
(380)
49
38
(1,719)
(143)
(617)
—
(157)
4,457
(6,077)
335
7,396
(7,551)
140
(386)
1,719
7
(3)
(104)
13
(88)
(4,599)
122
—
—
3,463
(1,545)
—
—
(421)
(1,065)
35
—
(178)
411
269
1,609
$ 1,878
Exelon Corporation and Subsidiary Companies
Consolidated Balance Sheets
ASSETS
Table of Contents
(In millions)
Current assets
Cash and cash equivalents
Restricted cash and cash equivalents
Deposit with IRS
Accounts receivable, net
Customer
Other
Mark-to-market derivative assets
Unamortized energy contract assets
Inventories, net
Fossil fuel
Materials and supplies
Regulatory assets
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
Pledged assets for Zion Station decommissioning
Other
Total deferred debits and other assets
Total assets (a)
December 31,
2016
2015
$
635
253
1,250
$ 6,502
205
—
4,158
1,201
917
88
364
1,274
1,342
930
12,412
71,555
10,046
11,061
629
6,677
492
447
113
1,472
30,937
$114,904
3,187
912
1,365
86
462
1,104
759
752
15,334
57,439
6,065
10,342
639
2,672
758
484
206
1,445
22,611
$95,384
See the Combined Notes to Consolidated Financial Statements
257
Exelon Corporation and Subsidiary Companies
Consolidated Balance Sheets
LIABILITIES AND SHAREHOLDERS’ EQUITY
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
Mark-to-market derivative liabilities
Unamortized energy contract liabilities
Renewable energy credit obligation
PHI Merger related obligation
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
Payable for Zion Station decommissioning
Other
Total deferred credits and other liabilities
Total liabilities (a)
Commitments and contingencies
Contingently redeemable noncontrolling interests
Shareholders’ equity
Common stock (No par value, 2000 shares authorized, 924 shares and 920 shares outstanding at December 31, 2016 and 2015,
respectively)
Treasury stock, at cost (35 shares at December 31, 2016 and 2015, respectively)
Retained earnings
Accumulated other comprehensive loss, net
Total shareholders’ equity
BGE preference stock not subject to mandatory redemption
Noncontrolling interests
Total equity
Total liabilities and shareholders’ equity
December 31,
2016
2015
$
1,267
2,430
3,441
3,460
8
602
282
407
428
151
981
13,457
31,575
641
18,138
9,111
4,248
1,848
1,024
4,187
392
830
14
1,827
41,619
87,292
533
$
1,500
2,883
2,376
8
369
205
100
302
—
842
9,118
23,645
641
13,776
8,585
3,385
1,618
1,021
4,201
374
117
90
1,491
34,658
68,062
—
28
18,794
(2,327)
12,030
(2,660)
25,837
—
1,775
27,612
$114,904
18,676
(2,327)
12,068
(2,624)
25,793
193
1,308
27,294
$95,384
(a) Exelon’s consolidated assets include $8,893 million and $8,268 million at December 31, 2016 and December 31, 2015, respectively, of certain VIEs that can only be used
to settle the liabilities of the VIE. Exelon’s consolidated liabilities include $3,356 million and $3,264 million at December 31, 2016 and December 31, 2015, respectively, of
certain VIEs for which the VIE creditors do not have recourse to Exelon. See Note 2—Variable Interest Entities.
See the Combined Notes to Consolidated Financial Statements
258
Table of Contents
(In millions, shares in
thousands)
Balance, December 31, 2013
Net income
Long-term incentive plan activity
Employee stock purchase plan issuances
Tax benefit on stock compensation
Acquisition of noncontrolling interests
Common stock dividends
Preference stock dividends
Fair value of financing contract payments
Noncontrolling interests established upon
consolidation of CENG
Transfer of CENG pension and non-pension
postretirement benefit obligations
Consolidated VIE dividend to noncontrolling
interests
Reversal of CENG equity method AOCI, net of
income taxes
Other comprehensive loss, net of income taxes
Balance, December 31, 2014
Net income (loss)
Long-term incentive plan activity
Employee stock purchase plan issuances
Issuance of common stock
Tax benefit on stock compensation
Acquisition of noncontrolling interests
Adjustment of contingently redeemable
noncontrolling interests due to release of
contingency
Common stock dividends
Preference stock dividends
Other comprehensive income, net of income
taxes
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
Sale of noncontrolling interests
Common stock dividends
Redemption of preference stock
Preference stock dividends
Other comprehensive loss, net of income taxes
Balance, December 31, 2016
Exelon Corporation and Subsidiary Companies
Consolidated Statements of Changes in Shareholders’ Equity
Accumulated
Other
Comprehensive
Loss
Common
Issued
Shares
892,034 $ 16,741 $ (2,327) $ 10,358 $
Retained
Earnings
Stock
Stock
Treasury
—
1,574
960
—
—
—
—
—
—
—
—
—
—
—
72
35
(8)
(2)
—
—
(131)
—
2
—
—
—
—
—
—
—
—
—
—
—
—
—
—
—
—
1,623
—
—
—
—
(1,071)
—
—
—
—
—
—
—
894,568 $ 16,709 $ (2,327) $ 10,910 $
—
1,430
1,170
57,500
—
—
—
—
—
—
—
70
32
1,868
(3)
—
—
—
—
—
—
—
—
—
—
—
—
—
—
—
2,269
—
—
—
—
—
—
(1,111)
—
—
954,668 $ 18,676 $ (2,327) $ 12,068 $
—
2,868
1,242
—
—
—
—
—
—
—
—
85
55
(18)
—
(4)
—
—
—
—
—
—
—
—
—
—
—
—
—
—
1,134
—
—
—
—
—
(1,172)
—
—
—
958,778 $ 18,794 $ (2,327) $ 12,030 $
Noncontrolling
Interests
Preference
Stock
Total
Shareholders’
Equity
(2,040) $
—
—
—
—
—
—
—
—
—
—
—
(116)
(528)
(2,684) $
—
—
—
—
—
—
—
—
—
60
(2,624) $
—
—
—
—
—
—
—
—
—
(36)
(2,660) $
15 $
184
—
—
—
6
—
—
—
1,548
—
(421)
—
—
1,332 $
(32)
—
—
—
—
4
4
—
—
—
1,308 $
62
—
—
—
5
400
—
—
—
—
1,775 $
193 $
13
—
—
—
—
—
(13)
—
—
—
—
—
—
193 $
13
—
—
—
—
—
—
—
(13)
—
193 $
8
—
—
—
—
—
—
(193)
(8)
—
— $
22,940
1,820
72
35
(8)
4
(1,071)
(13)
(131)
1,548
2
(421)
(116)
(528)
24,133
2,250
70
32
1,868
(3)
4
4
(1,111)
(13)
60
27,294
1,204
85
55
(18)
5
396
(1,172)
(193)
(8)
(36)
27,612
See the Combined Notes to Consolidated Financial Statements
259
Table of Contents
[THIS PAGE INTENTIONALLY LEFT BLANK]
260
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
Equity in losses of unconsolidated affiliates
Gain (Loss) on sales of assets
Gain on consolidation and acquisition of businesses
Operating income
Other income and (deductions)
Interest expense, net
Interest expense to affiliates
Other, net
Total other income and (deductions)
Income before income taxes
Income taxes
Equity in losses of unconsolidated affiliates
Net income
Net income (loss) 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 (loss) on cash flow hedges
Unrealized (loss) gain on equity investments
Unrealized gain (loss) on foreign currency translation
Unrealized loss on marketable securities
Reversal of CENG equity method AOCI
Other comprehensive income (loss)
Comprehensive income
Comprehensive income (loss) attributable to noncontrolling interests
Comprehensive income attributable to membership interest
See the Combined Notes to Consolidated Financial Statements
261
For the Years Ended
December 31,
2015
2016
2014
$16,312
1,439
17,751
$18,386
749
19,135
$16,614
779
17,393
10,007
14
4,688
620
1,054
489
16,872
—
12
—
2,275
(322)
(43)
(60)
(425)
1,850
502
(8)
1,340
(32)
$ 1,372
9,368
557
4,943
623
967
465
16,923
(20)
437
289
1,176
(303)
(53)
406
50
1,226
207
—
1,019
184
835
$
8,818
12
4,978
663
1,879
506
16,856
—
(59)
—
836
(325)
(39)
401
37
873
290
(25)
558
62
496
$
$
558
$ 1,340
$ 1,019
2
(4)
10
1
—
9
567
62
505
$
$
(3)
(3)
(21)
—
—
(27)
$ 1,313
(32)
$ 1,345
(132)
8
(9)
(1)
(116)
(250)
769
184
585
$
$
Table of Contents
Exelon Generation Company, LLC and Subsidiary Companies
Consolidated Statements of Cash Flows
(In millions)
Cash flows from operating activities
Net income
Adjustments to reconcile net income to net cash flows provided by operating activities:
Depreciation, amortization and accretion, including nuclear fuel and energy contract amortization
Impairment of long-lived assets
Gain on consolidation and acquisition of businesses
(Gain) Loss on sales of assets
Deferred income taxes and amortization of investment tax credits
Net fair value changes related to derivatives
Net realized and unrealized (gains) losses on nuclear decommissioning trust 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 nuclear decommissioning trust fund sales
Investment in nuclear decommissioning trust funds
Cash and restricted cash acquired from consolidations and acquisitions
Proceeds from sales of long-lived assets
Acquisitions of businesses, net
Change in restricted cash
Changes in Exelon intercompany money pool
Distribution from CENG
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
Retirement of long-term debt to affiliate
Changes in Exelon intercompany money pool
Distribution to member
Distribution to noncontrolling interests of consolidated VIE
Contribution from member
Sale of noncontrolling interests
Other financing activities
Net cash flows used in financing activities
Decrease in cash and cash equivalents
Cash and cash equivalents at beginning of period
Cash and cash equivalents at end of period
See the Combined Notes to Consolidated Financial Statements
262
For the Years Ended
December 31,
2016
2015
2014
$
558
$ 1,340
$ 1,019
3,519
243
—
59
(269)
40
(229)
15
(152)
(21)
(4)
29
(66)
923
182
(152)
(231)
4,444
(3,078)
9,496
(9,738)
—
37
(293)
(35)
—
—
(240)
(3,851)
620
240
(162)
388
(202)
—
(1,191)
(922)
—
142
372
(19)
(734)
(141)
431
290
$
2,589
12
—
(12)
49
(249)
131
268
194
15
16
(149)
58
407
(18)
(245)
(207)
4,199
(3,841)
6,895
(7,147)
—
147
(40)
35
—
—
(118)
(4,069)
—
—
—
1,309
(89)
(550)
1,252
(2,474)
—
47
32
(6)
(479)
(349)
780
431
$
2,519
663
(296)
(437)
(198)
635
(210)
346
(215)
15
(359)
29
38
(1,748)
265
(297)
57
1,826
(3,012)
7,396
(7,551)
140
1,719
(386)
(87)
44
13
(43)
(1,767)
17
—
—
1,112
(586)
—
—
(645)
(421)
53
—
(67)
(537)
(478)
1,258
780
$
Table of Contents
Exelon Generation Company, LLC and Subsidiary Companies
Consolidated Balance Sheets
ASSETS
(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
Materials and supplies
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
Pledged assets for Zion Station decommissioning
Unamortized energy contract assets
Deferred income taxes
Other
Total deferred debits and other assets
Total assets (a)
December 31,
2016
2015
$
290
158
$
431
123
2,433
558
917
156
88
292
935
701
6,528
25,585
11,061
418
47
476
1,595
113
447
16
688
14,861
$46,974
2,095
360
1,365
83
86
384
880
535
6,342
25,843
10,342
210
47
733
1,689
206
484
6
627
14,344
$46,529
See the Combined Notes to Consolidated Financial Statements
263
Table of Contents
(In millions)
Current liabilities
Exelon Generation Company, LLC and Subsidiary Companies
Consolidated Balance Sheets
LIABILITIES AND EQUITY
Short-term borrowings
Long-term debt due within one year
Accounts payable
Accrued expenses
Payables to affiliates
Borrowings from Exelon intercompany money pool
Mark-to-market derivative liabilities
Unamortized energy contract liabilities
Renewable energy credit obligation
Other
Total current liabilities
Long-term debt
Long-term debt to affiliate
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
Payable for Zion Station decommissioning
Other
Total deferred credits and other liabilities
Total liabilities (a)
Commitments and contingencies
Contingently redeemable noncontrolling interests
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,
2016
2015
699
$
1,117
1,610
989
137
55
263
72
428
313
5,683
7,202
922
5,585
8,922
930
1,024
2,608
153
80
14
595
19,911
33,718
$
29
90
1,583
935
104
1,252
182
100
302
356
4,933
7,936
933
5,845
8,431
924
1,021
2,577
150
117
90
602
19,757
33,559
—
28
9,261
2,275
(54)
11,482
1,774
13,256
$46,974
8,997
2,701
(63)
11,635
1,307
12,942
$46,529
(a) Generation’s consolidated assets include $8,817 million and $8,235 million at December 31, 2016 and 2015, respectively, of certain VIEs that can only be used to settle
the liabilities of the VIE. Generation’s consolidated liabilities include $3,170 million and $3,135 million at December 31, 2016 and 2015, respectively, of certain VIEs for
which the VIE creditors do not have recourse to Generation. See Note 2—Variable Interest Entities.
See the Combined Notes to Consolidated Financial Statements
264
Table of Contents
Exelon Generation Company, LLC and Subsidiary Companies
Consolidated Statements of Changes in Equity
(In millions)
Balance, December 31, 2013
Net income
Acquisition of noncontrolling interests
Allocation of tax benefit from member
Distribution to member
Noncontrolling interests established upon
consolidation of CENG
Consolidated VIE dividend to noncontrolling
interests
Reversal of CENG equity method AOCI, net of
income taxes
Other comprehensive loss, net of income taxes
Balance, December 31, 2014
Net income (loss)
Acquisition of noncontrolling interests
Adjustment of contingently redeemable
noncontrolling interests due to release of
contingency
Allocation of tax benefit from member
Distribution to member
Other comprehensive loss, net of income taxes
Balance, December 31, 2015
Net income
Sale of noncontrolling interests
Changes in equity of noncontrolling interests
Allocation of tax benefit from member
Contribution from member
Distribution to member
Other comprehensive income, net of income taxes
Balance, December 31, 2016
Member’s Equity
Membership
Interest
Undistributed
Earnings
$
$
$
$
8,898
—
—
53
—
—
—
—
—
8,951
—
(1)
—
47
—
—
8,997
—
(4)
—
98
170
—
—
9,261
$
$
$
$
3,613
835
—
—
(645)
—
—
—
—
3,803
1,372
—
—
—
(2,474)
—
2,701
496
—
—
—
—
(922)
—
2,275
Accumulated
Other
Comprehensive
Income (Loss)
214
$
—
—
—
—
—
(116)
(134)
(36)
—
—
—
—
—
(27)
(63)
—
—
—
—
—
—
9
(54)
$
$
$
See the Combined Notes to Consolidated Financial Statements
265
Noncontrolling
Interests
Total
Equity
$12,742
1,019
5
53
(645)
17
184
5
—
—
1,548
1,548
(421)
(421)
—
—
1,333
(32)
2
4
—
—
—
1,307
62
400
5
—
—
—
—
1,774
(116)
(134)
$14,051
1,340
1
4
47
(2,474)
(27)
$12,942
558
396
5
98
170
(922)
9
$13,256
$
$
$
$
Table of Contents
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266
Table of Contents
Commonwealth Edison Company and Subsidiary Companies
Consolidated Statements of Operations and Comprehensive Income
(in millions)
Operating revenues
Electric operating revenues
Operating revenues from affiliates
Total operating revenues
Operating expenses
Purchased power
Purchased power from affiliate
Operating and maintenance
Operating and maintenance from affiliate
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,
2015
2016
2014
$5,239
15
5,254
$4,901
4
4,905
1,411
47
1,303
227
775
293
4,056
7
1,205
(448)
(13)
(65)
(526)
679
301
$ 378
$ 378
1,301
18
1,372
195
707
296
3,889
1
1,017
(319)
(13)
21
(311)
706
280
$ 426
$ 426
$4,560
4
4,564
1,001
176
1,263
166
687
293
3,586
2
980
(308)
(13)
17
(304)
676
268
$ 408
$ 408
See the Combined Notes to Consolidated Financial Statements
267
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
Proceeds from sales of investments
Purchases of investments
Change in restricted cash
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
(Decrease) increase in cash and cash equivalents
Cash and cash equivalents at beginning of period
Cash and cash equivalents at end of period
For the Years Ended
December 31,
2015
2016
2014
$
378
$
426
$
408
775
439
215
(25)
3
1
339
7
306
(38)
105
2,505
(2,734)
—
—
—
49
(2,685)
(294)
1,200
(665)
315
(369)
(18)
169
(11)
67
56
$
707
353
416
(93)
(19)
(40)
68
(33)
192
(150)
69
1,896
(2,398)
—
—
2
34
(2,362)
(10)
850
(260)
202
(299)
(16)
467
1
66
67
$
687
433
255
(121)
(11)
(16)
95
2
(159)
(248)
1
1,326
(1,689)
7
(3)
(2)
32
(1,655)
120
900
(617)
273
(307)
(10)
359
30
36
66
$
See the Combined Notes to Consolidated Financial Statements
268
Table of Contents
Commonwealth Edison Company and Subsidiary Companies
Consolidated Balance Sheets
ASSETS
(In millions)
Current assets
Cash and cash equivalents
Restricted cash
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
Receivable from affiliates
Prepaid pension asset
Other
Total deferred debits and other assets
Total assets
December 31,
2016
2015
$
56
2
$
67
2
528
218
356
159
190
45
1,554
19,335
977
6
2,625
2,170
1,343
325
7,446
$28,335
533
272
199
164
218
63
1,518
17,502
895
6
2,625
2,172
1,490
324
7,512
$26,532
See the Combined Notes to Consolidated Financial Statements
269
Table of Contents
(In millions)
Current liabilities
Commonwealth Edison Company and Subsidiary Companies
Consolidated Balance Sheets
LIABILITIES AND SHAREHOLDERS’ EQUITY
Short-term borrowings
Long-term debt due within one year
Accounts payable
Accrued expenses
Payables to affiliates
Customer deposits
Regulatory liabilities
Mark-to-market derivative liability
Other
Total current liabilities
Long-term debt
Long-term debt to financing trust
Deferred credits and other liabilities
Deferred income taxes and unamortized investment tax credits
Asset retirement obligations
Non-pension postretirement benefits obligations
Regulatory liabilities
Mark-to-market derivative liability
Other
Total deferred credits and other liabilities
Total liabilities
Commitments and contingencies
Shareholders’ equity
Common stock
Other paid-in capital
Retained deficit unappropriated
Retained earnings appropriated
Total shareholders’ equity
Total liabilities and shareholders’ equity
December 31,
2016
2015
$ —
425
645
1,250
65
121
329
19
84
2,938
6,608
205
5,364
119
239
3,369
239
529
9,859
19,610
$
294
665
660
706
62
131
155
23
70
2,766
5,844
205
4,914
111
259
3,459
224
507
9,474
18,289
1,588
6,150
(1,639)
2,626
8,725
$28,335
1,588
5,677
(1,639)
2,617
8,243
$26,532
See the Combined Notes to Consolidated Financial Statements
270
Table of Contents
Commonwealth Edison Company and Subsidiary Companies
Consolidated Statements of Changes in Shareholders’ Equity
(In millions)
Balance, December 31, 2013
Net income
Common stock dividends
Contribution from parent
Parent tax matter indemnification
Appropriation of retained earnings for future
dividends
Balance, Balance at December 31, 2014
Net income
Common stock dividends
Contribution from parent
Parent tax matter indemnification
Appropriation of retained earnings for future
dividends
Balance, December 31, 2015
Net income
Common stock dividends
Contribution from parent
Parent tax matter indemnification
Appropriation of retained earnings for future
dividends
Balance, December 31, 2016
Common
Stock
$ 1,588
—
—
—
—
—
$ 1,588
—
—
—
—
—
$ 1,588
—
—
—
—
—
$ 1,588
Other
Paid-In
Capital
$5,190
—
—
273
5
—
$5,468
—
—
202
7
—
$5,677
—
—
315
158
—
$6,150
Retained Deficit
Unappropriated
(1,639)
$
408
—
Retained
Earnings
Appropriated
2,389
$
—
(307)
—
(408)
(1,639)
426
—
—
—
(426)
(1,639)
378
—
—
—
(378)
(1,639)
—
408
2,490
—
(299)
—
—
426
2,617
—
(369)
—
—
378
2,626
$
$
$
$
$
$
Total
Shareholders’
Equity
$
$
$
$
7,528
408
(307)
273
5
—
7,907
426
(299)
202
7
—
8,243
378
(369)
315
158
—
8,725
See the Combined Notes to Consolidated Financial Statements
271
Table of Contents
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272
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
Operating revenues from affiliates
Total operating revenues
Operating expenses
Purchased power
Purchased fuel
Purchased power from affiliate
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
Net income attributable to common shareholder
Comprehensive income
For the Years Ended
December 31,
2015
2016
2014
$2,524
462
8
2,994
598
162
287
665
146
270
164
2,292
—
702
(111)
(12)
8
(115)
587
149
438
$ 438
$ 438
$2,485
545
2
3,032
735
235
220
684
110
260
160
2,404
2
630
(102)
(12)
5
(109)
521
143
378
$ 378
$ 378
$2,446
646
2
3,094
740
327
194
767
99
236
159
2,522
—
572
(101)
(12)
7
(106)
466
114
352
$ 352
$ 352
See the Combined Notes to Consolidated Financial Statements
273
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
Change in restricted cash
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 provided by (used in) financing activities
(Decrease) Increase in cash and cash equivalents
Cash and cash equivalents at beginning of period
Cash and cash equivalents at end of period
For the Years Ended
December 31,
2016
2015
2014
$ 438
$ 378
$ 352
270
78
65
(71)
6
6
67
8
(30)
(8)
829
(686)
(131)
(1)
20
(798)
300
(300)
18
(277)
(4)
(263)
(232)
295
$ 63
260
90
70
37
3
10
(25)
(9)
(40)
(4)
770
(601)
—
(1)
14
(588)
350
—
16
(279)
(4)
83
265
30
$ 295
236
88
92
(16)
(6)
2
58
(57)
(16)
(21)
712
(661)
—
—
12
(649)
300
(250)
24
(320)
(4)
(250)
(187)
217
$ 30
See the Combined Notes to Consolidated Financial Statements
274
Table of Contents
(In millions)
Current assets
PECO Energy 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
Receivable from Exelon intercompany pool
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
Receivable from affiliates
Prepaid pension asset
Other
Total deferred debits and other assets
Total assets
December 31,
2016
2015
$
63
4
$
295
3
306
131
4
131
35
27
9
29
18
757
7,565
1,681
25
438
345
20
2,509
$10,831
258
146
2
—
43
26
11
34
24
842
7,141
1,583
28
405
347
21
2,384
$10,367
See the Combined Notes to Consolidated Financial Statements
275
Table of Contents
(In millions)
Current liabilities
PECO Energy Company and Subsidiary Companies
Consolidated Balance Sheets
LIABILITIES AND SHAREHOLDER’S EQUITY
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
December 31,
2016
2015
$ —
342
104
63
61
127
30
727
2,580
184
3,006
28
289
517
85
3,925
7,416
$
300
281
109
55
58
112
29
944
2,280
184
2,792
27
287
527
90
3,723
7,131
2,473
941
1
3,415
$10,831
2,455
780
1
3,236
$10,367
See the Combined Notes to Consolidated Financial Statements
276
Table of Contents
(In millions)
Balance, December 31, 2013
Net income
Common stock dividends
Allocation of tax benefit from parent
Balance, December 31, 2014
Net income
Common stock dividends
Allocation of tax benefit from parent
Balance, December 31, 2015
Net income
Common stock dividends
Allocation of tax benefit from parent
Balance, December 31, 2016
PECO Energy Company and Subsidiary Companies
Consolidated Statements of Changes in Shareholder’s Equity
Common
Stock
$ 2,415
—
—
24
$ 2,439
—
—
16
$ 2,455
—
—
18
$ 2,473
Retained
Earnings
649
$
352
(320)
—
681
$
378
(279)
—
780
$
438
(277)
—
941
$
Accumulated
Other
Comprehensive
Income
Total
Shareholder’s
Equity
$
$
$
$
1
—
—
—
1
—
—
—
1
—
—
—
1
$
$
$
$
3,065
352
(320)
24
3,121
378
(279)
16
3,236
438
(277)
18
3,415
See the Combined Notes to Consolidated Financial Statements
277
Table of Contents
[THIS PAGE INTENTIONALLY LEFT BLANK]
278
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
Operating revenues from affiliates
Total operating revenues
Operating expenses
Purchased power
Purchased fuel
Purchased power from affiliate
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,
2015
2016
2014
$2,603
609
21
3,233
528
162
604
605
132
423
229
2,683
—
550
(87)
(16)
21
(82)
468
174
294
8
$ 286
$ 294
8
$ 286
$2,490
631
14
3,135
602
205
498
565
118
366
224
2,578
1
558
(83)
(16)
18
(81)
477
189
288
13
$ 275
$ 288
13
$ 275
$2,460
680
25
3,165
733
302
382
614
103
371
221
2,726
—
439
(90)
(16)
18
(88)
351
140
211
13
$ 198
$ 211
13
$ 198
See the Combined Notes to Consolidated Financial Statements
279
Table of Contents
Baltimore Gas and Electric Company and Subsidiary Companies
Consolidated Statements of Cash Flows
(In millions)
Cash flows from operating activities
Net income
Adjustments to reconcile net income to net cash flows provided by operating activities:
Depreciation, amortization and accretion
Impairment of long-lived assets and 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 (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
Change in restricted cash
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
Redemption of preference stock
Dividends paid on common stock
Dividends paid on preference stock
Contributions from parent
Other financing activities
Net cash flows used in financing activities
Increase (Decrease) in cash and cash equivalents
Cash and cash equivalents at beginning of period
Cash and cash equivalents at end of period
For the Years Ended
December 31,
2016
2015
2014
$ 294
$ 288
$ 211
423
52
118
88
(98)
3
1
138
—
18
(49)
(43)
945
(934)
—
24
(910)
(165)
850
(379)
(190)
(179)
(8)
61
(11)
(21)
14
9
$ 23
366
—
165
137
84
(2)
18
(3)
(27)
(54)
(17)
(173)
782
(719)
26
18
(675)
90
—
(75)
—
(158)
(13)
7
(13)
(162)
(55)
64
9
$
371
—
116
180
46
(1)
(6)
(75)
27
45
(16)
(158)
740
(620)
(22)
20
(622)
(15)
—
(70)
—
—
(13)
—
13
(85)
33
31
$ 64
See the Combined Notes to Consolidated Financial Statements
280
Table of Contents
(In millions)
Current assets
Baltimore Gas and Electric Company and Subsidiary Companies
Consolidated Balance Sheets
ASSETS
Cash and cash equivalents
Restricted cash and cash equivalents
Accounts receivable, net
Customer
Other
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 (a)
December 31,
2016
2015
$
23
24
$
9
24
395
102
300
112
30
38
15
208
7
842
7,040
504
12
297
9
822
$8,704
36
33
61
267
3
845
6,597
514
12
319
8
853
$8,295
See the Combined Notes to Consolidated Financial Statements
281
Table of Contents
(In millions)
Current liabilities
Baltimore Gas and Electric Company and Subsidiary Companies
Consolidated Balance Sheets
LIABILITIES AND SHAREHOLDERS’ EQUITY
Short-term borrowings
Long-term debt due within one year
Accounts payable
Accrued expenses
Payables to affiliates
Customer deposits
Regulatory liabilities
Other
Total current liabilities
Long-term debt
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
Other
Total deferred credits and other liabilities
Total liabilities (a)
Commitments and contingencies
Shareholders’ equity
Common stock
Retained earnings
Total shareholders’ equity
Preference stock not subject to mandatory redemption
Total equity
Total liabilities and shareholders’ equity
December 31,
2016
2015
$
45
41
205
175
55
110
50
26
707
2,281
252
2,219
21
205
110
61
2,616
5,856
1,421
1,427
2,848
—
2,848
$8,704
$ 210
378
209
110
52
102
38
35
1,134
1,480
252
2,081
17
209
184
61
2,552
5,418
1,367
1,320
2,687
190
2,877
$8,295
__________________________
(a) BGE’s consolidated assets include $26 million and $26 million at December 31, 2016 and December 31, 2015, respectively, of BGE’s consolidated VIE that can only be
used to settle the liabilities of the VIE. BGE’s consolidated liabilities include $42 million and $122 million at December 31, 2016 and December 31, 2015, respectively, of
BGE’s consolidated VIE for which the VIE creditors do not have recourse to BGE. See Note 2—Variable Interest Entities.
See the Combined Notes to Consolidated Financial Statements
282
$
Preference
stock
not
subject to
mandatory
redemption
190
$
—
—
190
—
—
—
—
190
—
—
—
—
—
(190)
—
$
$
Total
Equity
$2,555
211
(13)
$2,753
288
(13)
(158)
7
$2,877
294
(8)
(179)
(7)
61
(190)
$2,848
Table of Contents
(In millions)
Balance, December 31, 2013
Net income
Preference stock dividends
Balance, December 31, 2014
Net income
Preference stock dividends
Common stock dividends
Contribution from parent
Balance, December 31, 2015
Net income
Preference stock dividends
Common stock dividends
Distribution to parent
Contribution from parent
Redemption of preference stock
Balance, December 31, 2016
Baltimore Gas and Electric Company and Subsidiary Companies
Consolidated Statements of Changes in Shareholders’ Equity
Common
Stock
$ 1,360
—
—
$ 1,360
—
—
—
7
$ 1,367
—
—
—
(7)
61
—
$ 1,421
Retained
Earnings
$ 1,005
211
(13)
$ 1,203
288
(13)
(158)
—
$ 1,320
294
(8)
(179)
—
—
—
$ 1,427
Total
Shareholders’
Equity
$
$
$
$
2,365
211
(13)
2,563
288
(13)
(158)
7
2,687
294
(8)
(179)
(7)
61
—
2,848
See the Combined Notes to Consolidated Financial Statements
283
Table of Contents
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284
Table of Contents
Pepco Holdings LLC and Subsidiary Companies
Consolidated Statements of Operations and Comprehensive Income
(In millions)
Operating revenues
Electric operating revenues
Natural gas operating revenues
Operating revenues from affiliates
Total operating revenues
Operating expenses
Purchased power
Purchased fuel
Purchased power and fuel from affiliates
Operating and maintenance
Operating and maintenance from affiliates
Depreciation, amortization and accretion
Taxes other than income
Total operating expenses
(Loss) gain on sales of assets
Operating income
Other income and (deductions)
Interest expense, net
Other, net
Total other income and (deductions)
(Loss) income before income taxes
Income taxes
Net (loss) income from continuing operations
Net income from discontinued operations
Net (loss) income attributable to membership interest/common
shareholders
Comprehensive income (loss), net of income taxes
Net (loss) income
Other comprehensive income (loss), net of income taxes
Pension and non-pension postretirement benefit plans:
Actuarial loss (gain) reclassified to periodic cost
Unrealized loss on cash flow hedges
Other comprehensive income (loss)
Comprehensive (loss) income
Successor
March 24 to
December 31,
2016
January 1 to
March 23,
2016
Predecessor
For the Years Ended
December 31,
2015
2014
$
$
$
$
3,506
92
45
3,643
925
36
486
1,144
89
515
354
3,549
(1)
93
(195)
44
(151)
(58)
3
(61)
—
(61)
(61)
—
—
—
(61)
$
$
$
$
1,096
57
—
1,153
471
26
—
294
—
152
105
1,048
—
105
(65)
(4)
(69)
36
17
19
—
$ 4,770
165
—
4,935
1,986
87
—
1,156
—
624
455
4,308
46
673
(280)
88
(192)
481
163
318
9
19
$
327
19
$
327
1
—
1
20
9
1
10
337
$
$ 4,614
194
—
4,808
1,940
117
—
1,183
—
526
437
4,203
—
605
(269)
44
(225)
380
138
242
—
$
$
242
242
(12)
—
(12)
230
$
See the Combined Notes to Consolidated Financial Statements
285
Table of Contents
(In millions)
Cash flows from operating activities
Pepco Holdings LLC and Subsidiary Companies
Consolidated Statements of Cash Flows
Successor
March 24 to
December 31,
2016
Predecessor
January 1 to
March 23,
2016
For the Years Ended
December 31,
2015 2014
Net (loss) income
Income from discontinued operations, net of income taxes
Adjustments to reconcile net (loss) income to net cash from operating activities:
$
Depreciation, amortization and accretion
Impairment of long-lived assets
Loss (Gain) on sales of 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
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
Proceeds from sales of land
Changes in restricted cash
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
Issuance of preferred stock
Dividends paid on common stock
Common stock issued for the Direct Stock Purchase and Dividend Reinvestment Plan and
employee-related compensation
Distribution to member
Contribution from member
Change in Exelon intercompany money pool
Other financing activities
Net cash flows (used in) provided by financing activities
(Decrease) Increase in cash and cash equivalents
Cash and cash equivalents at beginning of period
Cash and cash equivalents at end of period
$
(61)
—
515
—
1
295
—
514
(21)
42
3
19
—
(22)
(86)
(311)
888
(1,008)
24
(37)
—
(9)
(1,030)
(515)
—
(300)
179
(338)
—
—
—
(273)
1,251
(6)
(5)
(7)
(149)
319
170
See the Combined Notes to Consolidated Financial Statements
286
$
19 $
—
327 $
(9)
242
—
526
81
—
303
—
127
(2)
—
8
(31)
1
(197)
(18)
(186)
854
624
—
(46)
134
—
167
(105)
—
—
(41)
—
8
(21)
(99)
939
(1,230)
54
6
—
9
(1,161)
(1,223)
—
(12)
—
9
(1,226)
34
300
—
558
(430)
54
(275)
18
—
—
—
(26)
233
11
15
26 $
183
—
—
766
(462)
126
(272)
33
—
—
—
(11)
363
(9)
24
15
152
—
—
19
18
46
(28)
—
(4)
42
1
12
(4)
(9)
264
(273)
—
3
(68)
(5)
(343)
(121)
500
—
—
(11)
—
—
2
—
—
—
2
372
293
26
319 $
$
Pepco Holdings LLC and Subsidiary Companies
Consolidated Balance Sheets
ASSETS
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 asset
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
Total deferred debits and other assets
Total assets (a)
Successor
December 31,
2016
Predecessor
December 31,
2015
$
$
170
43
496
283
—
6
116
653
71
1,838
11,598
2,851
133
4,005
4
509
6
81
7,589
21,025
$
$
26
14
581
319
18
9
122
305
80
1,474
10,864
2,277
80
1,406
4
—
14
69
3,850
16,188
See the Combined Notes to Consolidated Financial Statements
287
Table of Contents
Pepco Holdings LLC and Subsidiary Companies
Consolidated Balance Sheets
(In millions)
Current liabilities
LIABILITIES AND EQUITY
Short-term borrowings
Long-term debt due within one year
Accounts payable
Accrued expenses
Payables to affiliates
Unamortized energy contract liabilities
Customer deposits
Merger related obligation
Regulatory liabilities
Other
Total current liabilities
Long-term debt
Deferred credits and other liabilities
Regulatory liabilities
Deferred income taxes and unamortized investment tax credits
Asset retirement obligations
Pension obligations
Non-pension postretirement benefit obligations
Unamortized energy contract liabilities
Other
Total deferred credits and other liabilities
Total liabilities (a)
Commitments and contingencies
Preferred stock (b)
Member’s equity/Shareholders’ equity
Membership interest/Common stock (c)
Undistributed (losses)/Retained earnings
Accumulated other comprehensive loss, net
Total member’s equity/shareholders’ equity
Total liabilities and member’s equity/shareholders’ equity
Successor
December 31,
2016
Predecessor
December 31,
2015
$
$
522
253
458
272
94
335
123
101
79
47
2,284
5,645
158
3,775
14
—
134
750
249
5,080
13,009
—
8,077
(61)
—
8,016
21,025
$
$
958
456
404
266
—
—
107
—
66
70
2,327
4,823
147
3,406
8
466
215
—
200
4,442
11,592
183
3,832
617
(36)
4,413
16,188
(a) PHI’s consolidated total assets include $49 million and $30 million at December 31, 2016 and 2015, respectively, of PHI’s consolidated VIE that can only be used to settle
the liabilities of the VIE. PHI’s consolidated total liabilities include $143 million and $172 million at December 31, 2016 and 2015, respectively, of PHI’s consolidated VIE
for which the VIE creditors do not have recourse to PHI. See Note 2—Variable Interest Entities.
(b) At December 31, 2015, PHI had 18,000 shares of Series A preferred stock authorized and outstanding, par value $0.01 per share.
(c) At December 31, 2015, PHI’s (predecessor) shareholders’ equity included $3,829 million of other paid-in capital and $3 million of common stock. At December 31, 2015,
PHI had 400,000,000 shares of common stock authorized and 254,289,261 shares of common stock outstanding, par value $0.01 per share.
See the Combined Notes to Consolidated Financial Statements
288
Table of Contents
Pepco Holdings LLC and Subsidiary Companies
Consolidated Statements of Changes in Equity
(In millions, except share data)
Predecessor
Balance, December 31, 2013
Net income
Common stock dividends
Original issue shares, net
DRP original issue shares
Net activity related to stock-based awards
Other comprehensive loss, net of income taxes
Balance, December 31, 2014
Net income
Common stock dividends
Original issue shares, net
DRP original issue shares
Net activity related to stock-based awards
Other comprehensive income, net of income taxes
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
Distribution to member (c)
Contribution 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
Common
Stock (a)
Retained
Earnings
Accumulated
Other
Comprehensive
Loss, net
Total
Shareholders’
Equity
$
$
$
$
3,754
—
—
14
28
7
—
3,803
—
—
15
11
3
—
3,832
—
3
3
—
3,838
$
$
$
$
595
242
(272)
—
—
—
—
565
327
(275)
—
—
—
—
617
19
—
—
—
636
$
$
$
$
(34)
—
—
—
—
—
(12)
(46)
—
—
—
—
—
10
(36)
—
—
—
1
(35)
Membership
Interest
Undistributed
Losses
Accumulated
Other
Comprehensive
Loss, net
$
$
7,200
—
(400)
1,251
35
53
(62)
8,077
$
$
—
(61)
—
—
—
—
—
(61)
$
$
—
—
—
—
—
—
—
—
$
$
$
$
$
$
4,315
242
(272)
14
28
7
(12)
4,322
327
(275)
15
11
3
10
4,413
19
3
3
1
4,439
Member’s
Equity
7,200
(61)
(400)
1,251
35
53
(62)
8,016
(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.
(b) 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.
(c) 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.
(d) 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 4—Mergers, Acquisitions, and Dispositions.
See the Combined Notes to Consolidated Financial Statements
289
Table of Contents
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290
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Potomac Electric Power Company
Statements of Operations and Comprehensive Income
(In millions)
Operating revenues
Electric operating revenues
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 attributable to common shareholder
Comprehensive income
For the Years Ended
December 31,
2015
2016
2014
$2,181
5
2,186
$2,124
5
2,129
411
295
607
35
295
377
2,020
8
174
(127)
36
(91)
83
41
42
42
$
$
719
—
435
4
256
376
1,790
46
385
(124)
28
(96)
289
102
$ 187
$ 187
$2,050
5
2,055
735
—
386
4
212
369
1,706
—
349
(115)
30
(85)
264
93
$ 171
$ 171
See the Combined Notes to Consolidated Financial Statements
291
Table of Contents
Potomac Electric Power Company
Statements of Cash Flows
(In millions)
Cash flows from operating activities
Net income
Adjustments to reconcile net (loss) income to net cash flows provided by operating activities:
Depreciation and amortization
Gain on sales of assets
Deferred income taxes and amortization of investment tax credits
Other non-cash operating activities
Changes in assets and liabilities:
Accounts receivable
Receivables from and payables to affiliates, net
Inventories
Accounts payable and accrued expenses
Income taxes
Pension and non-pension postretirement benefit contributions
Other assets and liabilities
Net cash flows provided by operating activities
Cash flows from investing activities
Capital expenditures
Proceeds from sale of long-lived asset
Purchases of investments
Changes in restricted cash
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
Contribution from parent
Other financing activities
Net cash flows provided by financing activities
Increase (decrease) in cash and cash equivalents
Cash and cash equivalents at beginning of period
Cash and cash equivalents at end of period
For the Years Ended
December 31,
2015
2016
2014
$ 42
$ 187
$ 171
295
(8)
153
183
(41)
44
1
32
110
(32)
(128)
651
(586)
12
(30)
(31)
(12)
(647)
(41)
4
(11)
(136)
187
(3)
—
4
5
9
$
256
(46)
150
54
(43)
—
(5)
(21)
(46)
(14)
(99)
373
(544)
54
—
3
10
(477)
(40)
208
(22)
(146)
112
(9)
103
(1)
6
5
$
212
—
175
37
7
(2)
5
(37)
(14)
(11)
(157)
386
(567)
9
—
(3)
1
(560)
(47)
412
(184)
(86)
80
(4)
171
(3)
9
6
$
See the Combined Notes to Consolidated Financial Statements
292
Potomac Electric Power Company
Balance Sheets
ASSETS
Table of Contents
(In millions)
Current assets
Cash and cash equivalents
Restricted cash and cash equivalents
Accounts receivable, net
Customer
Other
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
December 31,
2016
2015
$
9
33
$
5
2
235
150
63
162
32
684
5,571
690
102
282
6
1,080
$7,335
230
261
67
140
21
726
5,162
661
68
287
4
1,020
$6,908
See the Combined Notes to Consolidated Financial Statements
293
Table of Contents
(In millions)
Current liabilities
Potomac Electric Power Company
Balance Sheets
LIABILITIES AND SHAREHOLDER’S EQUITY
Short-term borrowings
Long-term debt due within one year
Accounts payable
Accrued expenses
Payables to affiliates
Customer deposits
Regulatory liabilities
Merger related obligation
Other
Total current liabilities
Long-term debt
Deferred credits and other liabilities
Regulatory liabilities
Deferred income taxes and unamortized investment tax credits
Non-pension postretirement benefit obligations
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
December 31,
2016
2015
$
23
16
209
113
74
53
11
68
29
596
2,333
20
1,910
43
133
2,106
5,035
$
64
11
145
119
30
46
15
—
25
455
2,340
29
1,723
49
72
1,873
4,668
1,309
991
2,300
$7,335
1,122
1,118
2,240
$6,908
See the Combined Notes to Consolidated Financial Statements
294
Table of Contents
(In millions)
Balance, December 31, 2013
Net income
Common stock dividends
Contribution from Parent
Balance, December 31, 2014
Net income
Common stock dividends
Contribution from Parent
Balance, December 31, 2015
Net income
Common stock dividends
Contribution from Parent
Balance, December 31, 2016
Potomac Electric Power Company
Statements of Changes in Shareholder’s Equity
Common
Stock
$
930
—
—
80
$ 1,010
—
—
112
$ 1,122
—
—
187
$ 1,309
Retained
Earnings
992
$
171
(86)
—
$ 1,077
187
(146)
—
$ 1,118
42
(169)
—
991
$
Total
Shareholder’s
Equity
$
$
$
$
1,922
171
(86)
80
2,087
187
(146)
112
2,240
42
(169)
187
2,300
See the Combined Notes to Consolidated Financial Statements
295
Table of Contents
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296
Table of Contents
Delmarva Power & Light Company
Statements of Operations and Comprehensive Income
(In millions)
Operating revenues
Electric operating revenues
Natural gas operating revenues
Operating revenues from affiliates
Total operating revenues
Operating expenses
Purchased power
Purchased fuel
Purchased power from affiliate
Operating and maintenance
Operating and maintenance from affiliates
Depreciation, amortization and accretion
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 (loss) income attributable to common shareholder
Comprehensive (loss) income
For the Years Ended
December 31,
2015
2016
2014
$1,122
148
7
1,277
369
60
154
422
19
157
55
1,236
9
50
(50)
13
(37)
13
22
(9)
(9)
$
$
$1,132
164
6
1,302
555
79
—
303
1
148
51
1,137
—
165
(50)
10
(40)
125
49
76
76
$
$
$1,081
194
7
1,282
536
104
—
266
1
122
46
1,075
—
207
(48)
10
(38)
169
65
$ 104
$ 104
See the Combined Notes to Consolidated Financial Statements
297
Table of Contents
Delmarva Power & Light Company
Statements of Cash Flows
(In millions)
Cash flows from operating activities
Net (loss) income
Adjustments to reconcile net (loss) income to net cash flows provided by operating activities:
For the Years Ended December 31,
2015
2016
2014
$
(9)
$
76
$
104
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
Collateral (paid) received, net
Income taxes
Pension and non-pension postretirement benefit contributions
Other assets and liabilities
Net cash flows provided by operating activities
Cash flows from investing activities
Capital expenditures
Proceeds from sales of long-lived assets
Change in restricted cash
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
Contribution from parent
Other financing activities
Net cash flows provided by financing activities
Increase in cash and cash equivalents
Cash and cash equivalents at beginning of period
Cash and cash equivalents at end of period
157
109
114
(5)
13
—
(4)
1
28
(22)
(72)
310
(349)
9
—
4
(336)
(105)
175
(100)
(54)
152
(1)
67
41
5
46
$
148
73
33
(24)
3
6
(8)
(1)
(26)
—
(14)
266
(352)
—
5
2
(345)
(1)
200
(100)
(92)
75
(2)
80
1
4
5
$
122
110
22
1
(6)
(2)
—
—
(1)
—
(82)
268
(352)
—
(5)
(1)
(358)
(41)
204
(100)
(100)
130
(1)
92
2
2
4
$
See the Combined Notes to Consolidated Financial Statements
298
Delmarva Power & Light Company
Balance Sheets
ASSETS
Table of Contents
(In millions)
Current assets
Cash and cash equivalents
Accounts receivable, net
Customer
Other
Receivables from affiliates
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
December 31,
2016
2015
$
46
$
5
136
63
3
154
96
—
7
32
59
24
370
3,273
289
8
206
7
510
$4,153
8
32
72
21
388
3,070
299
8
202
2
511
$3,969
See the Combined Notes to Consolidated Financial Statements
299
Table of Contents
(In millions)
Current liabilities
Delmarva Power & Light Company
Balance Sheets
LIABILITIES AND SHAREHOLDER’S EQUITY
Short-term borrowings
Long-term debt due within one year
Accounts payable
Accrued expenses
Payables to affiliates
Customer deposits
Regulatory liabilities
Merger related obligation
Other
Total current liabilities
Long-term debt
Deferred credits and other liabilities
Regulatory liabilities
Deferred income taxes and unamortized investment tax credits
Non-pension postretirement benefit obligations
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
December 31,
2016
2015
$ —
119
88
36
38
36
43
13
8
381
1,221
97
1,056
19
53
1,225
2,827
$ 105
204
109
31
20
31
49
—
15
564
1,061
111
945
19
32
1,107
2,732
764
562
1,326
$4,153
612
625
1,237
$3,969
See the Combined Notes to Consolidated Financial Statements
300
Table of Contents
(In millions)
Balance, December 31, 2013
Net income
Common stock dividends
Contribution from parent
Balance, December 31, 2014
Net income
Common stock dividends
Contribution from parent
Balance, December 31, 2015
Net loss
Common stock dividends
Contribution from parent
Balance, December 31, 2016
Delmarva Power & Light Company
Statements of Changes in Shareholder’s Equity
Common
Stock
$
407
—
—
130
$
537
—
—
75
$
612
—
—
152
764
$
Retained
Earnings
637
$
104
(100)
—
641
$
76
(92)
—
625
$
(9)
(54)
—
562
$
Total
Shareholder’s
Equity
$
$
$
$
1,044
104
(100)
130
1,178
76
(92)
75
1,237
(9)
(54)
152
1,326
See the Combined Notes to Consolidated Financial Statements
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302
Table of Contents
Atlantic City Electric Company and Subsidiary Company
Consolidated Statements of Operations and Comprehensive Income
(In millions)
Operating revenues
Electric operating revenues
Operating revenues from affiliates
Total operating revenues
Operating expenses
Purchased power
Purchased power from affiliates
Operating and maintenance
Operating and maintenance from affiliates
Depreciation, amortization and accretion
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)
(Loss) income before income taxes
Income taxes
Net (loss) income attributable to common shareholder
Comprehensive (loss) income
For the Years Ended
December 31,
2015
2016
2014
$1,254
3
1,257
$1,291
4
1,295
614
37
410
18
165
7
1,251
1
7
(62)
9
(53)
(46)
(4)
(42)
(42)
$
$
708
—
268
3
175
7
1,161
—
134
(64)
3
(61)
73
33
40
40
$
$
$1,206
4
1,210
664
—
247
3
155
4
1,073
—
137
(64)
3
(61)
76
30
46
46
$
$
See the Combined Notes to Consolidated Financial Statements
303
Table of Contents
Atlantic City Electric Company and Subsidiary Company
Consolidated Statements of Cash Flows
(In millions)
Cash flows from operating activities
Net (loss) income
Adjustments to reconcile net (loss) income to net cash from 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, accrued expenses and other current liabilities
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 sale of long-lived assets
Changes in restricted cash
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
Repayment of term loan
Dividends paid on common stock
Contributions from parent
Other financing activities
Net cash flows provided by (used in) financing activities
Increase (decrease) in cash and cash equivalents
Cash and cash equivalents at beginning of period
Cash and cash equivalents at end of period
For the Years Ended
December 31,
2016
2015
2014
$ (42)
$ 40
$ 46
165
22
155
(8)
13
(1)
9
174
(17)
(85)
385
(311)
2
(2)
2
(309)
(5)
—
(48)
—
(63)
139
(1)
22
98
3
$ 101
175
31
37
(67)
1
(1)
9
(34)
(2)
67
256
(300)
—
(6)
—
(306)
(122)
150
(58)
—
(12)
95
(2)
51
1
2
3
$
155
38
26
6
—
4
(17)
(20)
(3)
24
259
(225)
—
—
1
(224)
7
150
(66)
(100)
(26)
—
(1)
(36)
(1)
3
2
$
See the Combined Notes to Consolidated Financial Statements
304
Table of Contents
Atlantic City Electric Company and Subsidiary Company
Consolidated Balance Sheets
ASSETS
(In millions)
Current assets
Cash and cash equivalents
Restricted cash and cash equivalents
Accounts receivable, net
Customer
Other
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)
December 31,
2016
2015
$ 101
9
$
3
12
125
44
22
96
2
399
2,521
405
4
84
44
537
$3,457
156
242
23
98
12
546
2,322
414
4
82
19
519
$3,387
See the Combined Notes to Consolidated Financial Statements
305
Table of Contents
(In millions)
Current liabilities
Atlantic City Electric Company and Subsidiary Company
Consolidated Balance Sheets
LIABILITIES AND SHAREHOLDER’S EQUITY
Short-term borrowings
Long-term debt due within one year
Accounts payable
Accrued expenses
Payables to affiliates
Customer deposits
Regulatory liabilities
Merger related obligation
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
December 31,
2016
2015
$ —
35
132
38
29
33
25
20
8
320
1,120
917
34
—
32
983
2,423
$
5
48
96
70
16
30
18
—
14
297
1,153
885
33
7
12
937
2,387
912
122
1,034
$3,457
773
227
1,000
$3,387
(a) ACE’s consolidated assets include $32 million and $30 million at December 31, 2016 and 2015, respectively, of ACE’s consolidated VIE that can only be used to settle the
liabilities of the VIE. ACE’s consolidated liabilities include $126 million and $172 million at December 31, 2016 and 2015, respectively, of ACE’s consolidated VIE for which
the VIE creditors do not have recourse to ACE. See Note 2—Variable Interest Entities.
See the Combined Notes to Consolidated Financial Statements
306
Table of Contents
(In millions)
Balance, December 31, 2013
Net income
Common stock dividends
Balance, December 31, 2014
Net income
Common stock dividends
Contribution from parent
Balance, December 31, 2015
Net loss
Common stock dividends
Contribution from parent
Balance, December 31, 2016
Atlantic City Electric Company and Subsidiary Company
Consolidated Statements of Changes in Shareholder’s Equity
Common
Stock
$
678
—
—
$
678
—
—
95
$
773
—
—
139
912
$
$
Retained
Earnings
179
$
46
(26)
199
40
(12)
—
227
$
(42)
(63)
—
122
$
Total
Shareholder’s
Equity
$
$
$
$
857
46
(26)
877
40
(12)
95
1,000
(42)
(63)
139
1,034
See the Combined Notes to Consolidated Financial Statements
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Table of Contents
Combined Notes to Consolidated Financial Statements
(Dollars in millions, except per share data unless otherwise noted)
Index to Combined Notes to Consolidated Financial Statements
The notes to the consolidated financial statements that follow are a combined presentation. The following list indicates the registrants to which
the footnotes apply:
Registrant
Exelon Corporation
Exelon Generation Company,
Applicable Notes
1 2 3 4 5 6 7 8 9 10 11 12 13 14 15 16 17 18 19 20 21 22 23 24 25 26 27 28
• • • • • • • • • • • • • • • • • • • • • • • • • • • •
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. Significant Accounting Policies (All Registrants)
Description of Business (All Registrants)
Exelon is a utility services holding company engaged through its principal subsidiaries in the energy generation and energy distribution and
transmission businesses. Prior to March 23, 2016, Exelon’s principal, wholly owned subsidiaries included Generation, ComEd, PECO and BGE. On
March 23, 2016, in conjunction with the Amended and Restated Agreement and Plan of Merger (the PHI Merger Agreement), Purple Acquisition
Corp, a wholly owned subsidiary of Exelon, merged with and into PHI, with PHI continuing as the surviving entity as 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. Refer to Note 4—Mergers, Acquisitions, and Dispositions for further information regarding the merger
transaction.
The energy generation business includes:
•
Generation : Generation, physical delivery and marketing of power across multiple geographical regions through its customer-facing
business, Constellation. 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.
The energy delivery businesses include:
•
•
•
ComEd : Purchase and regulated retail sale of electricity and the provision of electric distribution and transmission services in northern
Illinois, including the City of Chicago.
PECO : Purchase and regulated retail sale of electricity and the provision of electric 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 natural gas
distribution services in the Pennsylvania counties surrounding the City of Philadelphia.
BGE : Purchase and regulated retail sale of electricity and the provision of electric 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 natural gas
distribution services in central Maryland, including the City of Baltimore.
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Combined Notes to Consolidated Financial Statements—(Continued)
(Dollars in millions, except per share data unless otherwise noted)
•
•
Pepco : Purchase and regulated retail sale of electricity and the provision of electric distribution and transmission services in the District of
Columbia and major portions of Prince George’s County and Montgomery County in Maryland.
DPL : Purchase and regulated retail sale of electricity and the provision of electric distribution and transmission services in portions of
Maryland and Delaware, and the purchase and regulated retail sale of natural gas and the provision of natural gas distribution services in
northern Delaware.
•
ACE : Purchase and regulated retail sale of electricity and the provision of electric distribution and transmission services in 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. All Equity in earnings (losses) from unconsolidated affiliates have been presented below Income taxes in the Registrants’ Consolidated
Statements of Operations and Comprehensive Income starting in the first quarter of 2015.
Pursuant to the acquisition of 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 requires the assets acquired
and liabilities assumed by Exelon to be reported in Exelon’s financial statements at fair value, with any excess of the purchase price over the fair
value of net assets acquired reported as goodwill. Exelon has pushed-down the application of the acquisition method of accounting to the
consolidated financial statements of PHI such that the assets and liabilities of PHI are similarly 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 financial positions and the results of operations 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.
For financial statement purposes, beginning on March 24, 2016, disclosures that had solely related to PHI, Pepco, DPL or ACE activities now
also apply to Exelon, 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. The costs of BSC, including support services, are directly
charged or allocated to the applicable subsidiaries using a cost-causative allocation method. Corporate governance-type costs that cannot be
directly assigned are allocated based on a Modified Massachusetts Formula, which is a method that utilizes a combination of gross revenues, total
assets and direct labor costs for the allocation base. The results of Exelon’s corporate operations are presented as “Other” within the consolidated
financial statements and include intercompany eliminations unless otherwise disclosed.
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Combined Notes to Consolidated Financial Statements—(Continued)
(Dollars in millions, except per share data unless otherwise noted)
PHISCO, a wholly owned subsidiary of PHI, provides a variety of support services at cost, including legal, accounting, 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 PHI Service Company and the participating operating subsidiaries.
Exelon owns 100% of all of its significant consolidated subsidiaries, including PHI, either directly or indirectly, except for ComEd, of which
Exelon owns more than 99%. As of December 31, 2016, Exelon owned none of BGE’s preferred securities, which BGE redeemed in 2016. Exelon
has reflected the third-party interests in ComEd, which totaled less than $1 million at December 31, 2016 and December 31, 2015, as equity, and
BGE’s preference stock as BGE preference stock not subject to mandatory redemption in its consolidated financial statements. BGE is subject to
some ring-fencing measures established by order of the MDPSC. As part of this arrangement, BGE common stock is held directly by RF Holdco
LLC, which is an indirect subsidiary of Exelon. GSS Holdings (BGE Utility), an unrelated party, holds a nominal non-economic interest in RF Holdco
LLC with limited voting rights on specified matters. PHI is subject to some ring-fencing measures established by orders of the DCPSC, DPSC,
MDPSC and NJBPU, pursuant to which all of the membership interest in PHI is held directly by PH Holdco LLC, which is an indirect subsidiary of
Exelon. GSS Holdings (PH Utility), Inc., an unrelated party, holds a nominal non-economic interest in PH Holdco LLC with limited voting rights on
specified matters. PHI owns 100% of its subsidiaries including Pepco, DPL and ACE.
Generation owns 100% of all of its significant consolidated subsidiaries, either directly or indirectly, except for certain variable interest entities,
including CENG, of which Generation holds a 50.01% interest. The remaining interests are included in noncontrolling interests on Exelon’s and
Generation’s Consolidated Balance Sheets. See Note 2—Variable Interest Entities for further discussion 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. A controlling financial interest is evidenced by either a voting interest greater than 50% in which the Registrant can
exercise control over the operations and policies of the investee, or the results of a model that identifies the Registrant or one of its subsidiaries as
the primary beneficiary of a VIE. Where the Registrants do not have a controlling financial interest in an entity, proportionate consolidation, equity
method accounting or cost method accounting 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, PECO and BGE. Under the equity method, 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 the cost method if they lack significant influence, which generally results when they hold less than 20% of the common stock of an entity. Under
the cost method, the Registrants report their investments at cost and recognize income only to the extent dividends or distributions are received.
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Combined Notes to Consolidated Financial Statements—(Continued)
(Dollars in millions, except per share data unless otherwise noted)
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.
Reclassifications (All Registrants)
Certain prior year amounts in the Registrants’ Consolidated Statements of Operations and Comprehensive Income, Consolidated Balance
Sheets and Consolidated Statements of Cash Flows have been reclassified between line items for comparative purposes. The reclassifications did
not affect any of the Registrants’ net income, financial positions, or cash flows from operating activities.
Certain prior year amounts in the Consolidated Statements of Operations and Comprehensive Income, Consolidated Balance Sheets and
Consolidated Statements of Cash Flows of PHI, Pepco, DPL and ACE have been reclassified to conform the presentation of these amounts to the
current period presentation in Exelon’s financial statements. Most significantly for PHI, Pepco, DPL and ACE, current regulatory assets and liabilities
have been presented separately from the non-current portions in each respective Consolidated Balance Sheet where recovery or refund is expected
within the next 12 months. Additionally, for PHI, Pepco, DPL and ACE, the removal cost within Accumulated depreciation was reclassified to the
Regulatory liability or Regulatory asset account to align with Exelon’s presentation. The reclassifications were not considered errors in the prior
financial statements.
Accounting for the Effects of Regulation (Exelon, ComEd, PECO, BGE, PHI, Pepco, DPL and ACE)
The Registrants apply the authoritative guidance for accounting for certain types of regulation, which requires them to record in their
consolidated financial statements the effects of cost-based rate regulation 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 are set at levels that will recover the entities’ costs 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, the PAPUC, the MDPSC, the DCPSC, the DPSC and the 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 believes that it is probable that its currently
recorded regulatory assets and liabilities will be recovered and settled, respectively, in future rates. Exelon and the Utility Registrants continue 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)
evaluate their respective abilities to continue to apply the authoritative guidance for accounting for certain types of regulation, including consideration
of current events in their respective regulatory and political environments. 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 results of operations and financial positions. See Note 3—Regulatory Matters
for additional information.
ACE has a recovery mechanism for purchased power costs associated with BGS. ACE records a deferred energy supply costs regulatory
asset or regulatory liability for under or over-recovered costs that are expected to be recovered from or refunded to ACE customers, respectively. In
the first quarter of 2016, ACE changed its method of accounting for determining under or over-recovered costs in this recovery mechanism to include
unbilled revenues in the determination of under or over-recovered costs. ACE believes this change is preferable as it better reflects the economic
impacts of dollar-for-dollar cost recovery mechanisms. ACE applied the change retrospectively. The impact of the change was a $12 million
reduction to ACE’s opening Retained earnings as of January 1, 2014 with a corresponding reduction to Regulatory assets. The impact of the change
on Net income attributable to common shareholder was an increase of $2 million and $1 million for the years ended December 31, 2015 and
December 31, 2014, respectively.
The 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. Operating revenues are recorded as service is rendered or energy is delivered to customers. 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 its best estimates
of the distribution and transmission revenue impacts resulting from changes in rates that ComEd believes are probable of approval by the ICC and
FERC in accordance with its formula rate mechanisms. BGE, Pepco, DPL and ACE record their best estimate of the transmission revenue impacts
resulting from changes in rates that they each believe are probable of approval by FERC in accordance with their formula rate mechanisms. See
Note 3—Regulatory Matters and Note 6—Accounts Receivable for further information.
RTOs and ISOs. In RTO and ISO markets that facilitate the dispatch of energy and energy-related products, the Registrants generally report
sales and purchases conducted on a net hourly basis in either revenues or purchased power on their Consolidated Statements of Operations and
Comprehensive Income, the classification of which depends on the net hourly activity. In addition, capacity revenue and expense classification is
based on the net sale or purchase position of the Company in the different RTOs and ISOs.
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. For example, gas transactions may be used to hedge the sale of power. This will result
in the change in fair value recorded through revenue. To the
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Table of Contents
Combined Notes to Consolidated Financial Statements—(Continued)
(Dollars in millions, except per share data unless otherwise noted)
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 on its Consolidated Balance Sheets. Refer to
Note 3—Regulatory Matters and Note 13—Derivative Financial Instruments for further information.
Proprietary Trading Activities. Exelon and Generation account for Generation’s trading activities under the provisions of the authoritative
guidance for accounting for contracts involved in energy trading and risk management activities, which require energy revenues and costs related to
energy trading contracts to be presented on a net basis in the Consolidated Statements of Operations and Comprehensive Income. Commodity
derivatives used for trading purposes are accounted for using the mark-to-market method with unrealized gains and losses recognized in operating
revenues. Refer to Note 13—Derivative Financial Instruments for further information.
Income Taxes (All Registrants)
Deferred Federal and state income taxes are provided on all significant temporary differences between the book basis and the tax basis of
assets and liabilities and for tax benefits carried forward. Investment tax credits have been deferred on the Registrants’ Consolidated Balance
Sheets and are recognized in book income over the life of the related property. In accordance with applicable authoritative guidance, 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 on their Consolidated Statements of Operations and
Comprehensive Income.
In the first quarter of 2016, PHI, Pepco, DPL and ACE changed their accounting for classification of interest on uncertain tax positions. PHI,
Pepco, DPL and ACE have reclassified interest on uncertain tax positions as Interest expense from Income tax expense in the Consolidated
Statements of Operations and Comprehensive Income. GAAP does not address the preferability of one acceptable method of accounting over the
other for the classification of interest on uncertain tax positions. However, PHI, Pepco, DPL and ACE believe this change is preferable for
comparability of their financial statements with the financial statements of the other Registrants in the combined filing, for consistency with FERC
classification and for a more appropriate representation of the effective tax rate as they manage the settlement of uncertain tax positions and interest
expense separately. PHI, Pepco, DPL and ACE applied the change retrospectively. The reclassification in the Consolidated Statements of
Operations and Comprehensive Income for the year ended December 31, 2015 is $34 million and $4 million for PHI and Pepco, respectively, and for
the year ended December 31, 2014 is $1 million for both Pepco and ACE. The impact on all other PHI Registrants for years ended December 31,
2015 and December 31, 2014 is less than $1 million.
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 15—Income Taxes for further information.
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(Dollars in millions, except per share data unless otherwise noted)
Taxes Directly Imposed on Revenue-Producing Transactions (All Registrants)
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. See Note 25—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.
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, 2016 and
2015, Exelon Corporate’s restricted cash and cash equivalents primarily represented restricted funds for payment of medical, dental, vision and long-
term disability benefits. Generation’s restricted cash and cash equivalents primarily included cash at various project-specific non-recourse financing
structures for debt service and financing of operations of the underlying entities, see Note 14—Debt and Credit Agreements for additional information
on Generation’s project- specific financing structures. ComEd’s restricted cash primarily represented cash collateral held from suppliers associated
with ComEd’s energy and REC procurement contracts. PECO’s restricted cash primarily represented funds from the sales of assets that were
subject to PECO’s mortgage indenture. BGE’s restricted cash primarily represented funds restricted at its consolidated variable interest entity for
repayment of rate stabilization bonds and cash collateral held from suppliers. PHI Corporate’s restricted cash and cash equivalents primarily
represented funds restricted for the payment of merger commitments and cash collateral held from its utility suppliers. Pepco’s restricted cash and
cash equivalents primarily represented funds restricted for the payment of merger commitments and collateral held from its utility suppliers. DPL’s
restricted cash and cash equivalents primarily represented cash collateral held from suppliers associated with procurement contracts. ACE’s
restricted cash and cash equivalents primarily represented funds restricted at its consolidated variable interest entity for repayment of transition
bonds and cash collateral held from suppliers.
Restricted cash and cash equivalents not available to satisfy current liabilities are classified as noncurrent assets. As of December 31, 2016
and 2015, Exelon’s and Generation’s NDT funds, which are designated to satisfy future decommissioning obligations, were classified as noncurrent
assets. As of December 31, 2016, Exelon, Generation, ComEd, PECO, BGE, PHI and Pepco had investments in Rabbi trusts classified as
noncurrent assets.
Allowance for Uncollectible Accounts (All Registrants)
The allowance for uncollectible accounts reflects the Registrants’ best estimates of losses on the accounts receivable balances. For
Generation, the allowance is based on accounts receivable aging
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Combined Notes to Consolidated Financial Statements—(Continued)
(Dollars in millions, except per share data unless otherwise noted)
historical experience and other currently available information. ComEd, PECO and BGE 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. At December 31, 2015, Pepco, DPL and ACE estimated the allowance for uncollectible accounts based on specific identification of
material amounts at risk by customer and maintained a reserve based on their historical collection experience. At December 31, 2016, Pepco, DPL
and ACE aligned the estimation of their allowance for uncollectible accounts to be consistent with ComEd, PECO and BGE, as described above.
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 historical average charge-
offs as a percentage of accounts receivable in each risk segment. Utility Registrants customers’ 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. See Note
3—Regulatory Matters for additional information regarding the regulatory recovery of uncollectible accounts receivable at ComEd.
Variable Interest Entities (All Registrants)
Exelon accounts for its investments in and arrangements with VIEs based on the authoritative guidance which includes 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, meaning (1) has the power to direct matters that most significantly impact the activities of the VIE, and (2) has the obligation to
absorb losses or the right to receive benefits of the VIE that could potentially be significant to the VIE,
•
•
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. Fossil fuel inventory includes natural gas held in storage, propane and oil. The costs of natural gas, propane and oil are generally
included in inventory when purchased and charged to purchased power and fuel expense at weighted average cost when used or sold.
Materials and Supplies. Materials and supplies inventory generally includes transmission, distribution and generating plant materials.
Materials are generally charged to inventory when purchased and expensed or capitalized to property, plant and equipment, as appropriate, at
weighted average cost when installed or used.
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Combined Notes to Consolidated Financial Statements—(Continued)
(Dollars in millions, except per share data unless otherwise noted)
Emission Allowances. Emission allowances are included in inventory (for emission allowances exercisable in the current year) and other
deferred debits (for emission allowances that are exercisable beyond one year) and charged to purchased power and fuel expense at weighted
average cost as they are used in operations.
Marketable Securities (All Registrants)
All marketable securities are reported at fair value. Marketable securities held in the NDT funds are classified as trading securities, and all
other securities are classified as available-for-sale securities. 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. Unrealized gains
and losses, net of tax, for Exelon’s available-for-sale securities are reported in OCI. Any decline in the fair value of Exelon’s
available-for-sale securities below the cost basis is reviewed to determine if such decline is other-than-temporary. If the decline is determined to be
other-than-temporary, the cost basis of the available-for-sale securities is written down to fair value as a new cost basis and the amount of the write-
down is included in earnings. See Note 3—Regulatory Matters for additional information regarding ComEd’s and PECO’s regulatory assets and
liabilities and Note 12—Fair Value of Financial Assets and Liabilities and Note 16—Asset Retirement Obligations for 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 and Exelon Corporate and AFUDC for regulated property
at ComEd, PECO, BGE, Pepco, DPL and ACE. The cost of repairs and maintenance, including planned major maintenance activities and minor
replacements of property, is charged to 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. DOE SGIG funds reimbursed to PECO, BGE, Pepco and
ACE 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
method 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 in accordance with the
composite method of depreciation. 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 Utility
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Combined Notes to Consolidated Financial Statements—(Continued)
(Dollars in millions, except per share data unless otherwise noted)
Registrants’ actual incurred removal costs are applied against a related regulatory liability. 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.
See Note 7—Property, Plant and Equipment, Note 10—Jointly Owned Electric Utility Plant and Note 25—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.
Prior to May 16, 2014, the estimated disposal cost of SNF was established per the Standard Waste Contract with the DOE and was expensed
through fuel expense at one mill ($0.001) per kWh of net nuclear generation. Effective May 16, 2014, the SNF disposal fee was set to zero by the
DOE and Exelon and Generation are not accruing any further costs related to SNF disposal fees until a new fee structure goes into effect. 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 24—Commitments and Contingencies for additional information regarding the SNF disposal fee.
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.
New Site Development Costs (Exelon and Generation)
New site development costs represent the costs incurred in the assessment and design of new power generating facilities. Such costs are
capitalized when management considers project completion to be probable, primarily based on management’s determination that the project is
economically and operationally feasible, management and/or the Exelon board of directors has approved the project and has committed to a plan to
develop it, and Exelon and Generation have received the required regulatory approvals or management believes the receipt of required regulatory
approvals is probable. As of December 31, 2016 and 2015, Generation has capitalized $1.7 billion and $1.3 billion, respectively, to Property, plant
and equipment, net on its Consolidated Balance Sheets. Capitalized development costs are charged to Operating and maintenance expense when
project completion is no longer probable. New site development costs incurred prior to a project’s completion being deemed probable are expensed
as incurred. Approximately $30 million, $22 million and $13 million of costs were expensed by Exelon and Generation for the years ended
December 31, 2016, 2015, and 2014, respectively. These costs are primarily related to the possible development of new power generating facilities
with the exception of approximately $13 million of costs expensed in 2016 which relate to projects for which completion is no longer probable.
Capitalized Software Costs (All Registrants)
Costs 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
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Combined Notes to Consolidated Financial Statements—(Continued)
(Dollars in millions, except per share data unless otherwise noted)
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. The following table presents net unamortized capitalized software costs and amortization of capitalized software costs by year:
Net unamortized software costs
December 31, 2016
December 31, 2015
Amortization of capitalized software costs
2016
2015
2014
PHI
Net unamortized software costs
Exelon Generation ComEd
PECO
BGE
$ 808 $
633
173 $ 213 $ 91 $164 $
180
172
86
178
Pepco
1
—
Exelon Generation ComEd
$ 255 $
208
186
72 $
73
59
BGE
PECO
Pepco
62 $ 33 $ 44 $ —
(2)
47
2
45
33
28
46
43
DPL
$
1 $
1
ACE
1
1
DPL
ACE
$ — $ —
—
—
—
—
Successor
December 31,
2016
Predecessor
December 31,
2015
$
153 $
172
Successor
March 24,
2016 to
December 31,
2016
January 1,
2016 to
March 23,
2016
Predecessor
For the Year
Ended
December 31,
2015
For the Year
Ended
December 31,
2014
$
29 $
8 $
36 $
30
PHI
Amortization of capitalized software costs
Depreciation, Depletion 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 composite method in which depreciation is calculated using the average estimated service life of assets within a
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 Utility Registrants are primarily based on each
company’s most recent depreciation studies of historical asset retirement and removal cost experience. 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. For its nuclear generating facilities, except for Oyster Creek and Clinton,
Generation estimates each unit will operate through the full term of its initial 20-year operating license renewal period. See Note 9—Early Nuclear
Plant Retirements for additional information on the impacts of expected and potential early plant retirements. The estimated service lives of
Generation’s hydroelectric generating facilities are based on the remaining useful lives of the stations, which assume a license renewal extension of
40 years.
See Note 7—Property, Plant and Equipment for further 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 Registrants’ Consolidated Statements of Operations
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Combined Notes to Consolidated Financial Statements—(Continued)
(Dollars in millions, except per share data unless otherwise noted)
and Comprehensive Income. Amortization of ComEd’s distribution formula rate regulatory asset and ComEd’s, BGE’s, Pepco’s, DPL’s and ACE’s
transmission formula rate regulatory assets is recorded to Operating revenues.
Amortization of income tax related regulatory assets and liabilities are generally recorded to Income tax expense. With the exception of the
regulatory assets and liabilities discussed above, when the recovery period is more than one year, the amortization is generally recorded to
Depreciation and amortization in the Registrants’ Consolidated Statements of Operations and Comprehensive Income.
See Note 3—Regulatory Matters and Note 25—Supplemental Financial Information for additional information regarding Generation’s nuclear
fuel, Generation’s ARC and the amortization of the Utility Registrants’ regulatory assets.
Asset Retirement Obligations (All Registrants)
The authoritative guidance for accounting for AROs requires the recognition of a liability for a legal obligation to perform an asset retirement
activity even though the timing and/or method of settlement may be conditional on a future event. To estimate its decommissioning obligation related
to its nuclear generating stations, 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 future cash flow models and discount rates. Generation generally 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 decommissioning scenarios. 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 (such as a change in assumed operating life for a nuclear plant). 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. The liabilities associated with Exelon’s non-nuclear AROs are adjusted on an ongoing rotational
basis, at least once every five years unless circumstances warrant more frequent updates. Changes to the recorded value of an ARO result from the
passage of new laws and regulations, revisions to either the timing or amount of estimated undiscounted cash flows, and estimates of cost
escalation factors. 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 16—Asset Retirement Obligations for additional information.
Capitalized Interest and AFUDC (All Registrants)
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.
Exelon, ComEd, PECO, BGE, PHI, Pepco, DPL and ACE apply the authoritative guidance for accounting for certain types of regulation to
calculate AFUDC, which is the cost, during the period of construction, of debt and equity funds used to finance construction projects for regulated
operations.
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Combined Notes to Consolidated Financial Statements—(Continued)
(Dollars in millions, except per share data unless otherwise noted)
AFUDC is recorded to construction work in progress and as a non-cash credit to AFUDC 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.
The following table summarizes total incurred interest, capitalized interest and credits to AFUDC by year:
Exelon (a) Generation (a) ComEd
2016 Total incurred interest (b)
Capitalized interest
Credits to AFUDC debt and equity
2015 Total incurred interest (b)
Capitalized interest
Credits to AFUDC debt and equity
2014 Total incurred interest (b)
Capitalized interest
Credits to AFUDC debt and equity
$ 1,678 $
108
98
$ 1,170 $
79
44
$ 1,144 $
63
37
PHI
Total incurred interest (b)
Credits to AFUDC debt and equity
BGE
—
30
—
22
Pepco
PECO
472 $ 469 $ 127 $114 $ 137
—
—
107
29
11
—
445 $ 336 $ 116 $113 $ 131
—
—
79
—
19
7
419 $ 323 $ 115 $118 $ 121
—
—
16
8
—
5
—
9
—
24
—
28
63
—
DPL
$ 52
—
7
$ 51
—
2
$ 49
—
3
ACE
$ 65
—
9
$ 65
—
2
$ 65
—
2
Successor
March 24,
2016 to
December 31,
2016
January 1,
2016 to
March 23,
2016
Predecessor
For the Year
Ended
December 31,
2015
For the Year
Ended
December 31,
2014
$
207 $
35
68 $
10
289 $
23
277
21
(a) On April 1, 2014, Generation assumed operational control of CENG’s nuclear fleet. As a result, the 2014 financial results include CENG’s financial position and results of
operations beginning April 1, 2014.
Includes interest expense to affiliates.
(b)
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 amortization method over the term of the guarantee. See Note 24—Commitments and
Contingencies for additional information.
Asset Impairments (All Registrants)
Long-Lived Assets. 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
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Combined Notes to Consolidated Financial Statements—(Continued)
(Dollars in millions, except per share data unless otherwise noted)
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 less costs to sell.
Cash flows for long-lived assets and asset groups are determined at the lowest level for which identifiable cash flows are largely independent
of the cash flows of other assets and liabilities. The cash flows from the generating units are generally evaluated at a regional portfolio level along
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 generation assets (typically contracted renewables). See Note 8—
Impairment of Long-Lived Assets for additional information.
Goodwill. Goodwill represents the excess of the purchase price paid over the estimated fair value of the 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 11—
Intangible Assets for additional information regarding Exelon’s, Generation’s, ComEd’s and PHI’s goodwill.
Equity Method Investments. 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 project 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 and Equity Security Investments. Exelon and Generation regularly monitor and evaluate debt and equity 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.
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. Additionally, derivatives that qualify and are designated for hedge accounting are classified as either hedges of the fair
value of a recognized asset or liability or of an unrecognized firm commitment (fair value hedge) or hedges of a forecasted transaction or the
variability of cash flows to be received or paid related to a recognized asset or liability (cash flow hedge). For fair value hedges, changes in fair
values for both the derivative and the underlying hedged exposure are recognized in earnings each period. For cash flow hedges, the portion of the
derivative gain or loss that is effective in offsetting the change in the cost or value of the underlying exposure is deferred in AOCI and later
reclassified into earnings when the underlying transaction occurs. Gains and losses from the ineffective portion of any hedge are recognized in
earnings immediately. For derivative contracts intended to serve as economic hedges and that are not
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Combined Notes to Consolidated Financial Statements—(Continued)
(Dollars in millions, except per share data unless otherwise noted)
designated or do not qualify for hedge accounting or the normal purchases and normal sales exception, changes in the fair value of the derivatives
are recognized in earnings each period, except for the Utility Registrants where 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. See Note 3—Regulatory Matters and Note 13—Derivative Financial Instruments
for additional information. Amounts classified in earnings are included in revenue, purchased power and fuel, interest expense or other, net on the
Consolidated Statements of Operations and Comprehensive Income based on the activity the transaction is economically hedging. For energy-
related derivatives entered into for proprietary trading purposes, which are subject to Exelon’s Risk Management Policy, changes in the fair value of
the derivatives are recognized in earnings each period. All amounts classified in earnings related to proprietary trading are included in revenue on
the Consolidated Statements of Operations and Comprehensive Income. 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.
For commodity derivative contracts Generation no longer utilizes the election provided for by the cash flow hedge designation and
de-designated all of its existing cash flow hedges prior to the March 2012 merger of Exelon and Constellation. Because the underlying forecasted
transactions at that time remained probable, the fair value of the effective portion of these cash flow hedges was frozen in AOCI and was reclassified
to results of operations when the forecasted purchase or sale of the energy commodity occurred through March 31, 2015. Accordingly, all derivatives
executed to hedge economic risk related to commodities are recorded at fair value with changes in fair value recognized through earnings for the
combined company.
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 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 13—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, including numerous
assumptions and inputs and accounting elections. The assumptions are reviewed annually and at any interim remeasurement of the plan obligations.
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 17—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)
Equity Investment Earnings (Losses) of Unconsolidated Affiliates (Exelon and Generation)
Exelon and Generation include equity in earnings from equity method investments in qualifying facilities, power projects and joint ventures, in
equity in earnings (losses) of unconsolidated affiliates within their Consolidated Statements of Operations and Comprehensive Income. Equity in
earnings (losses) of unconsolidated affiliates also includes any adjustments to amortize the difference, if any, except for goodwill and land, between
the cost in an equity method investment and the underlying equity in net assets of the investee at the date of investment.
New Accounting Standards (All Registrants)
New Accounting Standards Adopted: in 2016 the Registrants have adopted the following new authoritative accounting guidance issued by
the FASB. Unless otherwise indicated, adoption of the guidance in each instance had no or insignificant impacts on the Registrants’ Consolidated
Balance Sheets, Consolidated Statements of Operations and Comprehensive Income or Consolidated Statements of Cash Flows and disclosures.
Disclosures for Investments in Certain Entities that Calculate Net Asset Value per Share (Issued May 2015; Adopted first quarter 2016
retrospectively to all prior periods presented): Removes the requirement to categorize within the fair value hierarchy all investments for which fair
value is measured using the net asset value per share practical expedient, and instead provides for such investments to be disclosed as a
reconciling item between the fair value hierarchy disclosure and the investment line item on the Balance Sheet. The guidance also simplified the
disclosure requirements for investments valued using the practical expedient. See Note 12—Fair Value of Financial Assets and Liabilities for the
disclosure impacts.
Customer ’ s Accounting for Fees Paid in a Cloud Computing Arrangement (Issued April 2015; Adopted first quarter 2016 prospectively):
Clarifies the circumstances under which a cloud computing customer would account for the arrangement as a license of internal-use software. A
cloud computing arrangement would include a software license if (1) the customer has a contractual right to take possession of the software at any
time during the hosting period without significant penalty and (2) it is feasible for the customer to either operate the software on its own hardware or
contract with another party unrelated to the vendor to host the software. If the arrangement does not contain a software license, it would be
accounted for as a service contract.
Amendments to the Consolidation Analysis (Issued February 2015; Adopted January 1, 2016): Amends the consolidation analysis for variable
interest entities (VIEs) and voting interest entities. The new guidance primarily (1) changes the VIE assessment of limited partnerships, (2) amends
the effect that fees paid to a decision maker or service provider have on the VIE analysis, (3) amends how variable interests held by a reporting
entity’s related parties and de facto agents impact its consolidation conclusion, (4) clarifies how to determine whether equity holders (as a group)
have power over an entity, and (5) provides a scope exception for registered and similar unregistered money market funds. The Registrants did not
revise any consolidation conclusions as a result of the guidance, but did identify additional entities that are now considered VIEs. See Note 2—
Variable Interest Entities for the associated disclosures.
Simplifying the Transition to the Equity Method of Accounting (Issued March 2016; Early adopted fourth quarter 2016): Eliminates the
requirement to retroactively adopt the equity method of accounting as a result of an increase in the level ownership or degree of influence of an
existing investment.
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(Dollars in millions, except per share data unless otherwise noted)
Instead, an investor now adds the cost of acquiring the additional interest in the investee to the current basis of the investor’s previously held interest
and adopts the equity method of accounting as of the date the investment qualifies for such treatment.
Effect of Derivative Contract Novations on Existing Hedge Accounting Relationships (Issued March 2016; Early adopted fourth quarter 2016
prospectively): Clarifies that a change in the counterparty of a derivative contract does not, in and of itself, require dedesignation of that hedge
accounting relationship as long as all of the other hedge accounting criteria are met.
Simplifying the Measurement of Inventory (Issued July 2015; Early adopted fourth quarter 2016 prospectively): Requires inventory to be
measured at the lower of cost or net realizable value, with net realizable value defined as the estimated selling price in the ordinary course of
business, less reasonably predictable costs of completion, disposal and transportation. This definition is consistent with existing authoritative
guidance. Current guidance requires inventory to be measured at the lower of cost or market where market could be replacement cost, net realizable
value or net realizable value less an approximately normal profit margin.
Contingent Put and Call Options in Debt Instruments (Issued March 2016; Adopted January 1, 2017 on a modified retrospective basis):
Simplifies the embedded derivative analysis for debt instruments containing contingent call or put options by removing the requirement to assess
whether a contingent event is related to interest rates or credit risks. The guidance clarifies that a contingent put or call option embedded in a debt
instrument would be evaluated for possible separate accounting as a derivative instrument without regard to the nature of the exercise contingency.
The guidance is required to be applied on a modified retrospective basis to all existing and future debt instruments.
Interests Held through Related Parties that are Under Common Control (Issued October 2016; Adopted January 1, 2017 on a retrospective
basis to January 1, 2016): Requires consideration of indirect interests held through related parties under common control proportionately when
determining whether an entity is the primary beneficiary of a variable interest entity.
Improvements to Employee Share-Based Payment Accounting (Issued March 2016; Adopted January 1, 2017 using either the prospective,
modified retrospective, or retrospective method as prescribed by the standard): Simplifies various aspects of how share-based payment awards to
employees are accounted for and presented in the financial statements. The new guidance eliminates additional paid-in capital pools and requires
excess tax benefits and tax deficiencies to be recorded in the Statement of Operations and Comprehensive Income.
New Accounting Standards Issued and Not Yet Adopted: 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. Unless otherwise indicated, the Registrants are
currently assessing the impacts such guidance may have (which could be material) on 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 such
standards will not significantly impact the Registrants’ financial reporting.
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
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(Dollars in millions, except per share data unless otherwise noted)
customer. The new revenue recognition guidance, including subsequent amendments, is effective for annual reporting periods beginning on or after
December 15, 2017, with the option to early adopt the standard for annual periods beginning on or after December 15, 2016. The Registrants do not
plan to early adopt the standard.
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. In addition, the Registrants will be required to capitalize costs to acquire new
contracts, and amortize such costs in a manner consistent with the transfer to the customer of the associated goods or services. Exelon currently
expenses those costs as incurred. 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 continue to assess the impacts this guidance may have on their Consolidated Balance Sheets, Consolidated Statements of
Operations and Comprehensive Income, Consolidated Statements of Cash Flows and disclosures. In performing this assessment, the Registrants
have utilized a project implementation team comprised of both internal and external resources to conduct the following key activities:
•
•
•
•
Actively participate in the AICPA Power and Utilities Industry Task Force (Industry Task Force) process to identify implementation issues
and support the development of related implementation guidance;
Evaluate existing contracts and revenue streams for potential changes in the amounts and timing of recognizing revenues under the new
guidance;
Evaluate and select the transition method; and
Develop and implement the approach and process for complying with the new revenue recognition disclosure requirements.
While there continues to be some ongoing activities in all of these areas, the Registrants have substantially completed the evaluation of their
collective contracts and revenue streams, as well as the evaluation of the transition method. Based on the work completed thus far, the Registrants
have reached the following preliminary conclusions:
•
•
•
The Registrants expect to apply the new guidance using the full retrospective method, however this conclusion could change based on the
outcome of open implementation issues discussed below;
The Registrants currently anticipate that the implementation of the new guidance will not have a material impact on the amount and timing
of revenue recognition; and
The Registrants expect the new guidance will result in more detailed disclosures of revenue compared to current guidance.
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(Dollars in millions, except per share data unless otherwise noted)
Notwithstanding the preliminary conclusions noted above, certain implementation issues continue to be debated and worked through the
Industry Task Force process that could result in amendments to the standard or implementation guidance that could have a material impact on the
Registrants’ Consolidated Balance Sheets, Consolidated Statements of Operations and Comprehensive Income, Consolidated Statements of Cash
Flows and disclosures. The open implementation issues that could be most impactful to the Registrants include: (1) the ability of the Utility
Registrants to recognize revenue for certain contracts where collectability is in question, (2) the accounting by the Utility Registrants for contributions
in aid of construction (CIAC) and whether CIAC arrangements are within the scope of the revenue guidance and (3) primarily at Generation, bundled
sales contracts and contracts with pricing provisions that may require recognition of revenue at prices other than the contract price (e.g., straight line
or estimated future market prices). As part of the overall implementation project, the Registrants are developing alternative adoption plans that would
be implemented in the event the ultimate resolution of the open implementation issues result in significant changes from current revenue recognition
practices.
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 guidance requires lessees to recognize both the
right-of-use assets and lease liabilities in the balance sheet for most leases, whereas today only financing type lease liabilities (capital leases) are
recognized in the balance sheet. This is expected to require significant changes to systems, processes and procedures in order to recognize and
measure leases recorded on the balance sheet that are currently classified as operating leases. In addition, the definition of a lease has been
revised in regards to when an arrangement conveys the right to control the use of the identified asset under the arrangement which may result in
changes to the classification of an arrangement as a lease. The recognition, measurement, and presentation of expenses and cash flows arising
from a lease by a lessee have not significantly changed from current GAAP. The accounting applied by a lessor is largely unchanged from that
applied under current GAAP. The standard is effective for fiscal years beginning after December 15, 2018. Early adoption is permitted, however the
Registrants do not expect to early adopt the standard. Lessees and lessors are required to recognize and measure leases at the beginning of the
earliest period presented using a modified retrospective approach. Refer to Note 24—Commitments and Contingencies for additional information
regarding operating leases.
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 and, for most debt instruments, requires a modified retrospective transition approach through a cumulative-effect
adjustment to retained earnings as of the beginning of the period of adoption.
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
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(Dollars in millions, except per share data unless otherwise noted)
qualitative assessment to determine if a quantitative impairment test is necessary. Exelon, ComEd, Generation, and DPL have goodwill as of
December 31, 2016. 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 adopted on a prospective basis.
Clarifying the Definition of a Business (issued January 2017): Clarifies the definition of a business with the objective of addressing whether
acquisitions should be accounted for as acquisitions of assets or as acquisitions of businesses. If substantially all the fair value of the assets
acquired is concentrated in a single identifiable asset or a group of similar identifiable assets, the set of transferred assets and activities is not a
business. If the fair value of the assets acquired is not concentrated in a single identifiable asset or a group of similar identifiable assets, then an
entity must evaluate whether an input and a substantive process exist, which together significantly contribute to the ability to produce outputs. The
standard also revises the definition of outputs to focus on goods and services to customers. The standard could result in more acquisitions being
accounted for as asset acquisitions. The standard will be effective January 1, 2018 and will be applied prospectively.
Intra-Entity Transfers of Assets Other Than Inventory (Issued October 2016): Requires entities to recognize the income tax consequences of
an intra-entity transfer of an asset other than inventory when the transfer occurs (compared to current GAAP which prohibits the recognition of
current and deferred income taxes for an intra-entity asset transfer until the asset has been sold to an outside party). The standard is effective for
fiscal years beginning after December 15, 2017 with early adoption permitted. The guidance is required to be applied on a modified retrospective
basis through a cumulative-effect adjustment directly to retained earnings as of the beginning of the period of adoption.
Statement of Cash Flows: Classification of Certain Cash Receipts and Cash Payments (Issued August 2016) and Restricted Cash (Issued
November 2016): In 2016, the FASB issued two standards impacting the Statement of Cash Flows. The first adds or clarifies guidance on the
classification of certain cash receipts and payments on the statement of cash flows as follows: debt prepayment or extinguishment costs, settlement
of zero-coupon bonds, contingent consideration payments made after a business combination, proceeds from the settlement of insurance claims,
proceeds from the settlement of corporate-owned life insurance policies and bank-owned life insurance policies, distributions received from equity
method investees, beneficial interest in securitization transactions, and the application of the predominance principle to separately identifiable cash
flows. The second 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). Exelon will adopt both standards on January 1, 2018 on a retrospective basis. Adoption of the second standard
will result in a change in presentation of restricted cash on the face of the Statement of Cash Flows; otherwise the Registrants expect that adoption
of the guidance will have insignificant impacts on the Registrants’ Consolidated Statements of Cash Flows and disclosures.
Recognition and Measurement of Financial Assets and Financial Liabilities (Issued January 2016): (i) requires all investments in equity
securities, including other ownership interests such as partnerships, unincorporated joint ventures and limited liability companies, to be carried at fair
value through net income, (ii) requires an incremental recognition and disclosure requirement related to the presentation of fair value changes of
financial liabilities for which the fair value option has been elected, (iii) amends several disclosure requirements, including 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
(iv) requires disclosure of the fair value of financial assets and liabilities measured at
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(Dollars in millions, except per share data unless otherwise noted)
amortized cost at the amount that would be received to sell the asset or paid to transfer the liability. The standard is effective for fiscal years
beginning after December 15, 2017 with early adoption permitted. The guidance is required to be applied retrospectively with a cumulative effect
adjustment to retained earnings for initial application of the guidance at the date of adoption (modified retrospective method).
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, 2016, Exelon, Generation, BGE, PHI, and ACE collectively consolidated nine VIEs or VIE groups, for which the applicable
Registrant was the primary beneficiary. At December 31, 2015, Exelon, Generation and BGE collectively had seven consolidated VIEs or VIE groups
and PHI and ACE had one consolidated VIE ( see Consolidated Variable Interest Entities below) . As of December 31, 2016 and December 31,
2015, Exelon and Generation collectively had significant interests in eight 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) .
Consolidated Variable Interest Entities
The carrying amounts and classification of the consolidated VIEs’ assets and liabilities included in the Registrants’ consolidated financial
statements at December 31, 2016 and December 31, 2015 are as follows:
December 31, 2016
Successor
December 31, 2015
Predecessor
Current assets
Noncurrent assets
Total assets
Current liabilities
Noncurrent liabilities
Total liabilities
Exelon (a)(b) Generation BGE
$
916 $ 23 $
954 $
8,563
9,517 $
885 $
2,713
3,598 $
3
8,525
9,441 $ 26 $
802 $ 42 $
2,612
3,414 $ 42 $
—
$
$
$
PHI (b)
Generation BGE
23
ACE
Exelon
(a)
9 $ 909 $
8,009
14
35
49 $ 32 $8,918 $
37 $ 473 $
42
101
89
143 $126 $3,400 $
2,927
881 $ 23 $
3
8,004
8,885 $ 26 $
387 $ 81 $
2,884
3,271 $122 $
41
PHI
ACE
12 $ 12
18
18
30 $ 30
48 $ 48
124
124
172 $172
(a)
(b)
Includes certain purchase accounting adjustments not pushed down to the BGE standalone entity.
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.
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(Dollars in millions, except per share data unless otherwise noted)
Exelon’s, Generation’s, BGE’s, PHI’s and ACE’s consolidated VIEs consist of:
RSB BondCo LLC. In 2007, BGE formed RSB BondCo LLC (BondCo), a special purpose bankruptcy remote limited liability company, to
acquire and hold rate stabilization property and to issue and service bonds secured by the rate stabilization property. In June 2007, BondCo
purchased rate stabilization property from BGE, including the right to assess, collect, and receive non-bypassable rate stabilization charges payable
by all residential electric customers of BGE. These charges are being assessed in order to recover previously incurred power purchase costs that
BGE deferred pursuant to Senate Bill 1. BGE has determined that BondCo is a VIE for which it is the primary beneficiary. As a result, BGE
consolidates BondCo.
BondCo’s assets are restricted and can only be used to settle the obligations of BondCo. Further, BGE is required to remit all payments it
receives from customers for rate stabilization charges to BondCo. During 2016, 2015 and 2014, BGE remitted $86 million, $86 million and
$85 million, respectively, to BondCo.
BGE did not provide any additional financial support to BondCo during 2016. Further, BGE does not have any contractual commitments or
obligations to provide additional financial support to BondCo unless additional rate stabilization bonds are issued. The BondCo creditors do not have
any recourse to the general credit of BGE in the event the rate stabilization charges are not sufficient to cover the bond principal and interest
payments of BondCo.
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, 2016, 2015 and 2014, ACE transferred $60 million, $61 million
and $55 million to ATF, respectively.
Retail Gas Group. During 2009, Constellation formed two new entities, which now are part of Generation, and combined them with its
existing retail gas activities into a retail gas entity group for the purpose of entering into a collateralized gas supply agreement with a third-party gas
supplier. While Generation owns 100% of these entities, it has been determined that the retail gas entity group is a VIE because there is not
sufficient equity to fund the group’s activities without the additional credit support that is provided in the form of a parental guarantee. Generation is
the primary beneficiary of the retail gas entity group; accordingly, Generation consolidates the retail gas entity group as a VIE.
The third-party gas supply arrangement is collateralized as follows:
•
•
•
the assets of the retail gas entity group must be used to settle obligations under the third-party gas supply agreement before it can make
any distributions to Generation,
the third-party gas supplier has a collateral interest in all of the assets and equity of the retail gas entity group, and
Generation provides a $75 million parental guarantee to the third-party gas supplier and provides limited recourse to other third-party
suppliers and customers in support of the retail gas group.
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(Dollars in millions, except per share data unless otherwise noted)
Other than credit support provided by the parental guarantee, Exelon or Generation do not have any contractual or other obligations to provide
additional financial support under the collateralized third-party gas supply agreement. The third-party gas supply creditors do not have any recourse
to Exelon’s or Generation’s general credit other than the parental guarantee.
Solar Project Entity Group. In 2011, Generation acquired all of the equity interests in Antelope Valley Solar Ranch One (Antelope Valley)
from First Solar, Inc., a 242-MW solar PV project in northern Los Angeles County, California. In addition, Generation owns a number of limited
liability companies that build, own, and operate solar power facilities. While Generation owns 100% of these entities, it has been determined that
certain of the individual solar project 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 the solar
project entities that qualify as VIEs because Generation controls the design, construction, and operation of the solar power facilities. Generation
provides operating and capital funding to the solar entities for ongoing construction, operations and maintenance of the solar power facilities and
there is limited recourse related to Generation related to certain solar entities. In addition, these solar VIE entities have an aggregate amount of
outstanding debt with third parties of $568 million, as of December 31, 2016, for which the creditors have no recourse to Generation. For additional
information on these project-specific financing arrangements refer to Note 14—Debt and Credit Agreements.
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
$21 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.
Wind Project Entity Group . Generation owns and operates a number of wind project limited liability entities, the majority of which were
acquired during 2010 with the acquisition of all of the equity interests of John Deere Renewables, LLC (now known as Exelon Wind). Generation has
evaluated the significant agreements and ownership structures and the risks of each of its wind projects and underlying entities, and determined that
certain of the entities are VIEs because either the projects have noncontrolling equity interest holders that absorb variability from the wind projects,
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 the wind project entities that qualify as VIEs because Generation controls the design, construction, and operation of the wind
generation facilities.
In December 2016, Generation sold approximately 71% of its equity interest in one of its wind projects that was previously consolidated under
the voting interest model to a tax equity investor. The wind project was evaluated and it was determined to be 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.
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(Dollars in millions, except per share data unless otherwise noted)
While Generation owns 100% of the majority of the wind project entities, six of the projects have noncontrolling equity interests of 1% held by
third parties and one of the projects has noncontrolling equity interests of approximately 71%. Regarding the projects with noncontrolling equity
interests of 1% held by third parties, Generation’s current economic interests in five 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 is 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 of the
wind power 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 during 2016. As of December 31, 2016, the carrying amount of the assets and liabilities
that are consolidated as a result of Generation being the primary beneficiary of the wind VIE entities primarily relates to the wind generating assets,
PPA intangible assets and working capital amounts.
Other Generating Facilities. During the second quarter of 2015, Generation formed a limited liability company to build, own, and operate a
backup generator. While Generation owns 100% of the backup generator company, it was determined that the entity is a VIE because the customer
absorbs price variability from the entity through the fixed price backup generator agreement. Generation provides operating and capital funding to
the backup generator company. Generation also owns 90% of a biomass fueled, combined heat and power company. In the second quarter of 2015,
the entity was deemed to be a VIE because the entity requires additional subordinated financial support in the form of a parental guarantee provided
by Generation for up to $275 million in support of the payment obligations related to the Engineering, Procurement and Construction contract for the
facility in support of one of its other generating facilities (see Note 14—Debt and Credit Agreements for additional details on Albany Green Energy,
LLC). In addition to the parental guarantee, Generation provides operating and capital funding to the biomass fueled, combined heat and power
company. Generation is the primary beneficiary of both entities since Generation has the power to direct the activities that most significantly affect
the economic performance of the entities.
CENG. Through March 31, 2014, CENG was operated as a joint venture with EDF and was governed by a board of ten directors, five of which
were appointed by Generation and five by EDF. CENG was designed to operate under joint and equal control of Generation and EDF through the
Board of Directors, subject to the Chairman of the Board’s final decision making authority on certain special matters; therefore, CENG was not
subject to VIE guidance. Accordingly, Generation’s 50.01% interest in CENG was accounted for as an equity method investment. 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 now 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
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 financial position and results of operations of CENG. On April 1, 2014, Exelon and Generation
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(Dollars in millions, except per share data unless otherwise noted)
derecognized Generation’s equity method investment in CENG and reflected all assets, liabilities, and the EDF noncontrolling interests in CENG at
fair value on the consolidated balance sheets of Exelon and Generation, resulting in the recognition of a $261 million gain in their respective
Consolidated Statements of Operations and Comprehensive Income for the year ended December 31, 2014.
Generation and Exelon, where indicated, provide the following support to CENG (see Note 5—Investment in Constellation Energy Nuclear
Group, LLC and Note 27—Related Party Transactions for additional information regarding Generation’s and Exelon’s transactions with CENG):
•
under the NOSA, Generation conducts all activities related to the operation of the CENG nuclear generation fleet owned by CENG
subsidiaries (the CENG fleet) and provides corporate and administrative services for the remaining life and decommissioning of the CENG
nuclear plants as if they were a part of the Generation nuclear fleet, subject to the CENG member rights of EDF,
•
•
•
•
under the Power Services Agency Agreement (PSAA), Generation provides scheduling, asset management, and billing services to the
CENG fleet for the remaining operating life of the CENG nuclear plants,
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 have been suspended during the term of the Reliability Support Services Agreement (RSSA) (see Note 3—Regulatory
Matters for additional details),
Generation provided a $400 million loan to CENG. As of December 31, 2016, the remaining obligation is $316 million, including accrued
interest, which reflects the principal payment made in January 2015,
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 24—Commitments and Contingencies
for more details),
•
in connection with CENG’s severance obligations, Generation reimbursed CENG for a total of approximately $6 million of the severance
benefits paid from 2014 through 2016. The final reimbursement was made in 2016, and there was no remaining obligation as of
December 31, 2016.
•
•
Generation and EDF share in the $637 million of contingent payment obligations for the payment of contingent retrospective premium
adjustments for the nuclear liability insurance,
Generation provides a guarantee of approximately $7 million associated with hazardous waste management facilities and underground
storage tanks. In addition, EDF executed a reimbursement agreement that provides reimbursement to Exelon for 49.99% of any amounts
paid by Generation under this guarantee,
•
Generation and EDF are the members-insured with Nuclear Electric Insurance Limited and have assigned the loss benefits under the
insurance and the NEIL premium costs to CENG and guarantee the obligations of CENG under these insurance programs in proportion to
their respective member interests (See Note 24—Commitments and Contingencies for more details), and
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(Dollars in millions, except per share data unless otherwise noted)
•
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.
2015 ESA Investco, LLC. In June 2015, 2015 ESA Investco, LLC, then a wholly owned subsidiary of Generation, entered into an arrangement
to purchase a 90% equity interest and 99% of the tax attributes of another distributed energy company. In November 2015, Generation sold 69% of
its equity interest in 2015 ESA Investco, LLC to a tax equity investor. Generation and the tax equity investor will contribute up to a total of
$250 million of equity incrementally from inception through the first quarter of 2017 in proportion to their ownership interests, which is up to
$172 million for the tax equity investor and up to $78 million for Generation (see Note 24—Commitments and Contingencies for more details). The
investment in the distributed energy company was evaluated, and it was determined to be a VIE for which Generation is not the primary beneficiary
(see additional details in the Unconsolidated Variable Interest Entities section below). As of December 31, 2015, Generation consolidated 2015 ESA
Investco, LLC under the voting interest model. Pursuant to the new consolidation guidance effective January 1, 2016, 2015 ESA Investco, LLC
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. Under VIE guidance, Generation is the primary beneficiary; therefore, the entity continues to be consolidated.
For each of the consolidated VIEs, except as otherwise noted:
•
•
•
•
the assets of the VIEs are restricted and can only be used to settle obligations of the respective VIE;
Exelon, Generation, BGE, PHI and ACE did not provide any additional material financial support to the VIEs;
Exelon, Generation, BGE, PHI and ACE did not have any material contractual commitments or obligations to provide financial support to
the VIEs; and
the creditors of the VIEs did not have recourse to Exelon’s, Generation’s, BGE’s, PHI’s or ACE’s general credit.
As of December 31, 2016 and December 31, 2015, ComEd, PECO, 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, 2016 and December 31, 2015, these assets and liabilities primarily consisted of the following:
Cash and cash equivalents
Restricted cash
Accounts receivable, net
Customer
Other
Mark-to-market derivatives assets
Inventory
Materials and supplies
Other current assets
Total current assets
Property, plant and equipment, net
Nuclear decommissioning trust funds
Goodwill
Mark-to-market derivatives assets
Other noncurrent assets
Total noncurrent assets
Total assets
Long-term debt due within one year
Accounts payable
Accrued expenses
Mark-to-market derivative liabilities
Unamortized energy contract liabilities
Other current liabilities
Total current liabilities
Long-term debt
Asset retirement obligations
Pension obligation (c)
Unamortized energy contract liabilities
Other noncurrent liabilities
Noncurrent liabilities
Total liabilities
December 31, 2016
Successor
ACE Exelon (a) Generation BGE
Predecessor
PHI
December 31, 2015
Exelon (a)(b) Generation BGE PHI (b)
$
150 $
59
150 $ — $
27 23
— $ — $
9
9
371
48
31
199
50
908
5,415
2,185
47
23
315
7,985
8,893 $
181 $
269
119
60
15
30
674
641
1,904
9
22
106
2,682
3,356 $
371 —
48 —
31 —
— —
— —
— —
199 —
44 —
870 23
5,415 —
2,185 —
47 —
23 —
3
277
7,947
3
8,817 $ 26 $
99 $ 41 $
269 —
1
116
60 —
15 —
30 —
589 42
540 —
1,904 —
9 —
22 —
106 —
2,581 —
3,170 $ 42 $
— —
5 —
14
9
— —
— —
— —
— —
35 23
35 23
49 $ 32 $
40 $ 35 $
— —
2
— —
— —
— —
42 37
101 89
— —
— —
— —
— —
101 89
143 $ 126 $
2
$
$
$
164 $
100
219
43
140
181
35
882
5,160
2,036
47
53
90
7,386
8,268 $
111 $
216
115
5
12
13
472
666
1,999
9
39
79
2,792
3,264 $
164 $ — $
77 23
219 —
43 —
140 —
181 —
30 —
854 23
5,160 —
2,036 —
47 —
53 —
3
85
7,381
3
8,235 $ 26 $
27 $ 79 $
216 —
2
113
5 —
12 —
13 —
386 81
623 41
1,999 —
9 —
39 —
79 —
2,749 41
3,135 $ 122 $
ACE
— $ —
12 12
— —
— —
— —
— —
— —
12 12
— —
— —
— —
— —
18 18
18 18
30 $ 30
46 $ 46
— —
2
— —
— —
— —
48 48
124 124
— —
— —
— —
— —
124 124
172 $ 172
2
(a)
(b)
Includes certain purchase accounting adjustments not pushed down to the BGE standalone entity.
Includes certain purchase accounting adjustments not pushed down to the ACE standalone entity.
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Table of Contents
Combined Notes to Consolidated Financial Statements—(Continued)
(Dollars in millions, except per share data unless otherwise noted)
(c)
Includes the CNEG retail gas pension obligation, which is presented as a net asset balance within the Prepaid pension asset line item on Generation’s balance sheet. See
Note 17—Retirement Benefits for additional details.
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 on 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, 2016 and 2015, Exelon and Generation had significant unconsolidated variable interests in eight VIEs for which Exelon or
Generation, as applicable, was not the primary beneficiary; including certain equity method investments and certain commercial agreements. Exelon
and Generation only include unconsolidated VIEs that are individually material in the tables below. However, Generation has several individually
immaterial VIEs that in aggregate represent a total investment of $18 million. These immaterial VIEs are equity and debt securities in energy
development companies. The maximum exposure to loss related to these securities is limited to the $18 million included in Investments on Exelon’s
and Generation’s Consolidated Balance Sheets.
The following tables present summary information about Exelon and Generation’s significant unconsolidated VIE entities:
December 31, 2016
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
Debt and payment guarantees
Net assets pledged for Zion Station decommissioning (b)
335
Commercial
Agreement
VIEs
Equity
Investment
VIEs
$
638
215
—
423
—
9
—
9
$
567
287
248
32
264
—
3
—
Total
$1,205
502
248
455
264
9
3
9
Table of Contents
Combined Notes to Consolidated Financial Statements—(Continued)
(Dollars in millions, except per share data unless otherwise noted)
December 31, 2015
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
Debt and payment guarantees
Net assets pledged for Zion Station decommissioning (b)
Commercial
Agreement
VIEs
Equity
Investment
VIEs
$
263
22
—
241
—
9
—
17
$
164
125
11
28
21
—
3
—
Total
$427
147
11
269
21
9
3
17
(a) These items represent amounts on the unconsolidated VIE balance sheets, not on 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 on 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 $113 million and $206 million as of December 31, 2016 and December 31, 2015, respectively;
offset by payables to ZionSolutions LLC of $104 million and $189 million as of December 31, 2016 and December 31, 2015, respectively. These items are included to
provide information regarding the relative size of the ZionSolutions LLC unconsolidated VIE.
For each unconsolidated VIE, Exelon and Generation 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 agreements with, or commitments by, third parties that would materially affect the fair value or risk of their variable interests in these variable
interest entities.
The Registrants’ 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 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 16—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 Energy Development Projects, Distributed Energy Companies, and Energy Generating Facilities. Generation has
several equity investments in energy development projects and energy generating facilities. Generation has evaluated the significant agreements,
ownership structures and risks of each of its equity investments, and determined that certain of the entities are
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Combined Notes to Consolidated Financial Statements—(Continued)
(Dollars in millions, except per share data unless otherwise noted)
VIEs because the entity has an insufficient amount of equity at risk to finance its activities, Generation guarantees the debt of the entity, provides
equity support, or provides operating services to the entity. Generation has reviewed the entities and has determined that Generation is not the
primary beneficiary of the entities that qualify as VIEs because Generation does not have the power to direct the activities that most significantly
impact the VIEs economic performance.
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’s total equity commitment in this arrangement was $85 million and was paid incrementally over an approximate two year
period (see Note 24—Commitments and Contingencies for additional details). This arrangement did not meet the definition of a VIE and was
recorded as an equity method investment. However, pursuant to the new consolidation guidance effective as of January 1, 2016 for the Registrants,
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. (For additional details related to the new consolidation guidance, see Note 1—Significant
Accounting Policies.) Generation is not the primary beneficiary; therefore, the investment continues to be recorded using the equity method.
In June 2015, 2015 ESA Investco, LLC, then a wholly owned subsidiary of Generation, entered into an arrangement to purchase a 90% equity
interest and 99% of the tax attributes of another distributed energy company. Separate from the equity investment, Generation provided $27 million
in cash to the other (10%) equity holder in the distributed energy company in exchange for a convertible promissory note. In November 2015,
Generation sold 69% of its equity interest in 2015 ESA Investco, LLC to a tax equity investor. Generation and the tax equity investor will contribute
up to a total of $250 million of equity incrementally through the first quarter of 2017 in proportion to their ownership interests, which is up to
$172 million for the tax equity investor and up to $78 million for Generation (see Note 24—Commitments and Contingencies for additional details).
Generation and the tax equity investor provide a parental guarantee of up to $275 million in proportion to their ownership interests in support of 2015
ESA Investco, LLC’s obligation to make equity contributions to the distributed energy company. The investment in the distributed energy company
was evaluated and it was determined to be a VIE for which Generation is not the primary beneficiary. See additional details in the Consolidated
Variable Interest Entities section above.
Both distributed energy companies from the 2015 and 2014 arrangements are considered related parties.
ComEd, PECO and BGE
The financing trust of ComEd, ComEd Financing III, the financing trusts of PECO, PECO Trust III and PECO Trust IV, and the financing trust of
BGE, BGE Capital Trust II, are not consolidated in Exelon’s, ComEd’s, PECO’s or BGE’s financial statements. These financing trusts were created
to issue mandatorily redeemable trust preferred securities. ComEd, PECO, and BGE have concluded that they do not have a significant variable
interest in ComEd Financing III, PECO Trust III, PECO Trust IV or BGE Capital Trust II 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 14—Debt and Credit Agreements for additional
information.
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Combined Notes to Consolidated Financial Statements—(Continued)
(Dollars in millions, except per share data unless otherwise noted)
3. Regulatory Matters (All Registrants)
The following matters below discuss the current status of material regulatory and legislative proceedings of the Registrants.
Illinois Regulatory Matters
Energy Infrastructure Modernization Act (Exelon and ComEd).
Background
Since 2011, ComEd’s electric distribution rates are established through a performance-based formula rate, pursuant to EIMA. EIMA also
provides a structure for substantial capital investment by utilities to modernize Illinois’ electric utility infrastructure.
Participating utilities are required to file an annual update to the performance-based formula rate on or before May 1, with resulting rates
effective in January of the following year. This annual electric distribution formula rate update is based on prior year actual costs and current year
projected capital additions (initial revenue requirement). The update also reconciles any differences between the revenue requirement in effect for
the prior year and actual costs incurred for that year (annual reconciliation). See Annual Electric Distribution Filings below for further details.
Throughout each year, ComEd records regulatory assets or regulatory liabilities and corresponding increases or decreases to Operating revenues
for any differences between the revenue requirement in effect and ComEd’s best estimate of the revenue requirement expected to be approved by
the ICC for that year’s reconciliation. As of December 31, 2016, and December 31, 2015, ComEd had a regulatory asset associated with the electric
distribution formula rate of $188 million and $189 million, respectively. The regulatory asset associated with electric distribution formula rate is
amortized to Operating revenues in ComEd’s Consolidated Statement of Operations and Comprehensive Income as the associated amounts are
recovered through rates.
Participating utilities are also required to file an annual update on their AMI implementation progress. On April 1, 2016, ComEd filed an annual
progress report on its AMI Implementation Plan with the ICC, which allows for the installation of more than four million smart meters throughout
ComEd’s service territory through 2018. To date, approximately three million smart meters have been installed in the Chicago area.
Pursuant to EIMA, ComEd annually contributes $4 million for customer education for as long as the AMI Deployment Plan remains in effect.
Additionally, ComEd contributed $10 million annually through 2016 to fund customer assistance programs for low-income customers, which are not
recoverable through rates.
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Annual Electric Distribution Filings
Combined Notes to Consolidated Financial Statements—(Continued)
(Dollars in millions, except per share data unless otherwise noted)
For each of the following years, the ICC approved the following total increases/(decreases) in ComEd’s electric distributions formula rate
filings:
Annual Electric Distribution Filings
ComEd’s requested total revenue requirement
increase (decrease)
Final ICC Order
Initial revenue requirement increase
Annual reconciliation (decrease) increase
Total revenue requirement increase (decrease)
Allowed Return on Rate Base:
Initial revenue requirement
Annual reconciliation
Allowed ROE:
Initial revenue requirement
Annual reconciliation
Effective date of rates
2016
2015
2014
$
$
$
138
134
(7)
127(a)
6.71%
6.69%
$
$
$
(50)
85
(152)
(67)
7.05%
7.02%
8.64%
8.59% (b)
9.14%
9.09% (b)
$
$
$
269
160
72
232
7.06%
7.04%
9.25%
9.20% (b)
January 2017
January 2016
January 2015
(a) On December 20, 2016, the ICC granted ComEd’s and other parties’ joint application for rehearing on the impact that changing ComEd’s OSHA recordable rate for 2014
and 2015 has on the revenue requirement approved in this order. ComEd has proposed that the 2016 total electric distribution revenue requirement be reduced by
$18 million which would be refunded to customers in 2017.
Includes a reduction of 5 basis points for a reliability performance metric penalty.
(b)
Illinois Future Energy Jobs Act (Exelon, Generation, and ComEd).
Background
On December 7, 2016, FEJA was signed into law by the Governor of Illinois. FEJA is effective June 1, 2017, and includes, among other
provisions, (1) a ZES providing compensation for certain nuclear-powered generating facilities, (2) an extension of and certain adjustments to
ComEd’s electric distribution formula rate, (3) new cumulative persisting annual energy efficiency MWh savings goals for ComEd, (4) revisions to the
Illinois RPS requirements, (5) provisions for adjustments to or termination of FEJA programs if the average impact on ComEd’s customer rates
exceeds specified limits, (6) revisions to the existing net metering statute to (i) mandate net metering for community generation projects, and
establish billing procedures for subscribers to those projects, (ii) provide immediately for netting at the energy-only rate for nonresidential customers,
and (iii) transition from netting at the full retail rate to the energy-only rate for certain residential net metering customers once the net meter customer
load equals 5% of total peak demand supplied in the previous year and (7) support for low income rooftop and community solar programs.
Zero Emission Standard
FEJA includes a ZES that provides compensation through the procurement of ZECs targeted at preserving the environmental attributes of
zero-emissions nuclear-powered generating facilities that meet specific eligibility criteria. ZES will have a 10-year duration extending through May
31, 2027.
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Combined Notes to Consolidated Financial Statements—(Continued)
(Dollars in millions, except per share data unless otherwise noted)
Eligible generators may participate in a procurement event overseen by the Illinois Power Agency and selected generators will directly contract with
Illinois utilities for the procurement of the ZECs based upon the number of MWh produced by the eligible facilities, subject to specified annual caps.
The ZEC price will be based upon the current social cost of carbon as determined by the federal government and is initially established at $16.50 per
MWh of production, subject to future adjustments based on specified escalation and pricing adjustment mechanisms designed to lower the ZEC
price based on increases in underlying energy and capacity prices.
Illinois utilities, including ComEd, will be required to purchase from eligible nuclear facilities an amount of ZECs equivalent to 16% of the actual
amount of electricity delivered in 2014. ComEd will recover all costs associated with purchasing ZECs through a new rate rider, which will provide for
an annual reconciliation and true-up to actual costs incurred by ComEd to purchase ZECs, with any difference to be credited to or collected from
ComEd’s retail customers in subsequent periods.
See Note 9—Early Nuclear Plant Retirements for the impacts of the provisions above on Generation’s Consolidated Balance Sheets and
Consolidated Statements of Operations and Comprehensive Income. The provisions do not impact ComEd’s Consolidated Balance Sheets,
Consolidated Statements of Operations and Comprehensive Income or Consolidated Statements of Cash Flows until 2017.
ComEd Electric Distribution Rates
FEJA extends the sunset date for ComEd’s performance-based electric distribution formula rate from 2019 to the end of 2022, allows ComEd
to revise the electric distribution formula rate to eliminate the ROE collar, and allows ComEd to implement a decoupling tariff if the electric
distribution formula rate is terminated at any time. ComEd will revise its electric distribution formula rate to eliminate the ROE collar, which will
eliminate any unfavorable or favorable impacts of weather or load from ComEd’s electric distribution formula rate revenues beginning with the
reconciliation filed in 2018 for the 2017 calendar year. ComEd will begin reflecting the impacts of this change in its electric distribution services costs
regulatory asset or liability beginning in 2017.
FEJA requires ComEd to make non-recoverable contributions to low income energy assistance programs of $10 million per year for 5 years as
long as the electric distribution formula rate remains in effect. With the exception of these contributions, ComEd will recover from customers, subject
to certain caps explained below, the costs it incurs pursuant to FEJA either through its electric distribution formula rate or other recovery
mechanisms.
Energy Efficiency
Existing Illinois law requires ComEd to implement cost-effective energy efficiency measures and, for a 10-year period ending May 31, 2018,
cost-effective demand response measures to reduce peak demand by 0.1% over the prior year for eligible retail customers.
Beginning January 1, 2018, FEJA provides for new cumulative annual energy efficiency MWh savings goals for ComEd, which are designed to
achieve 21.5% of cumulative persisting annual MWh savings by 2030, as compared to the deemed baseline of 88 million MWhs of electric power
and energy sales. FEJA, deems the cumulative persisting annual MWh savings to be 6.6% from 2012 through the end of 2017. ComEd expects to
spend approximately $250 million to $400 million annually from 2017 through 2030 to achieve these energy efficiency MWh savings goals. In
addition, FEJA extends the peak demand reduction requirement from 2018 to 2026. Because the new requirements
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Combined Notes to Consolidated Financial Statements—(Continued)
(Dollars in millions, except per share data unless otherwise noted)
apply beginning in 2018, FEJA extends the existing energy efficiency plans, which were due to end on May 31, 2017, through December 31, 2017.
FEJA also exempts customers with demands over 10 MW from energy efficiency plans and requirements beginning June 1, 2017.
FEJA allows ComEd to cancel its existing energy efficiency rate rider and replace it with an energy efficiency formula rate, and to defer energy
efficiency costs (except for any voltage optimization costs which will be recovered through the electric distribution formula rate) as a separate
regulatory asset that will be 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 will earn 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. 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 will be required to file an update to its energy efficiency formula rate on or
before June 1 each year, with resulting rates effective in January of the following year. The annual update will be based on projected current year
energy efficiency costs and the related projected year-end regulatory asset balance less any related deferred taxes. The update will also include a
reconciliation of any differences between the revenue requirement in effect for the prior year and the revenue requirement based on actual prior year
costs and year-end energy efficiency regulatory asset balances less any related deferred taxes.
ComEd expects to cancel its existing energy efficiency rider, at which time it must perform a reconciliation of revenues and costs incurred
through the cancellation date and issue a one-time credit on retail customers’ bills for any over-recoveries. As of December 31, 2016, ComEd’s over-
recoveries associated with its existing energy efficiency rider of $141 million were reflected in Current regulatory liabilities on Exelon’s and ComEd’s
Consolidated Balance Sheets. As a result, ComEd expects to provide credits to customers in 2017 to address this over-recovery.
Renewable Portfolio Standard
Existing Illinois law requires ComEd to purchase each year an increasing percentage of renewable energy resources for the customers for
which it supplies electricity. This obligation is satisfied through the procurement of renewable energy credits (RECs). FEJA revises the Illinois RPS to
require ComEd to procure RECs for all retail customers by June 2019, regardless of the customers’ electricity supplier, and provides support for low-
income rooftop and community solar programs, which will be funded by the existing Renewable Energy Resources Fund and ongoing RPS
collections. ComEd will recover all costs associated with purchasing RECs through rate riders, which will provide for a reconciliation and true-up to
actual costs, with any difference between revenues and expenses to be credited to or collected from ComEd’s retail customers in subsequent
periods. The first reconciliation and true-up for RECs will cover revenues and costs for the four year period beginning June 1, 2017 through May 31,
2021. Subsequently, the RPS rate rider will provide for an annual reconciliation and true-up.
Customer Rate Increase Limitations
FEJA includes provisions intended to limit the average impact on ComEd customer rates for recovery of costs incurred under FEJA as follows:
(1) for a typical ComEd residential customer, the average impact must be less than $0.25 cents per month, (2) for nonresidential customers with a
peak demand less than 10 MW, the average annual impact must be less than 1.3% of the average amount
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Combined Notes to Consolidated Financial Statements—(Continued)
(Dollars in millions, except per share data unless otherwise noted)
paid per kWh for electric service by Illinois commercial retail customers during 2015, and (3) for nonresidential customers with a peak demand
greater than 10 MW, the average annual impact must be less than 1.3% of the average amount paid per kWh for electric service by Illinois industrial
retail customers during 2015.
By June 30, 2017, ComEd must submit a 10-year projection to the ICC of customer rate impacts for residential customers and nonresidential
customers with a peak demand less than 10 MW. Thereafter, beginning in 2018, ComEd must submit a report to the ICC for residential customers
and nonresidential customers with a peak demand less than 10 MW by February 15th and June 30th of each year, respectively. For nonresidential
customers with a peak demand greater than 10 MW, ComEd must submit a report to the ICC by May 1 of each year if a rate reduction will be
necessary in the following year. For residential customers, the reports will include the actual costs incurred under FEJA during the preceding year
and a rolling 10-year customer rate impact projection. The reports for nonresidential customers with a peak demand less than 10 MW will also
include the actual costs incurred under FEJA during the preceding year, as well as the average annual rate increase from January 1, 2017 through
the end of the preceding year and the average annual rate increase projected for the remainder of the 10-year period.
If the projected residential customer or nonresidential customer with a peak demand less than 10 MW rate increase exceeds the limitations
during the first four years, ComEd is required to decrease costs associated with FEJA investments, including reductions to ZEC contract quantities. If
the projected residential customer or nonresidential customer with a peak demand less than 10 MW rate increase exceeds the limitations during the
last six years, ComEd is required to demonstrate how it will reduce FEJA investments to ensure compliance. If the actual residential customer or
nonresidential customer with a peak demand less than 10 MW rate increase exceeds the limitations for any one year, ComEd is required to submit a
corrective action plan to decrease future year costs to reduce customer rates to ensure future compliance. If the actual residential customer or
nonresidential customer rate exceeds the limitations for two consecutive years, ComEd can offer to credit customers for amounts billed in excess of
the limitations or ComEd can terminate FEJA investments. If ComEd chooses to terminate FEJA investments, the ICC shall order termination of ZEC
contracts and further initiate proceedings to reduce energy efficiency savings goals and terminate support for low-income rooftop and community
solar programs. ComEd is allowed to fully recover all costs incurred as of and up to the date of the programs’ termination.
For the energy efficiency formula, ComEd will record a regulatory asset or liability and corresponding increase or decrease to Operating
revenues for any differences between the revenue requirement in effect and ComEd’s best estimate of the revenue requirement expected to be
approved by the ICC for that year’s reconciliation. For the other rate riders to be established under FEJA, ComEd will record a regulatory asset or
liability for any differences between revenues and incurred expenses. FEJA did not have any impacts on ComEd’s Consolidated Statements of
Operations and Comprehensive Income or Consolidated Statements of Cash Flows in 2016.
Illinois Procurement Proceedings (Exelon, Generation and ComEd). ComEd is permitted to recover its electricity procurement costs from
retail customers without mark-up. Since June 2009, the IPA designs, and the ICC approves, an electricity supply portfolio for ComEd and the IPA
administers a competitive process under which ComEd procures its electricity supply from various suppliers, including Generation. As of
December 31, 2016, ComEd has completed all required ICC-approved procurements as called for by the IPA Procurement Plan’s timeline.
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Combined Notes to Consolidated Financial Statements—(Continued)
(Dollars in millions, except per share data unless otherwise noted)
Energy Efficiency and Renewable Energy Resources (Exelon and ComEd).
In accordance with legislation in effect on December 31, 2016, the IPA’s Procurement Plans include the procurement of cost-effective
renewable energy resources in amounts that equal or exceed a minimum target percentage of the total electricity that each electric utility supplies to
its eligible retail customers. The June 1, 2016 target renewable energy resources obligation for the utilities was at least 11.5%. This obligation
increases by at least 1.5% each year thereafter to an ultimate target of at least 25% by June 1, 2025. All goals are subject to rate impact criteria set
forth by Illinois legislation. As of December 31, 2016, ComEd had purchased renewable energy resources or equivalents, such as RECs, in
accordance with the IPA Procurement Plan. ComEd currently retires all RECs upon transfer and acceptance. ComEd is permitted to recover
procurement costs of RECs from retail customers without mark-up through rates.
In accordance with FEJA that takes effect on June 1, 2017, beginning with the plan or plans to be implemented in the 2017 delivery year, the
IPA shall develop a long term renewable resources procurement plan (LT Plan). The RPS target percentages for the overall service territory have
not changed through June 1, 2025 although FEJA extended the 25% RPS target to delivery years after 2025. Currently, each RES and each utility is
responsible for the renewable resource obligation of the customers it supplies power for. Over time, this will change and the utility will procure
renewable resources based on the retail load of substantially all customers in its service territory. For the delivery year beginning June 1, 2017, the
LT Plan shall include cost effective renewable energy resources procured by the utility for the retail load the utility supplies and for 50% of the retail
customer load supplied by Retail Electric Suppliers in the utility service territory on February 28, 2017. Utility procurement for RES supplied retail
customer load will increase to 75% June 1, 2018 and to 100% beginning June 1, 2019.
Grand Prairie Gateway Transmission Line (Exelon and ComEd). On December 2, 2013, ComEd filed a request to obtain the ICC’s
approval to construct a 60-mile overhead 345kV transmission line that traverses Ogle, DeKalb, Kane and DuPage Counties in Northern Illinois. On
October 22, 2014, the ICC issued an Order approving ComEd’s request. The City of Elgin and certain other parties each filed an appeal of the ICC
Order in the Illinois Appellate Court for the Second District. ComEd then reached a settlement of the appeal filed by all parties except Elgin. On
March 31, 2016, the Illinois Appellate Court issued its opinion affirming the ICC’s grant of a certificate to ComEd to construct and operate the line.
Elgin did not seek further review of the Illinois Appellate Court decision. On May 28, 2014, in a separate proceeding, FERC issued an order granting
ComEd’s request to include 100% of the capital costs recorded to construction work in progress during construction of the line in ComEd’s
transmission rate base. If the project is cancelled or abandoned for reasons beyond ComEd’s control, FERC approved the ability for ComEd to
recover 100% of its prudent costs incurred after May 21, 2014 and 50% of its costs incurred prior to May 21, 2014 in ComEd’s transmission rate
base. The costs incurred for the project prior to May 21, 2014 were immaterial. ComEd has acquired the necessary land rights across the project
route through voluntary transactions. ComEd began construction of the line during 2015 with an expected in-service date of June 2017.
FutureGen Industrial Alliance, Inc (Exelon and ComEd). During 2013, the ICC approved, and directed ComEd and Ameren (the Utilities) to
enter into 20-year sourcing agreements with FutureGen Industrial Alliance, Inc (FutureGen), under which FutureGen will retrofit and repower an
existing plant in Morgan County, Illinois to a 166 MW near zero emissions coal-fueled generation plant, with an assumed commercial operation date
in 2017. ComEd executed the sourcing agreement with FutureGen in accordance with the ICC’s order. The order also directed ComEd and Ameren
to recover these costs from their electric distribution customers through the use of a tariff, regardless of whether they purchase electricity from
ComEd or Ameren, or from competitive electric generation suppliers.
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(Dollars in millions, except per share data unless otherwise noted)
In February 2015, the DOE suspended funding for the cost development of FutureGen. On January 13, 2016, FutureGen informed the Illinois
Supreme Court that it had ceased all development efforts on the FutureGen project. In February 2016, FutureGen terminated its sourcing agreement
with ComEd. On May 19, 2016, the Illinois Supreme Court dismissed the matter as moot. As a result, ComEd is under no further obligation under
this agreement.
Pennsylvania Regulatory Matters
2015 Pennsylvania Electric Distribution Rate Case (Exelon and PECO). On March 27, 2015, PECO filed a petition with the PAPUC
requesting an increase of $190 million to its annual service revenues for electric delivery, which requested an ROE of 10.95%. On September 10,
2015, PECO and interested parties filed with the PAPUC a petition for joint settlement for an increase of $127 million in annual distribution service
revenue. No overall ROE was specified in the settlement. On December 17, 2015, the PAPUC approved the settlement of PECO’s electric
distribution rate case, which included the approval of the In-Program Arrearage Forgiveness (“IPAF”) Program. The approved electric delivery rates
became effective on January 1, 2016.
The IPAF Program provides for forgiveness of a portion of the eligible arrearage balance of its low-income Customer Assistance Program
(CAP) accounts receivable at program inception. The forgiveness will be granted to the extent CAP customers remain current over the duration of
the five-year payment agreement term. The Settlement guarantees PECO’s recovery of two-thirds of the arrearage balance through a combination of
customer payments and rate recovery, including through future rates cases if necessary. The remaining one-third of the arrearage balance has been
absorbed by PECO through bad debt expense on its Consolidated Statements of Operations. In October 2016, the IPAF was fully implemented. A
regulatory asset of $11 million representing previously incurred bad debt expense associated with the eligible accounts receivable balances was
recorded as of December 31, 2016.
Pennsylvania Procurement Proceedings (Exelon and PECO). Through PECO’s first two PAPUC approved DSP Programs, PECO
procured electric supply for its default electric customers through PAPUC approved competitive procurements. DSP I and DSP II expired on May 31,
2013 and May 31, 2015, respectively.
The second DSP Program included a number of retail market enhancements recommended by the PAPUC in its previously issued Retail
Markets Intermediate Work Plan Order. PECO was also directed to submit a plan to allow its low-income CAP customers to purchase their
generation supply from EGSs beginning in April 2014. In May 2013, PECO filed its CAP Shopping Plan with the PAPUC. By an Order entered on
January 24, 2014, the PAPUC approved PECO’s plan, with modifications, to make CAP shopping available beginning April 15, 2014. On March 20,
2014, the Office of Consumer Advocate (OCA) and low-income advocacy groups filed an appeal and emergency request for a stay with the
Pennsylvania Commonwealth Court, claiming that the PAPUC-ordered CAP Shopping plan does not contain sufficient protections for low-income
customers. On July 14, 2015, the Court issued opinions on the OCA and low-income advocacy group appeal. Specifically, the Court remanded the
issue to the PAPUC with instructions that it approve a rule revision to the PECO CAP Shopping Plan that would prohibit CAP customers from
entering into contracts with an EGS that would impose early cancellation/termination fees. The PAPUC, as well as the low-income advocates and
the Office of Consumer Advocate, appealed the Court’s decision. On April 5, 2016, the Pennsylvania Supreme Court declined to accept the appeals.
On May 11, 2016, the PAPUC issued a Secretarial Letter requiring PECO to propose a rule revision to the PECO CAP Shopping Plan consistent
with the Court’s decision. On July 19, 2016, PECO filed a letter stating its intent to revise its Plan by September 1, 2016 to incorporate the rule
revision. On September 1, 2016, PECO filed its proposed rule revision that is consistent with the Court’s opinion with a proposed effective date of
April 14, 2017.
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(Dollars in millions, except per share data unless otherwise noted)
On December 4, 2014, the PAPUC approved PECO’s third DSP Program. The program has a 24-month term from June 1, 2015 through
May 31, 2017, and complies with electric generation procurement guidelines set forth in Act 129. Under the program, PECO procured electric supply
through four competitive procurements for fixed price full requirements contracts of two years or less for the residential classes and small and
medium commercial classes and spot market price full requirement contracts for the large commercial and industrial class load. Beginning in June
2016, the medium commercial class (101-500 kW) moved to spot market pricing. In September 2016, PECO entered into contracts with PAPUC-
approved bidders, including Generation, resulting from the final of its four scheduled procurements. Charges incurred for electric supply procured
through contracts with Generation are included in purchased power from affiliates on PECO’s Consolidated Statement of Operations and
Comprehensive Income.
On March 12, 2015, PECO settled the CAP Design with the Office of Consumer Advocates (OCA) and Low Income Advocates, and filed the
proposed plan with the PAPUC on March 20, 2015. The program design changes the rate structure of PECO’s CAP to make the bills more
affordable to customers enrolled in the assistance program. The CAP discounts continue to be recovered through PECO’s universal service fund
cost. On July 8, 2015, the CAP Design was approved by the PAPUC, and subsequently implemented in October 2016 as planned.
On March 17, 2016, PECO filed its fourth DSP Program with the PAPUC proposing a 24-month term from June 1, 2017 through May 31, 2019,
in compliance with electric generation procurement guidelines set forth in Act 129. On October 4, 2016, the Administrative Law Judge recommended
that PECO’s previously filed partial settlement be approved without modification. The settlement would extend the program period through May 2021
and consolidate the Medium Commercial and Large Commercial classes of default service customers into a Consolidated Large Commercial
Class proposed by the Company. The issue of PECO’s implementation of CAP Shopping was reserved for briefing, and the Administrative Law
Judge determined that issue was not a part of the DSP IV case. On December 8, 2016, the PAPUC approved the fourth DSP Program for a
48-month term and deferred CAP Shopping to another proceeding. OCA and Low Income Advocates subsequently filed a Petition for
Reconsideration and Clarification, which is pending before the PAPUC.
Smart Meter and Smart Grid Investments (Exelon and PECO). In April 2010, pursuant to Act 129 and the follow-on Implementation Order of
2009, the PAPUC approved PECO’s Smart Meter Procurement and Installation Plan (SMPIP), under which PECO will install more than 1.6 million
electric smart meters and an AMI communication network by 2020. As approved by the PAPUC, PECO accelerated its installation and deployed
substantially all smart meters by December 31, 2015, for a total of 1.7 million smart meters. PECO spent $578 million and $155 million on smart
meter and smart grid infrastructure, respectively, of which $200 million has been funded by SGIG. Recovery of smart meter costs are reflected in
base rates effective January 1, 2016.
Energy Efficiency Programs (Exelon and PECO). The PAPUC issued its Phase II EE&C implementation order on August 2, 2012, that
provided energy consumption reduction requirements for the second phase of Act 129’s EE&C program, which went into effect on June 1, 2013.
Pursuant to the Phase II implementation order, PECO filed its three-year EE&C Phase II Plan with the PAPUC on November 1, 2012. The plan set
forth how PECO would reduce electric consumption by at least 1,125,852 MWh in its service territory for the period June 1, 2013 through May 31,
2016, adjusted for weather and extraordinary loads. The implementation order permitted PECO to apply any excess savings achieved during Phase
I against its Phase II consumption reduction targets, with no reduction to its Phase II budget. In accordance with the Act 129 Phase II implementation
order, at least 10% and 4.5% of the total consumption reductions had to be through programs directed toward PECO’s public
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(Dollars in millions, except per share data unless otherwise noted)
and low income sectors, respectively. Act 129 mandates that the total cost of the plan may not exceed 2% of the electric company’s total annual
revenue as of December 31, 2006.
On March 15, 2013 and February 28, 2014, PECO filed Petitions for Approval to amend its EE&C Phase II Plan to continue its DLC demand
reduction program for mass market customers through May 31, 2014 and May 31, 2016, respectively. PECO proposed to fund the estimated
$10 million annual costs of the plan by modifying incentive levels for other Phase II programs. The costs of the DLC program were recovered
through PECO’s Energy Efficiency Plan surcharge along with other Phase II Plan costs. The PAPUC granted PECO’s Petitions on May 5, 2013 and
April 23, 2014, respectively. On November 15 2016, PECO reported to the PAPUC that as of the conclusion of the EE&C Phase II Plan, all plan
requirements have been met. A final Phase II compliance determination is expected to be issued in the first half of 2017.
On June 19, 2015, the PAPUC issued its Phase III EE&C implementation order that provides energy consumption reduction requirements for
the third phase of Act 129’s EE&C program with a five-year term from June 1, 2016 through May 31, 2021.
Pursuant to the Phase III implementation order, PECO filed its five-year EE&C Phase III Plan with the PAPUC on November 30, 2015. The
Plan sets forth how PECO will reduce electric consumption by at least 1,962,659 MWh, with a goal of 2,100,875 MWh in its service territory for the
period June 1, 2016 through May 31, 2021. The PAPUC approved PECO’s EE&C Phase III Plan, with requested clarifications, on May 19, 2016.
Alternative Energy Portfolio Standards (Exelon and PECO). In November 2004, Pennsylvania adopted the AEPS Act. The AEPS Act
mandated that beginning in 2011, following the expiration of PECO’s rate cap transition period, certain percentages of electric energy sold to
Pennsylvania retail electric customers shall be generated from certain alternative energy resources as measured in AECs. The requirement for
electric energy that must come from Tier I alternative energy resources ranges from approximately 3.5% to 8%, and the requirement for Tier II
alternative energy resources ranges from 6.2% to 10%. The required compliance percentages incrementally increase each annual compliance
period, which is from June 1 through May 31, until May 31, 2021. These Tier I and Tier II alternative energy resources include acceptable energy
sources as set forth in Act 129 and the AEPS Act.
PECO continues to procure alternative energy credits through full requirements contracts and its existing long-term solar contracts to meet the
annual AEPS compliance requirements. All AEPS compliance costs are being recovered on a full and current basis from default service customers
through the GSA.
Pennsylvania Retail Electricity and Gas Markets (Exelon and PECO). Beginning in 2011, the PAPUC issued an order outlining the next
steps in its investigation into the status of competition in Pennsylvania’s retail electricity market. The PAPUC found that the existing default service
model presents substantial impediments to the development of a vibrant retail market in Pennsylvania and directed its Office of Competitive Markets
Oversight to evaluate potential intermediate and long-term structural changes to the default service model. Through various orders, the PAPUC
issued default electric service pricing for customers in PECO’s service territory. See Pennsylvania procurement proceedings discussed above for
additional details.
In early 2014, the extreme weather in PECO’s service territory resulted in increased electricity commodity costs causing certain shopping
customers to receive unexpectedly high utility bills. In response to a significant number of customer complaints throughout Pennsylvania, on April 3,
2014,
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(Dollars in millions, except per share data unless otherwise noted)
the PAPUC unanimously voted to adopt two rulemaking orders to address the issue. The first rulemaking order requires electric generation suppliers
to provide more consumer education regarding their contract. The second rulemaking order requires electric distribution companies to enable
customers to switch suppliers within three business days (known as accelerated switching). The improved customer education and accelerated
switching were to be in place within 30 days and six months of approval of the orders, respectively. The orders became final on June 14, 2014. On
December 4, 2014, the PAPUC approved PECO’s implementation plan (known as Bill on Supplier Switch), allowing PECO to implement accelerated
switching by the December 15, 2014 deadline.
On September 12, 2013, the PAPUC issued an Order that initiated an investigation into Pennsylvania’s natural gas retail market, including the
role of the existing default service model and opportunities for market enhancements. On December 18, 2014, the PAPUC issued a Final Order
directing the Office of Competitive Market Oversight (OCMO) to continue its investigation, confirming that natural gas distribution companies should
remain with the default service model for the time being and directing establishment of a working group to examine other competitive issues. The
OCMO has established a working group to review operation of the natural gas retail market and to consider potential recommendations on
competitive issues.
Pennsylvania Act 11 of 2012 (Exelon and PECO). In February 2012, Act 11 was signed into law, which provided the PAPUC authority to
approve the implementation of a distribution system improvement charge (DSIC) in rates designed to recover capital project costs incurred to repair,
improve or replace utilities’ aging electric and natural gas distribution systems in Pennsylvania. Prior to recovering costs pursuant to a DSIC, the
PAPUC’s implementation order requires a utility to have a Long Term Infrastructure Improvement Plan (LTIIP) approved by the Commission, which
outlines how the utility is planning to increase its investment for repairing, improving or replacing aging infrastructure.
On May 7, 2015, the PAPUC approved PECO’s modified natural gas LTIIP. In accordance with the approved LTIIP, PECO plans to spend
$534 million through 2022 to further accelerate the replacement of existing gas mains and to relocate meters from indoors to outside in accordance
with recent PAPUC rulemaking. In addition, on March 20, 2015, PECO filed a petition with the PAPUC for approval of its gas DSIC mechanism for
recovery of gas LTIIP expenditures. On September 11, 2015, the PAPUC entered its Opinion and Order approving PECO’s petition for a gas DSIC.
On March 27, 2015, PECO filed a petition with the PAPUC for approval of its proposed electric DSIC and LTIIP. In accordance with the LTIIP
(System 2020 plan), PECO plans to spend $275 million over the next five years to modernize and storm-harden its electric distribution system,
making it more weather resistant and less vulnerable to damage. The DSIC will allow PECO the opportunity to recover the costs, subject to certain
criteria, incurred to repair, improve or replace its electric distribution property between rate cases. On October 22, 2015, the PAPUC entered its
Opinion and Order approving PECO’s proposed petition for its electric LTIIP and DSIC.
Maryland Regulatory Matters
2016 Maryland Electric Distribution Base Rates (Exelon, PHI and Pepco). On November 15, 2016, the MDPSC approved an increase in
electric distribution base rates of $53 million based on a ROE of 9.55%. The new rates became effective for services rendered on or after
November 15, 2016. MDPSC also approved Pepco’s recovery of substantially all of its capital investment and regulatory assets associated with its
AMI program as part of the newly effective rates as well as a recovery over a five-year period of transition costs related to a new billing system
implemented in 2015. As a result,
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(Dollars in millions, except per share data unless otherwise noted)
during the fourth quarter of 2016, Exelon, PHI and Pepco established a regulatory asset of $13 million, wrote-off $3 million in disallowed AMI costs
and recorded a pre-tax credit to net income for $10 million. Additionally, the MDPSC denied Pepco’s request to extend its Grid Resiliency Program
surcharge for new system reliability and safety improvement projects, with costs for such programs to be recovered going forward through base
rates.
2016 Maryland Electric Distribution Base Rates (Exelon, PHI and DPL). On July 20, 2016, DPL filed an application with the MDPSC
requesting an increase of $66 million to its electric distribution base rates, which was later updated to $57 million, based on a requested ROE of
10.6%. The application is inclusive of a request seeking recovery of DPL’s regulatory assets associated with its AMI program over a five year period,
which was later modified to 10 years, supported by evidence demonstrating that the benefits of the AMI program exceed the costs on a present
value basis. Any adjustments to rates approved by the MDPSC are expected to take effect in February 2017. DPL cannot predict how much of the
requested increase the MDPSC will approve. In addition to the proposed rate increase, DPL is proposing to continue its Grid Resiliency Program
initially approved in September 2013 in connection with DPL’s electric distribution rate case filed in February 2013. Under the Grid Resiliency
Program, DPL is authorized to receive recovery of specific investments as the assets are placed in service through the Grid Resiliency Charge. In
connection with the Grid Resiliency Program, DPL proposes to accelerate improvement to priority feeders and install single-phase reclosing fuse
technology by investing $4.6 million a year for two years for a total of $9.2 million. DPL cannot predict whether the MDPSC will approve a
continuation of DPL’s Grid Resiliency Program proposal.
2015 Maryland Electric and Natural Gas Distribution Base Rates (Exelon and BGE). On November 6, 2015, and as amended through the
course of the proceeding, BGE filed for electric and natural gas base rate increases with the MDPSC, ultimately requesting annual increases of
$116 million and $78 million, respectively, of which $104 million and $37 million were related to recovery of electric and natural gas smart grid
initiative costs, respectively. BGE also proposed to recover an annual increase of approximately $30 million for Baltimore City underground conduit
fees through a surcharge.
On June 3, 2016, the MDPSC issued an order in which the MDPSC found compelling evidence to conclude that BGE’s smart grid initiative
overall was cost beneficial to customers. However, the June 3 order contained several cost disallowances and adjustments, including not allowing
BGE to defer or recover through a surcharge the $30 million increase in annual Baltimore City underground conduit fees. On June 30, 2016, BGE
filed a petition for rehearing of the June 3 order requesting that the MDPSC modify its order to reverse certain decisions including the decision
associated with the Baltimore City underground conduit fees. OPC also subsequently filed for a petition for rehearing of the June 3 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. Through the combination of the orders, the MDPSC authorized electric and natural gas rate increases
of $44 million and $48 million, respectively, and an allowed ROE for the electric and natural gas distribution businesses of 9.75% and 9.65%,
respectively. The new electric and natural gas base rates took effect for service rendered on or after June 4, 2016. However, MDPSC’s July 29 order
on the petition on rehearing still did not allow BGE to defer or recover through a surcharge the increase in Baltimore City underground conduit fees.
On August 26, 2016, BGE filed an appeal of the MDPSC’s orders with the Circuit Court for Baltimore County. On August 29, 2016, the
residential consumer advocate also filed an appeal of the
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(Dollars in millions, except per share data unless otherwise noted)
MDPSC’s order but with the Circuit Court for Baltimore City. On November 15, 2016, Baltimore County Circuit Court issued an order deciding that
the cases should be consolidated and should proceed in Baltimore County Circuit Court. However, on January 9, 2017, BGE filed to withdraw its
appeal of the MDPSC’s orders and on January 10, 2017, the residential consumer advocate filed to withdraw its appeal as well. Refer to the Smart
Meter and Smart Grid Investment disclosure below for further details on the impact of the ultimate disallowances contained in the orders to BGE.
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 all of its SOS-related
costs. The Administrative Charge is now comprised of five components: CWC, uncollectibles, incremental costs, return, and an administrative
adjustment, which is an adder to the utility’s SOS rate to act as a proxy for retail suppliers’ costs. The Commission accepted BGE positions on
recovery of CWC and pass-through recovery of BGE’s actual uncollectibles and incremental costs. The order also grants BGE a modest return on
the SOS. The Commission ruled that the level of the administrative adjustment will be determined in BGE’s next rate case. On December 16, 2016,
MDPSC Staff requested clarification concerning the amount of return on the SOS awarded to BGE and on December 19, 2016, the residential
consumer advocate sought rehearing of the return awarded. On January 24, 2017, the MDPSC issued an order denying the MDPSC Staff request
for clarification and the residential consumer advocate request for rehearing.
2014 Maryland Electric and Gas Distribution Base Rates (Exelon and BGE). On July 2, 2014, and as amended on September 15, 2014,
BGE filed for electric and gas base increases with the MDPSC, ultimately requesting increases of $99 million and $68 million, respectively.
On October 17, 2014, BGE filed with the MDPSC a unanimous settlement agreement (the Settlement Agreement) reached with all parties to
the case under which it would receive an increase of $22 million in electric base rates and an increase of $38 million in gas base rates. The
Settlement Agreement establishes new depreciation rates which have the effect of decreasing annual depreciation expense by approximately
$20 million, primarily for electric. On December 4, 2014, the Public Utility Law Judge issued a proposed order approving the Settlement Agreement
without modification, which became a final order on December 12, 2014. The approved distribution rate order authorizing BGE to increase electric
and gas distribution rates became effective for services rendered on or after December 15, 2014.
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. Refer to AMI programs in the Regulatory Assets and Liabilities section below for further details.
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-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 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
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(Dollars in millions, except per share data unless otherwise noted)
non-AMI meters replaced under the program. On June 30, 2016, BGE filed a petition for rehearing of the June 3 order requesting that the MDPSC
modify its order to reverse certain decisions and change certain of the cost disallowances and adjustments to enable BGE to defer those costs for
recovery through future electric and natural gas rates. The residential consumer advocate also subsequently filed for a petition for rehearing of the
June 3 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. On August 26, 2016, BGE filed an appeal of the MDPSC’s orders with the Circuit Court for Baltimore
County. On August 29, 2016, the residential consumer advocate also filed an appeal of the MDPSC’s order but with the Circuit Court for Baltimore
City. On November 15, 2016, Baltimore County Circuit Court issued an order deciding that the cases should be consolidated and should proceed in
Baltimore County Circuit Court. However, on January 9, 2017, BGE filed to withdraw its appeal of the MDPSC’s orders and on January 10, 2017, the
residential consumer advocate filed to withdraw its appeal as well.
As a combined result of the MDPSC orders, BGE recorded a $52 million charge 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. Pursuant
to the combined MDPSC orders, BGE also reclassified $54 million of non-AMI plant costs from Property, plant and equipment, net to Regulatory
assets on Exelon’s and BGE’s Consolidated Balance Sheets as of December 31, 2016.
2013 Maryland Electric and Gas Distribution Base Rates (Exelon and BGE). On May 17, 2013, and as amended on August 23, 2013, BGE
filed for electric and natural gas base increases with the MDPSC. In addition to these requested rate increases, BGE’s application also included a
request for recovery of incremental capital expenditures and operating costs associated with BGE’s proposed short-term reliability improvement plan
(the ERI initiative) in response to a MDPSC order through a surcharge separate from base rates.
On December 13, 2013, the MDPSC issued an order authorizing BGE to recover through a surcharge mechanism costs associated with five
ERI initiative programs designed to accelerate electric reliability improvements premised upon the condition that the MDPSC approve specific
projects in advance of cost recovery. As of December 31, 2016, BGE has received approval of its updated surcharge filings three times for rates to
be effective in 2014, 2015 and 2016.
In January 2014, the residential consumer advocate in Maryland filed an appeal to the order issued by the MDPSC on December 13, 2013 in
BGE’s 2013 electric and natural gas distribution rate cases. The residential consumer advocate filed its related legal memorandum on August 22,
2014, challenging the MDPSC’s approval of the ERI initiative surcharge. BGE submitted a response to the appeal on October 15, 2014, and a
hearing was held on November 17, 2014. On October 26, 2015, the Circuit Court for Baltimore City issued an order affirming the MDPSC decision.
However, on November 30, 2015, the residential consumer advocate filed an appeal of the Circuit Court’s decision with the Maryland Court of
Special Appeals. On March 7, 2016, the consumer advocate withdrew its appeal and no further action is expected.
MDPSC New Generation Contract Requirement (Exelon, Generation, BGE, PHI, Pepco and DPL). On April 12, 2012, the MDPSC issued
an order that requires BGE, Pepco and DPL (collectively, the Contract EDCs) to negotiate and enter into a contract with the winning bidder of a
competitive bidding process to build one new power plant in the range of 650 to 700 MWs beginning in 2015, in amounts proportional to their relative
SOS loads. Under the terms of the order, the winning bidder was to construct a 661 MW natural gas-fired combined cycle generation plant in
Waldorf, Maryland, with an
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expected commercial operation date of June 1, 2015, and each of the Contract EDCs was to recover its costs associated with the contract through
surcharges on its respective SOS customers.
In response to a complaint filed by a group of generating companies in the PJM region, on September 30, 2013, the U.S. District Court for the
District of Maryland issued a ruling that the MDPSC’s April 2012 order violated the Supremacy Clause of the U.S. Constitution by attempting to
regulate wholesale prices. In contrast, on October 1, 2013, in response to appeals filed by the Contract EDCs and other parties, the Maryland Circuit
Court for Baltimore City upheld the MDPSC’s orders requiring the Contract EDCs to enter into the contracts.
On October 24, 2013, the Federal district court issued an order ruling that the contracts are illegal and unenforceable. In November 2013 both
the winning bidder and the MDPSC appealed the Federal district court decision to the U.S. Court of Appeals for the Fourth Circuit, which affirmed the
lower Federal court ruling. On November 26, 2014, both the winning bidder and the MDPSC petitioned the U.S. Supreme Court to consider hearing
an appeal of the Fourth Circuit decision. On October 19, 2015, the U.S. Supreme Court agreed to review the decision. On April 19, 2016, the U.S.
Supreme Court unanimously affirmed the Fourth Circuit’s ruling upholding the Federal district court’s decision.
The decision of the Maryland Circuit Court was appealed to the Maryland Court of Special Appeals and was stayed pending decision by the
U.S. Supreme Court. On August 1, 2016, the Contract EDCs submitted a filing requesting that the MDPSC take notice of the U.S. Supreme Court’s
decision, and notifying the MDPSC that the Contract EDCs will dismiss their appeal pending at the Maryland Court of Special Appeals. On
September 14, 2016, the Maryland Court of Special Appeals dismissed the pending appeal and the matter is considered closed.
MDPSC Derecho Storm Order (Exelon and BGE). Following the June 2012 Derecho storm which hit the mid-Atlantic region interrupting
electrical service to a significant portion of the State of Maryland, the MDPSC issued an order on February 27, 2013 requiring BGE and other
Maryland utilities to file several comprehensive reports with short-term and long-term plans to improve reliability and grid resiliency that were due at
various times before August 30, 2013.
On September 3, 2013, BGE filed a comprehensive long term assessment examining potential alternatives for improving the resiliency of the
electric grid and a staffing analysis reviewing historical staffing levels as well as forecasting staffing levels necessary under various storm scenarios.
During the summer of 2014, an evaluation of the reports filed by BGE and other Maryland utilities was undertaken by consultants on behalf of the
MDPSC and MDPSC Staff. The MDPSC Staff also proposed standards for reliability during major events and estimated times of restoration as well
as undertaking an evaluation of performance-based ratemaking principles and methodologies that would more directly and transparently align
reliable service with the utilities’ distribution rates and that reduce returns or otherwise penalize sub-standard performance. The MDPSC held
hearings in September 2014. BGE currently cannot predict the outcome of these proceedings, which may result in increased capital expenditures
and operating costs.
The Maryland Strategic Infrastructure Development and Enhancement Program (Exelon and BGE). In 2013, legislation intended to
accelerate gas infrastructure replacements in Maryland was signed into law. The law established 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
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Combined Notes to Consolidated Financial Statements—(Continued)
(Dollars in millions, except per share data unless otherwise noted)
a subsequent gas base rate proceeding at which time all costs for the infrastructure replacement projects would be rolled into gas distribution rates.
Irrespective of the cap, BGE is required to file a gas rate case every five years under this legislation.
On August 2, 2013, BGE filed its infrastructure replacement plan and associated surcharge. On January 29, 2014, the MDPSC issued a
decision conditionally approving the first five years of BGE’s plan and surcharge. On July 1, 2016, BGE filed an amendment to its infrastructure
replacement plan, which the MDPSC conditionally approved in an order dated November 23, 2016. The revised surcharge reflecting the costs of the
amendment became effective January 1, 2017. On December 2, 2016, BGE filed a surcharge update to be effective February 1, 2017, including a
true-up of cost estimates included in the 2016 surcharge, along with its 2017 project list and projected capital estimates of $131 million to be
included in the 2017 surcharge calculation. The MDPSC subsequently approved BGE’s 2017 project list and the proposed surcharge for 2017, which
included the 2016 surcharge true-up. As of December 31, 2016, BGE recorded a regulatory liability of $2 million, representing the difference
between the surcharge revenues and program costs.
In 2014, the residential consumer advocate in Maryland appealed MDPSC’s decision on BGE’s infrastructure replacement plan and associated
surcharge with the Baltimore City Circuit Court, who affirmed the MDPSC’s decision. On October 10, 2014, the residential consumer advocate
noticed its appeal to the Maryland Court of Special Appeals from the judgment entered by the Baltimore City Circuit Court. During the third quarter of
2015, the residential consumer advocate, MDPSC and BGE filed briefs. Oral argument in this matter was held before the Court of Special Appeals
on November 3, 2015. On January 28, 2016, the Maryland Court of Special Appeals issued a decision affirming the MDPSC’s decision. As the
residential consumer advocate did not appeal the decision of the Court of Special Appeals, the matter is now closed.
Delaware Regulatory Matters
Gas Cost Rates. (Exelon, PHI and DPL) DPL makes an annual GCR filing with the DPSC for the purpose of allowing DPL to recover natural
gas procurement costs through customer rates. In August 2016, DPL made its 2016-2017 GCR filing. The rates proposed in the 2016-2017 GCR
filing would result in a GCR increase of approximately 14%. On September 20, 2016, the DPSC issued an order allowing DPL to place the new rates
into effect on November 1, 2016, subject to refund and pending final DPSC approval.
2016 Delaware Electric and Natural Gas Distribution Base Rates (Exelon, PHI and DPL). On May 17, 2016, DPL filed an application with
the DPSC to increase its annual electric and natural gas distribution base rates by $63 million and $22 million, respectively, based on a requested
ROE of 10.6%. While the DPSC is not required to issue a decision on the application within a specified period of time, Delaware law allowed DPL to
put into effect $2.5 million of each of the rate increases two months after filing the applications which were effective July 16, 2016. On December 1,
2016, the DPSC approved that an additional $30 million in electric distribution base rates be implemented effective December 17, 2016, subject to
refund based on the final DPSC order, and an additional $10 million in gas base rates be implemented effective December 17, 2016, subject to
refund based on the final DPSC order.
2013 Delaware Electric Distribution Base Rates (Exelon, PHI and DPL). In March 2013, and as amended on September 20, 2013, DPL
filed for an electric distribution base rate increase with the DPSC, ultimately requesting an annual increase of $39 million.
In August 2014, the DPSC issued a final order in DPL’s 2013 electric distribution rate case for an annual increase of $15 million and an ROE of
9.7%. Rates became effective on May 1, 2014.
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Combined Notes to Consolidated Financial Statements—(Continued)
(Dollars in millions, except per share data unless otherwise noted)
In September 2014, DPL filed an appeal with the Delaware Superior Court of the DPSC’s August 2014 order in this proceeding, seeking the
court’s review of the DPSC’s decision relating to the recovery of costs associated with one component of employee compensation, certain retirement
benefits and credit facility expenses. The Division of the Public Advocate filed a cross-appeal in September 2014, pertaining to the treatment of a
prepaid pension expense and other postretirement benefit obligations in base rates. Under the Settlement Agreement related to the Merger, the
parties agreed to suspend the appeal and, upon consummation of the Merger, to the withdrawal of the appeal and the cross-appeal with prejudice. In
accordance with the settlement, on April 13, 2016, the parties filed a Stipulation of Dismissal with the court to dismiss the appeal and the cross-
appeal, at which time the matter was closed.
District of Columbia Regulatory Matters
2016 District of Columbia Electric Distribution Base Rates (Exelon, PHI and Pepco). On June 30, 2016, Pepco filed an application with
the DCPSC to increase its annual electric distribution base rates by $86 million, which was updated to $82 million on October 14, 2016, and further
updated to approximately $77 million on February 1, 2017, based on a requested ROE of 10.6%. The DCPSC has issued a procedural schedule
indicating a final decision will be issued by July 25, 2017. Any adjustments to its rates approved by the DCPSC are expected to take effect soon
thereafter. Pepco cannot predict how much of the requested increase the DCPSC will approve.
On April 18, 2016, a party to a separate DCPSC proceeding filed a motion to suspend Pepco’s bill stabilization adjustment (BSA), which
decouples distribution revenues from utility customers from the amount of electricity delivered. On September 9, 2016, the DCPSC denied the
party’s motion and determined that the appropriate forum in which to determine whether the BSA continues to be just and reasonable is in Pepco’s
rate case proceeding. In addition, the DCPSC stated that it was putting Pepco on notice that all funds collected for the BSA from January 2015 to the
issuance of a decision in the rate case proceeding are subject to refund should the DCPSC determine that such funds were not justly or reasonably
collected. On November 22, 2016, following Pepco’s October 7, 2016 request for reconsideration of the order, the DCPSC issued an order stating
that its September 9, 2016 order was not final and confirming that issues related to the BSA, including potential remedial actions, would be
addressed in Pepco’s rate case. Pepco cannot predict the outcome of this matter or the impact of a refund if ordered by the DCPSC.
District of Columbia Power Line Undergrounding Initiative (Exelon, PHI and Pepco). In May 2014, the Council of the District of Columbia
enacted the Electric Company Infrastructure Improvement Financing Act of 2014 (the Improvement Financing Act), which provided enabling
legislation for the District of Columbia Power Line Undergrounding (DC PLUG) initiative which would selectively place underground some of the
District of Columbia’s most outage-prone power lines.
The Improvement Financing Act provides that: (i) Pepco is to fund approximately $500 million of the estimated cost to complete the DC PLUG
initiative, recovering those costs through a volumetric surcharge on the electric bills of Pepco District of Columbia customers; (ii) $375 million of the
DC PLUG initiative cost is to be financed by the District of Columbia’s issuance of securitized bonds, which bonds will be repaid through a volumetric
surcharge (the DDOT surcharge) on the electric bills of Pepco District of Columbia customers that Pepco will remit to the District of Columbia; and
(iii) the remaining costs up to $125 million are to be covered by the existing capital projects program of the District of Columbia Department of
Transportation (DDOT). Pepco will not earn a return on or a return of the cost of the assets funded with the proceeds of the securitized bonds or
assets that are constructed by DDOT under its capital projects program, but ownership and responsibility for the operation and maintenance of such
assets will be transferred to Pepco for a nominal amount.
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Combined Notes to Consolidated Financial Statements—(Continued)
(Dollars in millions, except per share data unless otherwise noted)
In June 2014, Pepco and DDOT filed a Triennial Plan related to the construction of selected underground feeders in the District of Columbia. In
August 2014, Pepco filed an application for the issuance of a financing order to provide for the issuance of the District’s bonds. In March 2016, the
DCPSC’s orders approving the Triennial Plan and the application for financing were upheld upon the resolution of appeals that had been filed with
the District of Columbia Court of Appeals. In compliance with the Improvement Financing Act, on September 30, 2016, Pepco and DDOT filed a
Second Triennial Plan. Recognizing the delays to the First Triennial Plan, Pepco and DDOT requested that the DCPSC hold the Second Triennial
Plan in abeyance, and the DCPSC granted this request by order dated October 27, 2016.
In June 2015, an agency of the federal government served by Pepco asserted that the DDOT surcharge constitutes a tax on end users from
which the federal government is immune. PHI is currently evaluating the assertion and the resolution of this matter will likely further delay
implementation of the DC PLUG initiative.
New Jersey Regulatory Matters
2016 New Jersey Electric Distribution Base Rates (Exelon, PHI and ACE). On August 24, 2016, the NJBPU issued an order approving a
stipulation of settlement among ACE, the New Jersey Division of Rate Counsel, NJBPU Staff and Unimin Corporation, and an increase of $45 million
(before New Jersey sales and use tax) to its electric distribution base rates, with the new rates effective immediately. The stipulation of settlement
provided that a determination on PowerAhead would be separated into a phase II of the rate proceeding and decided at a later date and the parties
would seek to resolve the matter by the end of 2016, although resolution will most likely occur in the first quarter of 2017. PowerAhead includes
capital investments to advance modernization of the electric grid through energy efficiency, increased distributed generation, and resiliency, focused
on improving the distribution system’s ability to withstand major storm events. ACE cannot predict if the NJBPU will approve the PowerAhead
initiative.
Update and Reconciliation of Certain Under-Recovered Balances (Exelon, PHI and ACE). O n February 1, 2016, ACE submitted its 2016
annual petition with the NJBPU seeking to reconcile and update (i) charges related to the recovery of above-market costs associated with ACE’s
long-term power purchase contracts with the non-utility generators and (ii) costs related to surcharges for the New Jersey Societal Benefit Program
(a statewide public interest program that is intended to benefit low income customers and address other public policy goals) and ACE’s uncollectible
accounts.
As filed, the net impact of adjusting the charges as proposed would have been an overall annual rate increase of $9 million (revised to
$19 million in April 2016, based upon an update for actuals through March 2016), including New Jersey sales and use tax.
On November 30, 2016, the NJBPU approved a stipulation of settlement entered into by the parties providing for an overall annual rate
increase of $1 million effective January 1, 2017. This settlement included a credit of approximately $10 million to the Non-Utility Generation charge
deferral balance and a credit of approximately $7 million to the Uncollectible deferral balance. These credits were directed to be applied to the
deferral balances in an NJBPU order dated October 31, 2016. That order approved the Joint Recommendation for Settlement of the Most Favored
Nation Provision, which was a condition of the merger between Exelon Corporation and Pepco Holdings, Inc. This rate increase will have no effect
on ACE’s operating income, since these revenues provide for recovery of deferred costs under an approved deferral mechanism.
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Combined Notes to Consolidated Financial Statements—(Continued)
(Dollars in millions, except per share data unless otherwise noted)
On February 1, 2017, ACE submitted its 2017 annual petition with the NJBPU seeking to reconcile and update the same categories of charges
and costs as set forth in its 2016 annual petition discussed above. The net impact of adjusting the charges as proposed is an overall annual rate
decrease of approximately $29 million, including New Jersey Sales and Use Tax. The matter is pending at the NJBPU and will be updated for
January through March 2017 actual data. ACE has requested that the NJBPU place the new rates into effect by June 1, 2017. There is no assurance
that NJBPU will put final rates in effect by the requested date.
New York Regulatory Matters
New York Clean Energy Standard (Exelon, Generation). On August 1, 2016, the New York Public Service Commission (NYPSC) issued an
order establishing the CES, a component of a Tier 3 ZEC program targeted at preserving the environmental attributes of zero-emissions nuclear-
powered generating facilities that meet the criteria demonstrating public necessity as determined by the NYPSC. The New York State Energy
Research and Development Authority (NYSERDA) will centrally procure the ZECs from eligible plants through a 12-year contract, to be administered
in six two-year tranches, extending from April 1, 2017 through March 31, 2029. ZEC payments will be made to the eligible resources based upon the
number of MWh produced, subject to specified caps and minimum performance requirements. The price to be paid for the ZECs under each tranche
will be 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 increase in underlying energy and capacity prices. The ZEC price for the first tranche
has been set at $17.48 per MWh of production. Following the first tranche, the price will be updated bi-annually. Each Load Serving Entity (LSE)
shall be required to purchase an amount of ZECs equivalent to its load ratio share of the total electric energy in the New York Control Area. Cost
recovery from ratepayers shall be incorporated into the commodity charges on customer bills.
The NYPSC initially identified the three plants eligible for the ZEC program to include, for now, the FitzPatrick, Ginna, and Nine Mile Point
nuclear facilities. As issued, the order also provided that the duration of the program beyond the first tranche was conditional upon a buyer
purchasing the FitzPatrick facility and taking title prior to September 1, 2018. On November 18, 2016, the required contracts with NYSERDA were
executed for Ginna and Nine Mile Point, in addition to Entergy’s execution of the required contract for the FitzPatrick facility.
Several parties filed with the NYPSC requests for rehearing or reconsideration of the CES. Generation and CENG also filed a request for
clarification, or in the alternative limited rehearing, that the condition limiting the duration of the program beyond the first tranche be limited to the
eligibility of the FitzPatrick plant only and have no bearing on Ginna or Nine Mile Point’s eligibility for the full 12-year duration. On December 15,
2016, the NYPSC approved Exelon’s petition to clarify this condition and denied all petitions for rehearing of the CES. Parties have until mid-April to
appeal to New York State court the denials of the requests for rehearing. In addition, one Petition seeking to invalidate the ZEC program was filed in
New York State court on November 30, 2016, and amended on January 13, 2017, arguing that the NYPSC violated certain technical provisions of
the State Administrative Procedures Act (SAPA) when adopting the ZEC program.
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
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Combined Notes to Consolidated Financial Statements—(Continued)
(Dollars in millions, except per share data unless otherwise noted)
and that it discriminates against out of state competitors. On December 9, 2016, Generation and CENG filed a motion to intervene in the case and to
dismiss the lawsuit. The motion to intervene has been granted and the motion to dismiss is pending.
Other legal challenges remain possible, the outcomes of which remain uncertain. See Note 9—Early Nuclear Plant Retirements for additional
information relative to Ginna and Nine Mile Point, and Note 4—Mergers, Acquisitions, and Dispositions for additional information on Generation’s
proposed acquisition of FitzPatrick.
Ginna Nuclear Power Plant Reliability Support Services Agreement (Exelon and Generation). 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 Reliability Support Services Agreement (RSSA) to support the continued operation of Ginna to maintain the
reliability of the RG&E transmission grid for a specified period of time. During 2015 and 2016, Ginna and RG&E made filings with the NYPSC and
FERC for their approval of the proposed RSSA. Although the RSSA was still subject to regulatory approvals, on April 1, 2015, Ginna began
delivering the power and capacity from the Ginna plant into the ISO-NY consistent with the technical provisions of the RSSA.
On March 22, 2016, Ginna submitted a compliance filing with FERC with revisions to the RSSA requested by FERC. On April 8, 2016, FERC
accepted the compliance filing and on April 20, 2016, the NYPSC accepted the revised RSSA. Because all regulatory approvals for the RSSA have
now been received, Generation began recognizing revenue based on the final approved pricing contained in the RSSA. Generation also recognized
a one-time revenue adjustment in April 2016 of approximately $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 will be removed from
Generation’s results of operations as a result of the noncontrolling interests in CENG.
The RSSA approved by the regulatory authorities has a term expiring on March 31, 2017, subject to possible extension in the event that RG&E
needs additional time to complete transmission upgrades to address reliability concerns. In March 2016, RG&E notified Ginna that RG&E expects to
complete the transmission upgrades prior to the RSSA expiration in March 2017 and will not need Ginna as an ongoing reliability solution after that
date.
The approved RSSA requires Ginna to continue operating through the RSSA term. If Ginna did not plan to retire shortly after the expiration of
the RSSA, Ginna was required to file a notice to that effect with the NYPSC no later than September 30, 2016. Under the terms of the RSSA, if
Ginna continues to operate after June 14, 2017, Ginna would be required to make certain refund payments up to a maximum of $20 million to RG&E
related to capital expenditures. 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 CES. As stated previously, on November 18, 2016 the required contract with NYSERDA was executed by Generation and CENG for
Ginna. Subject to prevailing over any administrative or legal challenges, it is expected the CES will allow Ginna to continue to operate through the
end of its current operating license in 2029. See Note 9—Early Nuclear Plant Retirements for additional discussion of Ginna.
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Federal Regulatory Matters
Combined Notes to Consolidated Financial Statements—(Continued)
(Dollars in millions, except per share data unless otherwise noted)
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. 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. ComEd, BGE, Pepco, DPL, and ACE record
regulatory assets or regulatory liabilities and corresponding increases or decreases to operating revenues for any differences between the revenue
requirement in effect and ComEd’s, BGE’s, Pepco’s, DPL’s and ACE’s best estimate of the revenue requirement expected to be filed with the FERC
for that year’s reconciliation. The regulatory asset associated with transmission true-up is amortized to Operating revenues within their Consolidated
Statements of Operations of Comprehensive Income as the associated amounts are recovered through rates. On December 13, 2016, BGE filed
with the FERC to modify its FERC-approved formula to recover its existing regulatory asset and any future changes to its regulatory asset
concerning various tax issues including certain deferred income taxes.
For each of the following years, the following total increases/(decreases) were included in ComEd’s, BGE’s, Pepco’s, DPL’s and ACE’s electric
transmission formula rate filings:
Annual Transmission
Filings
Initial revenue requirement increase
Annual reconciliation increase (decrease)
Dedicated facilities increase (a)
Total revenue requirement increase
Allowed return on rate base (c)
Allowed ROE (d)
Effective date of rates
$
$
2016
90
4
—
94
8.47%
11.50%
ComEd
2015
$
$
68
18
—
86
8.61%
11.50%
2014
2016
$
$
36
(14)
—
22
8.62%
11.50%
$
$
12
3
13
28
8.09%
10.50%
$
$
BGE
2015
—
(3)
13
10
8.46%
11.30%
$
$
2014
9
5
3
17
8.53%
11.30%
June 2016
June 2015
June 2014
June 2016
June 2015
June 2014
2016
Pepco
2015
2014
2016
DPL
2015
2014
2016
ACE
2015
2014
$
2
$
10
$
(9)
$
8
$
15
$
4
$
8
$
10
$
(10)
(15)
(3)
(2)
(1)
17
(10)
(12)
(1)
(2)
6
15
(14)
—
2
4
3
—
—
(23)
$
5
$
7
$
(14)
$
12
$
25
$
(6)
$
12
$
7
Allowed ROE (d)
Effective date of rates (e) June 2016
7.88%
10.50%
8.36%
11.30%
8.60%
11.30%
7.21%
10.50%
7.80%
11.30%
8.05%
11.30%
7.83%
10.50%
8.51%
11.30%
8.66%
11.30%
June 2015
June 2014
June 2016
June 2015
June 2014
June 2016
June 2015
June 2014
(a) BGE’s transmission revenues include a FERC approved dedicated facilities charge to recover the costs of providing transmission service to specifically designated load by
(b)
BGE.
In 2012, PJM terminated the MAPP transmission line construction project planned for the Pepco and DPL service territories. Pursuant to a FERC approved settlement
agreement, the abandonment costs associated with MAPP were being recovered in transmission rates over a three-year period that ended in May 2016.
(c) Represents to the weighted average debt and equity return on transmission rate bases.
357
Annual Transmission
Filings
Initial revenue
requirement
increase (decrease)
Annual reconciliation
(decrease) increase
MAPP abandonment
recovery (decrease)
increase (b)
Total revenue
requirement (decrease)
increase
$
Allowed return on rate
base (c)
Table of Contents
Combined Notes to Consolidated Financial Statements—(Continued)
(Dollars in millions, except per share data unless otherwise noted)
(d) As part of the FERC-approved settlement of ComEd’s 2007 transmission rate case, the rate of return on common equity is 11.50% 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 10.5%, inclusive of a 50 basis point incentive adder for being
a member of a regional transmission organization.
(e) The time period for any challenges to the annual transmission formula rate update flings expired with no challenges submitted.
PJM Transmission Rate Design and Operating Agreements (Exelon, Generation, ComEd, PECO, BGE, PHI, Pepco, DPL and ACE).
PJM Transmission Rate Design specifies the rates for transmission service charged to customers within PJM. Currently, ComEd, PECO, BGE,
Pepco, DPL and ACE incur costs based on the existing rate design, which charges customers based on the cost of the existing transmission
facilities within their load zone and the cost of new transmission facilities based on those who benefit from those facilities. In April 2007, FERC
issued an order concluding that PJM’s current rate design for existing facilities is just and reasonable and should not be changed. In the same order,
FERC held that the costs of new facilities 500 kV and above should be socialized across the entire PJM footprint and that the costs of new facilities
less than 500 kV should be allocated to the customers of the new facilities who caused the need for those facilities. A number of parties appealed to
the U.S. Court of Appeals for the Seventh Circuit for review of the decision.
In August 2009, the court issued its decision affirming the FERC’s order with regard to the existing facilities, but remanded to FERC the issue
of the cost allocation associated with the new facilities 500 kV and above (Cost Allocation Issue) for further consideration by the FERC. On remand,
FERC reaffirmed its earlier decision to socialize the costs of new facilities 500 kV and above. A number of parties filed appeals of these orders. In
June 2014, the court again remanded the Cost Allocation Issue to FERC. On December 18, 2014, FERC issued an order setting an evidentiary
hearing and settlement proceeding regarding the Cost Allocation Issue. On June 15, 2016, a number of parties, including Exelon and the Utility
Registrants filed an Offer of Settlement with FERC. Each state that is a party in this proceeding either signed, or will not oppose, the settlement. If
the Settlement is approved, effective January 1, 2016, for the costs of the 500 kV facilities approved by the PJM Board on or after February 1, 2013,
50% will be socialized across PJM and 50% will be allocated according to an engineering formula that calculates the flows on the transmission
facilities. The Settlement includes provisions for monthly credits or charges that are expected to be mostly refunded or recovered through customer
rates over a 10-year period based on negotiated numbers for charges prior to January 1, 2016.
Exelon expects that the Settlement will not have a material impact on the results of operations, cash flows and financial position of Generation,
ComEd, PECO, BGE, Pepco, DPL or ACE. The Settlement is subject to approval by FERC.
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Combined Notes to Consolidated Financial Statements—(Continued)
(Dollars in millions, except per share data unless otherwise noted)
The Utility Registrants are committed to the construction of transmission facilities under their operating agreements with PJM to maintain
system reliability. The Utility Registrants will work with PJM to continue to evaluate the scope and timing of any required construction projects. The
Utility Registrant’s estimated commitments are as follows:
ComEd
PECO
BGE
Pepco
DPL
ACE
2019
2017 2018
Total
$ 97 $ 64 $ 28 $
14
113
6
47
36
34
226
104
63
93
10
55
39
16
39
2021
2020
5 $ — $ —
1
2
7
—
14
44
—
19
40
—
—
—
—
—
18
Complaints at FERC Seeking to Mitigate Illinois and New York Programs Providing ZECs (Exelon and Generation). 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 remove the revenues it receives through a federal, state or other 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 resources. Exelon has generally opposed policies that require subsidies or give preferential treatment to generation providers or technologies
that do not provide superior reliability or environmental benefits, or that would threaten the reliability and value of the integrated electricity grid. Thus,
Exelon has supported a MOPR as a means of minimizing the detrimental impact certain subsidized resources could have on capacity markets (such
as the New Jersey (LCAPP) and Maryland (CfD) programs). However, in Exelon’s view, MOPRs should not be applied to resources that receive
compensation for providing superior reliability or environmental benefits.
On January 9, 2017, the Electric Power Supply Association (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. Both filings allege that the
relevant MOPR should be expanded to also apply to existing resources receiving ZEC compensation under the New York CES and Illinois ZES
programs. Exelon has 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 that have generally not been subject to a MOPR. However, if successful, an expanded MOPR
could result in mitigation of Generation’s Quad Cities, Ginna, and Nine Mile Point facilities, which are expected to receive ZEC compensation, such
that they would have an increased risk of not clearing in future capacity auctions and thus of no longer receiving capacity revenues during the
respective ZEC programs. This would also impact the FitzPatrick facility that Generation is currently in the process of acquiring from Entergy. 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
timing of FERC’s decision with respect to both proceedings is currently unknown and the outcome of these matters is currently uncertain.
Demand Response Resource Order (Exelon, Generation, ComEd, PECO, BGE, PHI, Pepco, DPL and ACE). On May 23, 2014, the D.C.
Circuit Court issued an opinion vacating the FERC Order No. 745 (D.C. Circuit Decision). Order No. 745 established uniform compensation levels for
demand response resources that participate in the day ahead and real-time wholesale energy markets. Under Order No. 745, buyers in ISO and
RTO markets were required to pay demand response resources the full Locational Marginal Price when the demand response replaced a generation
resource and was
359
Table of Contents
Combined Notes to Consolidated Financial Statements—(Continued)
(Dollars in millions, except per share data unless otherwise noted)
cost-effective. On January 25, 2016, the U.S. Supreme Court reversed the D.C. Circuit Court decision and remanded the matter to the D.C. Circuit
Court. While Exelon cannot predict exactly how the D.C. Circuit Court will handle the matter on remand, Exelon does not expect there will be any
significant change in how demand response resources have or will participate in and be paid by wholesale energy markets. Thus, Exelon does not
anticipate that there will be any impact to the Registrants’ results of operations or cash flows based on these proceedings.
New England Capacity Market Results (Exelon and Generation). On February 28, 2014, ISO-NE filed the results of its eighth capacity
auction (covering the June 1, 2017 through May 31, 2018 delivery period). On June 27, 2014, the FERC issued a letter to ISO-NE noting that
ISO-NE’s February 28, 2014 filing was deficient and that ISO-NE must file additional information before the FERC can process the filing. ISO-NE
filed the information on July 17, 2014, and the ISO-NE’s filings became effective by operation of law pursuant to a notice issued by the secretary of
FERC on September 16, 2014. Several parties sought rehearing of the secretary’s notice which was effectively denied in October 2014 and have
since appealed the matter to the D.C. Circuit Court. On October 25, 2016, the D.C. Circuit Court dismissed the appeal.
Operating License Renewals (Exelon and Generation). Generation has 40-year operating license from the NRC for each of its nuclear
units. The operating license renewal process takes approximately four to five years from the commencement of the renewal process until completion
of the NRC’s review.
On December 9, 2014, Generation submitted an application to the NRC to extend the current operating licenses of LaSalle Units 1 and 2 by 20
years. On October 19, 2016, the NRC approved Generation’s request to extend the operating licenses of LaSalle units 1 and 2 by 20 years to 2042
and 2043, respectively.
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
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. In addition, Generation continues to work with MDE and
other Federal and Maryland state agencies to conduct and fund an additional sediment and nutrient monitoring study.
On August 7, 2015, US Fish and Wildlife Service of the US Department of the Interior (Interior) submitted its modified fishway prescription to
FERC in the Conowingo licensing proceedings. On September 11, 2015, Exelon filed a request for an administrative hearing and proposed an
alternative prescription to challenge Interior’s preliminary prescription. On April 21, 2016, Exelon and Interior executed a Settlement Agreement
resolving all fish passage issues between the parties. Accordingly, on April 22, 2016, Exelon withdrew its Request for a Trial-Type Hearing and
Alternative Prescription. The financial impact of the Settlement Agreement is estimated to be $3 million to $7 million per year, on average, over the
46-year 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. Resolution of the remaining issues relating to Conowingo involving
various stakeholders may have a material effect on Exelon’s and Generation’s results of operations and financial position through an increase in
capital expenditures and operating costs. As of December 31, 2016, $28 million of direct costs associated with Conowingo licensing efforts have
been capitalized-to-date.
360
Table of Contents
Combined Notes to Consolidated Financial Statements—(Continued)
(Dollars in millions, except per share data unless otherwise noted)
Regulatory Assets and Liabilities (Exelon, ComEd, PECO, BGE, PHI, Pepco, DPL and ACE)
Exelon, ComEd, PECO, BGE, PHI, Pepco, DPL and ACE each prepare their consolidated financial statements in accordance with the
authoritative guidance for accounting for certain types of regulation. Under this guidance, 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.
As a result of applying the acquisition method of accounting and pushing it down to the consolidated financial statements of PHI, certain
regulatory assets and liabilities were established at Exelon and PHI to offset the impacts of fair valuing the acquired assets and liabilities assumed
which are subject to regulatory recovery. In total, Exelon and PHI recorded a net $2.4 billion regulatory asset reflecting adjustments recorded as a
result of the acquisition method of accounting. See Note 4—Mergers, Acquisitions and Dispositions for additional information.
361
Table of Contents
Combined Notes to Consolidated Financial Statements—(Continued)
(Dollars in millions, except per share data unless otherwise noted)
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, 2016 and December 31, 2015:
December 31, 2016
Regulatory assets
Pension and other postretirement benefits
Deferred income taxes
AMI programs
Under-recovered distribution service costs
Debt costs
Fair value of long-term debt
Fair value of PHI’s unamortized energy contracts
Severance
Asset retirement obligations
MGP remediation costs
Under-recovered uncollectible accounts
Renewable energy
Energy and transmission programs
Deferred storm costs
Electric generation-related regulatory asset
Rate stabilization deferral
Energy efficiency and demand response programs
Merger integration costs
Under-recovered revenue decoupling
COPCO acquisition adjustment
Recoverable workers compensation and long-term disability
costs
Vacation accrual
Securitized stranded costs
CAP arrearage
Removal costs
Other
Total regulatory assets
Less: current portion
Total noncurrent regulatory assets
Exelon ComEd
PECO BGE
PHI
Pepco
DPL ACE
Successor
$ 4,162 $ — $ — $ — $ — $ — $ — $ —
51
—
—
6
—
—
—
—
—
—
2
17
18
—
—
—
—
—
—
1,583 98
49 230
— —
1
7
— —
— —
5
—
23 12
26
1
— —
— —
— 38
1
—
— 10
7
—
1 285
— 10
3
—
— —
2,016
701
188
124
812
1,085
5
111
305
56
260
89
36
10
7
621
25
27
8
75
164
188
42
—
—
—
76
278
56
258
23
—
—
—
—
—
—
—
171
174
—
17
—
—
—
—
—
—
—
6
12
—
—
250
11
21
—
260
258
—
81
671
1,085
—
—
—
—
2
28
35
—
—
335
15
24
8
38
84
—
9
—
—
—
—
—
—
—
5
5
—
—
85
4
3
8
34
31
138
11
477
49
11,388
1,342
—
10
138
—
255
4
501
96
$10,046 $ 977 $1,681 $504 $ 2,851 $ 690 $289 $405
— —
7 —
— —
11 —
— —
9
5
1,710 712
29 208
—
—
—
—
—
7
1,167
190
34
—
—
—
134
22
852
162
34
24
138
—
477
29
3,504
653
—
14
—
—
88
5
348
59
362
Table of Contents
Combined Notes to Consolidated Financial Statements—(Continued)
(Dollars in millions, except per share data unless otherwise noted)
December 31, 2016
Regulatory liabilities
Other postretirement benefits
Nuclear decommissioning
Removal costs
Deferred rent
Energy efficiency and demand response programs
DLC program costs
Electric distribution tax repairs
Gas distribution tax repairs
Energy and transmission programs
Other
Total regulatory liabilities
Less: current portion
Total noncurrent regulatory liabilities
Exelon ComEd PECO BGE
Pepco DPL ACE
Successor
PHI
$
2,607
1,601
39
185
8
76
20
134
72
4,789
602
47 $ — $ — $ — $ — $ — $ — $ —
—
—
—
—
—
—
—
5
20
25
25
158 $ 20 $ 97 $ —
2,169
1,324
—
141
—
—
—
60
4
3,698
329
—
18
—
3
—
—
—
8
2
31
11
438
—
—
41
8
76
20
56
5
644
127
—
118
—
—
—
—
—
5
17
140
43
—
141
—
—
—
—
—
—
19
160
50
—
136
39
3
—
—
—
18
41
237
79
$4,187 $3,369 $ 517 $110 $
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Table of Contents
Combined Notes to Consolidated Financial Statements—(Continued)
(Dollars in millions, except per share data unless otherwise noted)
December 31, 2015
Regulatory assets
Pension and other postretirement benefits
Deferred income taxes
AMI programs
Under-recovered distribution service costs
Debt costs
Fair value of long-term debt
Severance
Asset retirement obligations
MGP remediation costs
Under-recovered uncollectible accounts
Renewable energy
Energy and transmission programs
Deferred storm costs
Electric generation-related regulatory asset
Rate stabilization deferral
Energy efficiency and demand response programs
Merger integration costs
Conservation voltage reduction
Under-recovered revenue decoupling
COPCO acquisition adjustment
Workers compensation and long-term disability costs
Vacation accrual
Securitized stranded costs
CAP arrearage
Removal costs
Other
Total regulatory assets
Less: current portion
Total noncurrent regulatory assets
Exelon ComEd
PECO BGE
Pepco DPL ACE
Predecessor
PHI
$3,156 $ — $ — $ — $
1,616
399
189
47
162
9
108
286
52
247
84
2
20
87
279
6
3
30
—
—
6
—
7
—
29
6,824
759
64
140
189
46
—
—
67
255
52
247
43
—
—
—
—
—
—
—
—
—
—
—
—
—
10
1,113
218
1,473
63
—
1
—
—
22
30
—
—
1
—
—
—
1
—
—
—
—
—
6
—
7
—
13
1,617
34
79
196
—
8
—
9
19
1
—
—
40
2
20
87
278
6
3
30
—
—
—
—
—
—
3
781
267
$6,065 $ 895 $1,583 $514 $
364
910 $ — $ — $ —
41
214
—
267
—
—
7
36
—
—
—
—
—
1
—
—
—
—
5
6
13
33
18
43
—
—
—
—
1
401
—
—
—
—
—
14
—
—
—
31
9
23
202
202
—
—
208
369
8
32
512
2,582
98
305
2,277 $ 661 $299 $414
137
180
—
19
—
—
1
—
—
—
9
19
—
—
289
—
—
10
—
31
—
—
—
92
14
801
140
36
87
—
10
—
—
—
—
—
1
11
6
—
—
111
—
—
4
13
—
14
—
—
69
9
371
72
Table of Contents
Combined Notes to Consolidated Financial Statements—(Continued)
(Dollars in millions, except per share data unless otherwise noted)
December 31, 2015
Regulatory liabilities
Other postretirement benefits
Nuclear decommissioning
Removal costs
Energy efficiency and demand response programs
DLC program costs
Electric distribution tax repairs
Gas distribution tax repairs
Energy and transmission programs
Over-recovered revenue decoupling
Other
Total regulatory liabilities
Less: current portion
Exelon ComEd PECO
BGE
PHI
Pepco
DPL ACE
Predecessor
$
94 $ — $ — $ — $
2,577
1,527
92
9
95
28
131
1
16
4,570
369
2,172
1,332
52
—
—
—
53
—
5
3,614
155
405
—
40
9
95
28
60
—
2
639
112
—
195
—
—
—
—
18
1
8
222
38
— $ — $ — $ —
—
—
—
150
1
1
—
—
—
—
—
—
8
27
—
—
16
35
25
213
18
66
7
—
21
—
—
—
—
16
—
7
44
15
147 $ 29 $111 $
—
129
—
—
—
—
19
—
12
160
49
Total noncurrent regulatory liabilities
$4,201 $3,459 $ 527 $184 $
Pension and other postretirement benefits. As of December 31, 2016, Exelon had regulatory assets of $3,075 and regulatory liabilities of
$47 million related to ComEd’s and BGE’s portion of deferred costs associated with Exelon’s pension plans and ComEd’s, PECO’s and BGE’s
portion of deferred costs associated with Exelon’s other postretirement benefit plans. PECO’s pension regulatory recovery is based on cash
contributions and is not included in the regulatory asset (liability) balances. The regulatory asset (liability) is amortized in proportion to the recognition
of prior service costs (gains), transition obligations and actuarial losses (gains) attributable to Exelon’s pension and other postretirement benefit
plans determined by the cost recognition provisions of the authoritative guidance for pensions and postretirement benefits. ComEd, PECO and BGE
will recover these costs through base rates as allowed in their most recently approved regulated rate orders. The pension and other postretirement
benefit regulatory asset balance includes a regulatory asset established at the date of the Constellation merger related to BGE’s portion of the
deferred costs associated with legacy Constellation’s pension and other postretirement benefit plans. The BGE-related regulatory asset is being
amortized over a period of approximately 12 years, which generally represents the expected average remaining service period of plan participants at
the date of the Constellation merger. As of December 31, 2016, the pension and other postretirement benefits regulatory asset at Exelon includes
regulatory assets of $1,087 million established at the date of the PHI Merger related to unrecognized costs that are probable of regulatory recovery.
The regulatory assets are amortized and recovered over periods from 3 to 15 years, depending on the underlying component. Pepco, DPL and ACE
are currently recovering these costs through base rates. Pepco, DPL and ACE are not earning a return on the recovery of these costs in base rates.
See Note 17—Retirement Benefits for additional detail. No return is earned on Exelon’s regulatory asset.
Deferred income taxes. These costs represent the difference between the method by which the regulator allows for the recovery of income
taxes and how income taxes would be recorded under GAAP. Regulatory assets and liabilities associated with deferred income taxes, recorded in
compliance with the authoritative guidance for accounting for certain types of regulation and income taxes, include the deferred tax effects
associated principally with accelerated depreciation accounted for in accordance with the ratemaking policies of the ICC, PAPUC and MDPSC, as
well as the revenue impacts thereon, and assume continued recovery of these costs in future transmission and distribution rates. For BGE, this
amount includes the impacts of a reduction in the deductibility, for Federal income
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Combined Notes to Consolidated Financial Statements—(Continued)
(Dollars in millions, except per share data unless otherwise noted)
tax purposes, of certain retiree health care costs pursuant to the March 2010 Health Care Reform Acts. For BGE, these additional income taxes are
being amortized over a 5-year period that began in March 2011 in accordance with the MDPSC’s March 2011 rate order. For PECO, this amount
includes the impacts of electric and gas distribution repairs in the deductibility pursuant to PUC’s 2010 and 2015 rate case settlement agreements.
As of December 31, 2016, includes transmission-related regulatory assets that require FERC approval separate from the transmission formula rate
of $22 million, $38 million, $31 million, $20 million and $19 million for ComEd, BGE, Pepco, DPL and ACE, respectively. As of December 31, 2015,
includes transmission-related regulatory assets that require FERC approval separate from the transmission formula rate of $15 million, $16 million,
$26 million, $18 million and $15 million for ComEd, BGE, Pepco, DPL and ACE, respectively. See Note 15—Income Taxes, Note 17—Retirement
Benefits, and the Transmission Formula Rate section above for additional information. ComEd, PECO, BGE, Pepco, DPL and ACE are not earning a
return on the regulatory asset in rates. The recovery period is over the life of the associated assets.
AMI programs. For ComEd, this amount represents meter costs associated with ComEd’s AMI pilot program approved in ComEd’s 2010 rate
case. The recovery periods for these meter costs are through January 2020. As of December 31, 2016 and December 31, 2015, ComEd had
regulatory assets of $162 million and $137 million, respectively, related to accelerated depreciation costs resulting from the early retirements of
non-AMI meters, which will be amortized over an average ten year period pursuant to the ICC approved AMI Deployment plan. ComEd is earning a
return on the regulatory asset. For PECO, this amount primarily represents accelerated depreciation on PECO’s non-AMI meter assets over a
10-year period ending December 31, 2020. Recovery of smart meter costs are reflected in base rates effective January 1, 2016. For BGE, this
amount represents AMI costs associated with the installation of smart meters and the early retirement of legacy meters. The incremental costs
associated with the installation, along with depreciation, amortization, and an appropriate return, had been building in a regulatory asset since the
MDPSC approved the comprehensive smart grid initiative for BGE in August 2010 through approval of the program in BGE’s rate order issued June,
2016. As of December 31, 2016, the balance of BGE’s regulatory asset was $230 million, which consists of three major components, including
$144 million of unamortized incremental deployment costs of the AMI program, $54 million of unamortized costs of the non-AMI meters replaced
under the program, and $32 million related to post-test year incremental program deployment costs incurred prior to when approval became effective
June 2016. The incremental deployment costs for the AMI program and the non-AMI meter components of the regulatory asset are being amortized
and recovered through rates over a 10-year period, which began in June, 2016. A return on the $144 million incremental deployment costs for the
AMI program portion of the regulatory asset is included in rates. The $54 million portion of the regulatory asset related to the unamortized cost of the
retired non-AMI meters is not earning a return in rates. The $32 million portion related to post-test year incremental program deployment costs have
not yet been approved for recovery by the MDPSC and are not currently earning a return for financial reporting purposes. For PHI, this amount
represents AMI costs associated with the installation of smart meters and the early retirement of legacy meters throughout the service territories for
Pepco and DPL. An AMI program has not been approved by the NJBPU for ACE in New Jersey. Pepco has received approval for recovery of
deferred AMI program costs from the DCPSC and the MDPSC in its DC and Maryland service territories. Pepco does earn a return on the AMI
deployment costs, but not on the early retirement of legacy meters. DPL has received approval for recovery of deferred AMI program costs from the
DPSC in its Delaware service territory and has received a proposed order from the MDPSC approving recovery of deferred AMI program costs in its
Maryland service territory. As of December 31, 2016, the DPL deferred AMI program costs pending finalization of the proposed order from the
MDPSC are $41 million, of which $14 million relates to retired legacy meters which are not earning a return.
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Table of Contents
Combined Notes to Consolidated Financial Statements—(Continued)
(Dollars in millions, except per share data unless otherwise noted)
Under-recovered distribution services costs. These amounts represent under recoveries related to electric distribution services costs
recoverable through EIMA’s performance based formula rate. Under (over) recoveries for the annual reconciliations are recoverable (refundable)
over a one-year period and costs for certain one-time events, such as large storms, are recoverable over a five-year period. ComEd earns and pays
a return on under and over-recovered costs, respectively. As of December 31, 2016, the regulatory asset was comprised of $134 million for the 2015
to 2016 annual reconciliations and $54 million related to significant one-time events, including $20 million in deferred storm costs and $11 million of
Constellation and PHI merger and integration related costs, and $23 million of smart meter related costs. ComEd’s 2015 annual reconciliation
regulatory asset includes a reduction of $8 million related to a ComEd-proposed refund to customers for the impact of changing its OSHA recordable
rate for 2014 and 2015. As of December 31, 2015, the regulatory asset was comprised of $142 million for the 2014 and 2015 annual reconciliations
and $47 million related to significant one-time events, including $36 million in deferred storm costs and $11 million of Constellation merger and
integration related costs.
Debt costs. Consistent with rate recovery for ratemaking purposes, ComEd’s, PECO’s, BGE’s, Pepco’s, DPL’s and ACE’s recoverable losses
on reacquired long-term debt related to regulated operations are deferred and amortized to interest expense over the life of the new debt issued to
finance the debt redemption or over the life of the original debt issuance if the debt is not refinanced. Interest-rate swap settlements are deferred and
amortized over the period that the related debt is outstanding or the life of the original issuance retired. These debt costs are used in the
determination of the weighted cost of capital applied to rate base in the rate-making process. ComEd and BGE are not earning a return on these
costs. Recovery of these costs will continue through 2038 for ComEd and BGE. PECO, Pepco, DPL and ACE are earning a return on the premium
of the cost of the reacquired debt through base rates. The regulatory asset for Pepco, DPL and ACE was eliminated at Exelon and PHI as part of
acquisition accounting.
Fair value of long-term debt. These amounts represent the unamortized regulatory assets recorded at Exelon for the difference between the
carrying value and fair value of the long-term debt of BGE as of the Constellation merger date based on the MDPSC practice to allow BGE to
recover its debt costs through rates and at Exelon and PHI for the difference between carrying value and fair value of long-term debt of Pepco, DPL
and ACE as of the PHI Merger date. Exelon is amortizing the regulatory asset and the associated fair value over the life of the underlying debt and is
not earning a return on the recovery of these costs.
Fair value of PHI’s unamortized energy contracts. These amounts represent the regulatory asset recorded at Exelon and PHI offsetting the
fair value adjustments 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. Pepco, DPL and ACE are allowed full recovery of the costs of these contracts through their respective rate making processes.
Severance. For BGE, these costs represent deferred severance costs associated with a 2010 workforce reduction that were deferred as a
regulatory asset and are being amortized over a 5-year period that began in March 2011 in accordance with the MDPSC’s March 2011 rate
order. Additionally, costs associated with the 2012 BGE voluntary workforce reduction were deferred in 2012 as a regulatory asset in accordance
with the MDPSC’s orders in prior rate cases and are being amortized over a 5-year period that began in July 2012. BGE is earning a regulated return
on the regulatory asset included in base rates.
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Table of Contents
Combined Notes to Consolidated Financial Statements—(Continued)
(Dollars in millions, except per share data unless otherwise noted)
Asset retirement obligations. These costs represent future legally required removal costs associated with existing asset retirement
obligations. PECO will begin to earn a return on, and a recovery of, these costs once the removal activities have been performed. ComEd and BGE
will recover these costs through future depreciation rates and will earn a return on these costs once the removal activities have been performed. The
recovery period will be over the expected life of the related assets. See Note 16—Asset Retirement Obligations for additional information.
MGP remediation costs . ComEd is allowed recovery of these costs under ICC approved rates. For PECO, these costs are recoverable
through rates as affirmed in the 2010 approved natural gas distribution rate case settlement. The period of recovery for both ComEd and PECO will
depend on the timing of the actual expenditures, c urrently estimated to be completed in 2022 for both ComEd and PECO. ComEd and PECO are
not earning a return on the recovery of these costs. While BGE does not have a rider for MGP clean-up costs, BGE has historically received
recovery of actual clean-up costs on a site-specific basis in distribution rates. For BGE, $5 million of clean-up costs incurred during the period from
July 2000 through November 2005 and an additional $1 million from December 2005 through November 2010 are recoverable through rates in
accordance with MDPSC orders. BGE is earning a return on this regulatory asset and these costs are being amortized over 10-year periods that
began in January 2006 and December 2010, respectively. The recovery period for the 10-year period that began January 2006 was extended for an
additional 24 months, in accordance with the MDPSC approved 2014 electric and natural gas distribution rate case order. See Note 24—
Commitments and Contingencies for additional information.
Under recovered uncollectible accounts. These amounts represent the difference between ComEd’s annual uncollectible accounts expense
and revenues collected in rates through an ICC-approved rider. The difference between net uncollectible account charge-offs and revenues collected
through the rider each calendar year is recovered or refunded over a twelve-month period beginning in June of the following calendar year. ComEd
does not earn a return on these under recoveries.
Renewable energy. In December 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 through 2032 in order to meet a portion of its obligations under the Illinois
RPS. Delivery under the contracts began in June 2012. Since the swap contracts were deemed prudent by the Illinois Settlement Legislation,
ensuring ComEd of full recovery in rates, the changes in fair value each period as well as an offsetting regulatory asset or liability are recorded by
ComEd. ComEd does not earn (pay) a return on the regulatory asset (liability). Recovery of these costs will continue through 2032. The basis for the
mark-to-market derivative asset or liability position is based on the difference between ComEd’s cost to purchase energy at the market price and the
contracted price.
Energy and transmission programs. These amounts represent under (over) recoveries related to energy and transmission costs recoverable
(refundable) under ComEd’s ICC and/or FERC-approved rates. Under (over) recoveries are recoverable (refundable) over a one-year period or less.
ComEd earns a return or interest on under-recovered costs and pays interest on over-recovered costs to customers. As of December 31, 2016,
ComEd’s regulatory asset of $23 million included $15 million associated with transmission costs recoverable through its FERC approved formula
rate and $8 million of Constellation merger and integration costs to be recovered upon FERC approval. As of December 31, 2016, ComEd’s
regulatory liability of $60 million included $30 million related to over-recovered energy costs and $30 million associated with revenues received for
renewable energy requirements. As of December 31, 2015, ComEd’s regulatory asset of $43 million included $5 million
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Combined Notes to Consolidated Financial Statements—(Continued)
(Dollars in millions, except per share data unless otherwise noted)
related to under-recovered energy costs, $31 million associated with transmission costs recoverable through its FERC-approved formula rate tariff,
and $7 million of Constellation merger and integration costs to be recovered upon FERC approval. As of December 31, 2015, ComEd’s regulatory
liability of $53 million included $29 million related to over-recovered energy costs and $24 million associated with revenues received for renewable
energy requirements. See Transmission Formula Rate above for further details.
The PECO energy costs represent the electric and gas supply related costs recoverable (refundable) under PECO’s GSA and PGC,
respectively. PECO earns interest on the under-recovered energy and natural gas costs and pays interest on over-recovered energy and natural gas
costs to customers. In addition, the DSP Program costs are presented on a net basis with PECO’s GSA under (over)-recovered energy costs. These
amounts represent recoverable administrative costs incurred relating to the filing and procurement associated with PECO’s PAPUC-approved DSP
programs for the procurement of electric supply. The filings and procurements of these DSP Programs are recoverable through the GSA over each
respective term. DSP II and DSP III each have a 24-month term that began June 1, 2013 and June 1, 2015, respectively. The independent evaluator
costs associated with conducting procurements are recoverable over a 12-month period after the PAPUC approves the results of the procurements.
PECO is not earning a return on these costs. Certain costs included in PECO’s original DSP program related to information technology
improvements were recovered over a 5-year period that began January 1, 2011. PECO earns a return on the recovery of information technology
costs. The PECO transmission costs represent the electric transmission costs recoverable (refundable) under the TSC under which PECO earns
interest on under-recovered costs and pays interest on over-recovered costs to customers. As of December 31, 2016, PECO’s regulatory liability of
$56 million included $34 million related to over-recovered costs under the DSP program, $10 million related to over-recovered non-bypassable
transmission service charges, $8 million related to the over-recovered natural gas costs under the PGC and $4 million related to over-recovered
electric transmission costs. As of December 31, 2015, PECO’s regulatory asset of $1 million related to under-recovered non-bypassable
transmission service charges. As of December 31, 2015, PECO’s regulatory liability of $60 million included $35 million related to over-recovered
costs under the DSP program, $22 million related to the over-recovered natural gas costs under the PGC and $3 million related to the over-
recovered electric transmission costs.
The BGE energy costs represent the electric supply, gas supply, and transmission related costs recoverable (refundable) from (to) customers
under BGE’s market-based SOS program, MBR program, and FERC approved transmission rates, respectively. BGE earns or pays interest to
customers on under-recovered or over-recovered FERC transmission formula-related costs. BGE does not earn or pay interest to customers on
under-recovered or over-recovered SOS and MBR costs. The recovery or refund period is a twelve-month period beginning in June of the following
calendar year. As of December 31, 2016, BGE’s regulatory asset of $38 million included $4 million of costs associated with transmission costs
recoverable through its FERC approved formula rate, $28 million related to under-recovered electric energy costs, $3 million of abandonment costs
to be recovered upon FERC approval, and $3 million related to under-recovered natural gas costs. As of December 31, 2015, BGE’s regulatory
asset of $40 million included $12 million of costs associated with transmission costs recoverable through its FERC approved formula rate
and $28 million related to under-recovered electric energy costs. As of December 31, 2015, BGE’s regulatory liability of $18 million related to
$14 million of over-recovered transmission costs and $5 million of over-recovered natural gas costs, offset by $1 million of abandonment costs to be
recovered upon FERC approval.
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Combined Notes to Consolidated Financial Statements—(Continued)
(Dollars in millions, except per share data unless otherwise noted)
The Pepco energy costs represent the electric supply and transmission related costs recoverable (refundable) from (to) customers under
Pepco’s market-based SOS program and FERC approved transmission rates. Pepco earns or pays interest to customers on under-recovered or
over-recovered FERC transmission formula-related costs. Pepco does not earn or pay interest to customers on under- or over-recovered SOS costs.
The asset is being amortized and recovered over the life of the associated assets. As of December 31, 2016, Pepco’s regulatory asset of $6 million
related to under-recovered electric energy costs. As of December 31, 2016, Pepco’s regulatory liability of $8 million included $5 million of over-
recovered transmission costs and $3 million of over-recovered electric energy costs. As of December 31, 2015, Pepco’s regulatory asset of
$9 million included $5 million of transmission costs recoverable through its FERC approved formula rate and $4 million of recoverable abandonment
costs. As of December 31, 2015, Pepco’s regulatory liability of $16 million included $14 million of over-recovered transmission costs and $2 million of
over-recovered electric energy costs.
The DPL energy costs represent the electric supply, gas supply, and transmission related costs recoverable (refundable) from (to) customers
under DPL’s market-based SOS program, GCR and FERC approved transmission rates. DPL earns or pays interest to customers on under-
recovered or over-recovered FERC transmission formula-related costs. In Delaware, DPL earns interest on under-recovered costs and pays interest
to customers on over-recovered SOS an GCR costs. In Maryland, DPL does not earn or pay interest to customers on under- or over-recovered SOS
costs. The asset is being amortized and recovered over the life of the associated assets. As of December 31, 2016, DPL’s regulatory asset of
$5 million included $1 million of transmission costs recoverable through its FERC approved formula rate and $4 million of under-recovered electric
energy costs. As of December 31, 2016, DPL’s regulatory liability of $5 million included $2 million of over-recovered electric energy costs and
$3 million of over-recovered transmission costs. As of December 31, 2015, DPL’s regulatory asset of $11 million included $7 million of transmission
costs recoverable through its FERC approved formula rate, $3 million of recoverable abandonment costs, and $1 million of under-recovered electric
energy costs. As of December 31, 2015, DPL’s regulatory liability of $19 million included $4 million related to the over-recovered natural gas costs
under the GCR mechanism, $4 million of over-recovered electric energy costs, and $11 million of over-recovered transmission costs.
The ACE energy costs represent the electric supply and transmission related costs recoverable (refundable) from (to) customers under ACE’s
market-based BGS program and FERC approved transmission rates. ACE earns or pays interest to customers on under-recovered or over-
recovered FERC transmission formula-related costs. ACE earns interest on under-recovered and pays interest to customers on over-recovered BGS
costs. As of December 31, 2016, ACE’s regulatory asset of $17 million included $6 million of transmission costs recoverable through its FERC
approved formula rate and $11 million of under-recovered electric energy costs. As of December 31, 2016, ACE’s regulatory liability of $5 million
included $4 million of over-recovered transmission costs and $1 million of over-recovered electric energy costs. As of December 31, 2015, ACE’s
regulatory asset of $13 million included $2 million of transmission costs recoverable through its FERC approved formula rate and $11 million of
under-recovered electric energy costs. As of December 31, 2015, ACE’s regulatory liability of $8 million related to over-recovered transmission
costs.
Deferred storm costs. In the MDPSC’s March 2011 rate order, BGE was authorized to defer $16 million in storm costs incurred in February
2010. BGE earns a return on this regulatory asset and the original recovery period of five years was extended for an additional 25 months, in
accordance with the MDPSC 2014 electric and natural gas distribution rate case order.
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Combined Notes to Consolidated Financial Statements—(Continued)
(Dollars in millions, except per share data unless otherwise noted)
For Pepco, DPL and ACE, amounts represent total incremental storm restoration costs incurred for repair work due to major storm events in
2016, 2015, 2012 and 2011, including the January 2016 winter storm Jonas for Pepco, June 2015 storm (for DPL and ACE), Hurricane Sandy, the
June 2012 derecho, Hurricane Irene and the 2011 severe winter storm (for Pepco), that are recoverable from customers in the Maryland and New
Jersey jurisdictions. Pepco’s and DPL’s costs related to Hurricane Sandy, the June 2012 derecho, Hurricane Irene and Pepco’s costs related to the
2011 severe winter storm are being amortized and recovered from customers, each over a five-year period. However, in the November 2016 Pepco
Maryland Case No. 9418 order, the Commission ruled that the remaining amortization for the Pepco Maryland February 2010 storm, the January
2011 storm and Hurricane Irene be extended for an additional three years. The reason for the extension was that since these assets would be fully
amortized in 2017, Pepco would over-recover these costs if the rates in this case remained in effect beyond July 2017. The January 2017 PULJ
report for DPL Maryland Case No. 9424 also recommended that amortization period for Hurricane Irene (DPL MD) be extended an additional three
years as well. ACE’s costs related to Hurricane Sandy, the June 2012 derecho and Hurricane Irene are being amortized and recovered from
customers, each over a three-year period. PHI does not earn a return on these ACE regulatory assets.
Electric generation-related regulatory asset. As a result of the deregulation of electric generation, BGE ceased to meet the requirements for
accounting for a regulated business for the previous electric generation portion of its business. As a result, BGE wrote-off its entire individual,
generation-related regulatory assets and liabilities and established a single, generation-related regulatory asset to be collected through its regulated
rates, which is being amortized on a basis that approximates the pre-existing individual regulatory asset amortization schedules. The portion of this
regulatory asset that does not earn a regulated rate of return was $9 million as of December 31, 2016, and $19 million as of December 31, 2015.
BGE will continue to amortize this amount through 2017.
Rate stabilization deferral. In June 2006, Senate Bill 1 was enacted in Maryland and imposed a rate stabilization measure that capped rate
increases by BGE for residential electric customers at 15% from July 1, 2006, to May 31, 2007. As a result, BGE recorded a regulatory asset on its
Consolidated Balance Sheets equal to the difference between the costs to purchase power and the revenues collected from customers, as well as
related carrying charges based on short-term interest rates from July 1, 2006 to May 31, 2007. In addition, as required by Senate Bill 1, the MDPSC
approved a plan that allowed residential electric customers the option to further defer the transition to market rates from June 1, 2007 to January 1,
2008. During 2007, BGE deferred $306 million of electricity purchased for resale expenses and certain applicable carrying charges, which are
calculated using the implied interest rates of the rate stabilization bonds, as a regulatory asset related to the rate stabilization plans. During 2016 and
2015, BGE recovered $81 million and $73 million, respectively, of electricity purchased for resale expenses and carrying charges related to the rate
stabilization plan regulatory asset. BGE began amortizing the regulatory asset associated with the deferral which ended in May 2007 to earnings
over a period not to exceed ten years when collection from customers began in June 2007.
Energy efficiency and demand response programs. For ComEd, these amounts represent over recoveries related to ComEd’s
ICC-approved Energy Efficiency and Demand Response Plan. ComEd expects to refund these over recoveries in 2017. ComEd earns a return on
the capital investment incurred under the program, but does not earn or pay a return or interest on under or over recoveries, respectively. For PECO,
these amounts represent over recoveries of program costs related to both Phase II and Phase III of its PAPUC-approved EE&C Plan. PECO began
recovering the costs of its Phase II and Phase III EE&C Plans through a surcharge in June 2013 and June 2016, respectively,
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Combined Notes to Consolidated Financial Statements—(Continued)
(Dollars in millions, except per share data unless otherwise noted)
based on projected spending under the programs. Phase II of the program began on June 1, 2013 and expired on May 31, 2016. Phase III of the
program began on June 1, 2016 and will expire on May 31, 2021. PECO does not earn (pay) interest on under (over) collections. For BGE, these
amounts represent under (over) recoveries related to BGE’s Smart Energy Savers Program ® , which includes both MDPSC-approved demand
response and energy efficiency programs. For the BGE Peak Rewards SM demand response program which began in January 2008, actual
marketing and customer bonus costs incurred in the demand response program are being recovered over a 5-year amortization period from the date
incurred pursuant to an order by the MDPSC. Fixed assets related to the demand response program are recovered over the life of the equipment.
Also included in the demand response program are customer bill credits related to BGE’s Smart Energy Rewards program which began in July 2013
and are being recovered through the surcharge. Actual costs incurred in the energy efficiency program are being amortized over a 5-year period with
recovery beginning in 2010 pursuant to an order by the MDPSC. BGE earns a rate of return on the capital investments and deferred costs incurred
under the program and earns (pays) interest on under (over) collections.
For Pepco, DPL and ACE, amounts represent recoverable costs associated with customer direct load control and energy efficiency and
conservation programs in all jurisdictions that are being recovered from customers. These programs are designed to reduce customers’ energy
consumption. PHI earns a return on these regulatory assets.
Merger integration costs. These amounts include integration costs to achieve distribution synergies related to the Constellation merger
transaction. As a result of the MDPSC’s February 2013 rate order, BGE deferred $8 million related to non-severance merger integration costs
incurred during 2012 and the first quarter of 2013. Of these costs, $4 million was authorized to be amortized over a 5-year period that began in
March 2013. The recovery of the remaining $4 million was deferred. In the MDPSC’s December 2013 rate order, BGE was authorized to recover the
remaining $4 million and an additional $4 million of non-severance merger integration costs incurred during 2013. These costs are being amortized
over a 5-year period that began in December 2013. BGE is earning a return on this regulatory asset included in base rates.
These amounts also include integration costs to achieve distribution synergies related to the PHI acquisition. As of December 31, 2016, BGE’s
regulatory asset of $10 million included $6 million of previously incurred PHI acquisition costs as authorized by the June 2016 rate case order. As of
December 31, 2016, PHI’s regulatory asset of $15 million represents previously incurred PHI acquisition costs expected to earn a return and be
recovered in distribution rates in the Maryland service territories of Pepco and DPL.
Under (Over)-recovered electric and gas revenue decoupling. For BGE, these amounts represent the electric and gas distribution costs
recoverable from or (refundable) to customers under BGE’s decoupling mechanisms, which does not earn a rate of return and is being recovered
over the life of the associated assets. As of December 31, 2016, BGE had a regulatory asset of $2 million related to under-recovered natural gas
revenue decoupling and $1 million related to under-recovered electric revenue decoupling. As of December 31, 2015, BGE had a regulatory asset of
$30 million related to under-recovered electric revenue decoupling and a regulatory liability of $1 million related to over-recovered natural gas
revenue decoupling.
For Pepco and DPL, these amounts represents the electric distribution costs recoverable from customers under Pepco’s Maryland and District
of Columbia decoupling mechanisms and DPL’s Maryland decoupling mechanism. Pepco and DPL earn a return on these regulatory assets.
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Combined Notes to Consolidated Financial Statements—(Continued)
(Dollars in millions, except per share data unless otherwise noted)
COPCO acquisition adjustment. On July 19, 2007, the MDPSC issued an order which provided for the recovery of a portion of DPL’s
goodwill. As a result of this order, $41 million in DPL goodwill was transferred to a regulatory asset. This item is being amortized from August 2007
through August 2018. DPL earns a return of 12.95% on these regulatory assets.
Recoverable workers compensation and long-term disability costs. These amounts represent accrued workers’ compensation and long-
term disability costs for Pepco, which are recoverable from customers when actual claims are paid to employees. Pepco is not earning a return on
the recovery of these costs and the recovery period is over the life of the associated assets.
Vacation accrual. These amounts represent accrued vacation costs for PECO, DPL and ACE. PECO, DPL and ACE do not earn a return on
these regulatory assets and the costs are recoverable from customers when actual payments are made to employees or when vacation is taken.
Securitized stranded costs. These amounts represent certain contract termination payments under a contract between ACE and an
unaffiliated non-utility generator and costs associated with the regulated operations of ACE’s electricity generation business that are no longer
recoverable through customer rates (collectively referred to as “stranded costs”). The stranded costs are amortized over the life of Transition Bonds
issued by Atlantic City Electric Transition Funding LLC (ACE Funding) to securitize the recoverability of these stranded costs. These bonds mature
between 2017 and 2023. A customer surcharge is collected by ACE to fund principal and interest payments on the Transition Bonds. PHI earns a
return on these regulatory assets.
CAP arrearage. These amounts represent the guaranteed recovery of PECO’s previously incurred bad debt expense associated with the
eligible CAP accounts receivable balances under the IPAF Program as provided by the 2015 electric distribution rate case settlement. These costs
are amortized as recovery is received through a combination of customer payments over the duration of the five-year payment agreement term and
rate recovery, including through future rate cases if necessary. PECO is not earning a return on this regulatory asset.
Nuclear decommissioning. These amounts represent estimated future nuclear decommissioning costs for the Regulatory Agreement Units
that exceed (regulatory asset) or are less than (regulatory liability) the associated decommissioning trust fund assets. Exelon believes the trust fund
assets, including prospective earnings thereon and any future collections from customers, will be sufficient to fund the associated future
decommissioning costs at the time of decommissioning. Exelon is not accruing interest on these costs. See Note 16—Asset Retirement Obligations
for additional information.
Removal costs. These amounts represent funds ComEd, BGE, PHI, Pepco, DPL and ACE have received from customers through
depreciation rates to cover the future non-legally required cost of removal of property, plant and equipment which reduces rate base for ratemaking
purposes. This liability is reduced as costs are incurred. PHI, Pepco, DPL, and ACE have a regulatory asset which represents removal costs
incurred in excess of amounts received from customers through depreciation rates recoverable from ratepayers. Pepco, DPL and ACE do not earn a
return on these regulatory assets and the recovery period is over the life of the associated assets.
Deferred rent. Represents the regulatory liability recorded at Exelon and PHI for deferred rent related to a lease. The costs of the lease are
recoverable through the ratemaking process at 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)
DLC program costs. The DLC program costs include equipment, installation, and information technology costs necessary to implement the
DLC Program under PECO’s EE&C Phase I Plans. PECO received full cost recovery through Phase I collections and will amortize the costs as a
credit to the income statement to offset the related depreciation expense during the same period through September 2025, which is the remaining
useful life of the assets. PECO is not paying interest on these over-recovered costs.
Electric distribution tax repairs. PECO’s 2010 electric distribution rate case settlement required that the expected cash benefit from the
application of Revenue Procedure 2011-43, which was issued on August 19, 2011, to prior tax years be refunded to customers over a seven-year
period. Credits began being reflected in customer bills on January 1, 2012. PECO’s 2015 electric distribution rate case settlement requires PECO to
pay interest on the unamortized balance of the tax-effected catch-up deduction beginning January 1, 2016.
Gas distribution tax repairs. PECO’s 2010 natural gas distribution rate case settlement required that the expected cash benefit from the
application of new tax repairs deduction methodologies for 2010 and prior tax years be refunded to customers over a seven-year period. In
September 2012, PECO filed an application with the IRS to change its method of accounting for gas distribution repairs for the 2011 tax year. Credits
began being reflected in customer bills on January 1, 2013. No interest will be paid to customers.
Capitalized Ratemaking Amounts Not Recognized (Exelon, ComEd, PECO, BGE, PHI, Pepco, DPL and ACE)
The following table illustrates our authorized amounts capitalized for ratemaking purposes related to earnings on shareholders’ investment that
are not recognized for financial reporting purposes on our Consolidated Balance Sheets. These amounts will be recognized as revenues in our
Consolidated Statements of Operations and Comprehensive Income in the periods they are billable to our customers.
December 31, 2016
December 31, 2015
Exelon
72
$
ComEd
(a)
$
5
PECO
$ —
BGE
(b)
Successor
PHI
Pepco
(b)
DPL
(b)
$ 57
$
10
$
6
$ 4
ACE
$ —
Exelon
55
$
ComEd
(a)
$
6
PECO
$ —
BGE
(b)
PHI
Pepco
(b)
DPL
(b)
$ 49
$
4
$
1
$ 3
ACE
$ —
Predecessor
(a) Reflects ComEd’s unrecognized equity returns earned for ratemaking purposes on its under-recovered distribution services costs regulatory assets.
(b) BGE’s, Pepco’s and DPL’s authorized amounts capitalized for ratemaking purposes related to earnings on shareholders’ investment on their respective AMI Programs.
Purchase of Receivables Programs (Exelon, ComEd, PECO, BGE, PHI, Pepco, DPL and ACE)
ComEd, PECO, BGE, Pepco, DPL and ACE are required, under separate legislation and regulations in Illinois, Pennsylvania, Maryland,
District of Columbia and New Jersey, to purchase certain receivables from retail electric and natural gas suppliers that participate in the utilities’
consolidated billing. ComEd, BGE, Pepco and DPL purchase receivables at a discount primarily to recover uncollectible accounts expense from the
suppliers. PECO is required to purchase receivables
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Combined Notes to Consolidated Financial Statements—(Continued)
(Dollars in millions, except per share data unless otherwise noted)
at face value and is permitted to recover uncollectible accounts expense, including those from Third Party Suppliers, from customers through
distribution rates. ACE purchases receivables at face value. ACE recovers all uncollectible accounts expense, including those from Third Party
Suppliers, through the Societal Benefits Charge (SBC) rider, which includes uncollectible accounts expense as a component. The SBC is filed
annually with the NJBPU. Exelon, ComEd, PECO, BGE, PHI, Pepco, DPL and ACE do not record unbilled commodity receivables under the POR
programs. Purchased billed receivables are classified in Other accounts receivable, net on Exelon’s, ComEd’s, PECO’s, BGE’s, PHI’s, Pepco’s,
DPL’s and ACE’s Consolidated Balance Sheets. The following tables provide information about the purchased receivables of those companies as of
December 31, 2016 and December 31, 2015.
As of December 31, 2016
Purchased receivables (c)
Allowance for uncollectible accounts (a)
Purchased receivables, net
Exelon
$ 313
(37)
$ 276
ComEd
87
$
(14)
73
$
PECO
$ 72
(6)
$ 66
BGE
$ 59
(4)
$ 55
As of December 31, 2015
Purchased receivables (b)(c)
Allowance for uncollectible accounts (a)
Purchased receivables, net
Exelon
$ 229
(31)
$ 198
ComEd
$ 103
(16)
87
$
PECO
$ 67
(7)
$ 60
BGE
$ 59
(8)
$ 51
Successor
PHI
$
$
95
(13)
82
Predecessor
PHI
$
$
100
(6)
94
Pepco
$ 63
(7)
$ 56
DPL
$ 10
(2)
8
$
ACE
$ 22
(4)
$ 18
Pepco
$ 70
(4)
$ 66
DPL
$ 11
—
$ 11
ACE
$ 19
(2)
$ 17
(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 its Purchase of Receivables with Consolidated Billing tariff.
(b) PECO’s natural gas POR program became effective on January 1, 2012 and included a 1% discount on purchased receivables in order to recover the implementation
costs of the program. The implementation costs were fully recovered and the 1% discount was reset to 0%, effective July 2015.
(c) Pepco’s electric POR program in Maryland included a discount on purchased receivables ranging from 0% to 2% depending on customer class, and Pepco’s electric POR
program in the District of Columbia included a discount on purchased receivables ranging from 0% to 6% depending on customer class. DPL’s electric POR program in
Maryland included a discount on purchased receivables ranging from 0% to 1% depending on customer class.
4. Mergers, Acquisitions, and Dispositions (Exelon, Generation, PHI, DPL and Pepco)
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). 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). Following the
completion of the PHI Merger, Exelon and PHI completed a series of internal corporate organization restructuring transactions resulting in the
transfer of PHI’s unregulated business interests to Exelon and Generation and the transfer of PHI, Pepco, DPL and ACE to a special purpose
subsidiary of EEDC.
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Regulatory Matters
Combined Notes to Consolidated Financial Statements—(Continued)
(Dollars in millions, except per share data unless otherwise noted)
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
speaking, requires allocation of merger benefits proportionally across all the jurisdictions.
During the third and fourth quarters of 2016, Exelon and PHI filed proposals in Delaware, New Jersey and Maryland for amounts and
allocations reflecting the application of the most favored nation provision, resulting in a total nominal cost of commitments of $513 million excluding
renewable generation commitments (approximately $444 million on a net present value basis, excluding renewable generation commitments and
charitable contributions). These filings, which reflect agreements reached with certain parties to the merger proceedings in the jurisdictions, were
subject to regulatory review and approval in each jurisdiction. The DPSC and NJBPU approved the amounts and allocations during the third and
fourth quarters of 2016. An order from the MDPSC is expected in the first quarter of 2017. No changes in commitment cost levels are required in the
District of Columbia.
During the fourth quarter of 2016, the MDPSC approved a change in the application of $9 million in funding for energy-efficiency program
support in the DPL MD service territory. This resulted in an adjustment to the merger commitment costs recorded at Exelon Corporate and DPL.
Exelon Corporate recorded a decrease and DPL recorded an increase of $9 million in Operating and maintenance expense.
The following amounts were recognized as total commitment costs in Operating and maintenance expense in Exelon’s, PHI’s, Pepco’s, DPL’s
and ACE’s Consolidated Statements of Operations and Comprehensive Income for the year ended December 31, 2016 and PHI’s successor period:
Description
Rate credits
Energy efficiency
Charitable contributions
Delivery system modernization
Green sustainability fund
Workforce development
Other
Total
Expected
Payment
Period
2016 - 2017
2016 - 2021
2016 - 2026
Q2 2016
Q2 2016
2016 - 2020
Pepco
(a)
$ 91
—
28
—
—
—
7
$ 126
DPL
(a)
$ 67
—
12
—
—
—
7
$ 86
ACE
(a)
$101
—
10
—
—
—
—
$111
Successor
PHI (a)
$
$
259
—
50
—
—
—
14
323
Exelon
(a)
$ 259
111
50
22
14
24
33
$ 513
(a)
Included within the individual line items is the most favored nation provision estimate of $6 million, $5 million $38 million, $49 million and $134 million at Pepco, DPL, ACE,
PHI and Exelon, respectively.
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.
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Combined Notes to Consolidated Financial Statements—(Continued)
(Dollars in millions, except per share data unless otherwise noted)
In addition, Exelon is committed to develop or to assist in the commercial development of 37 MWs of new generation in Maryland, District of
Columbia, and Delaware, 27 MWs of which are to be completed by 2018. These investments are expected to total approximately $137 million, are
expected to be primarily capital in nature, and will generate future earnings at Exelon and Generation. Investment costs will be recognized as
incurred and recorded on Exelon’s and Generation’s financial statements. Exelon has also committed to purchase 100 MWs of wind energy in PJM,
to procure 120 MWs of wind RECs for the purpose of meeting Delaware’s renewable portfolio standards, and to maintain and promote energy
efficiency and demand response programs in the PHI jurisdictions.
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.
Exelon was previously named in suits filed in the Delaware Chancery Court alleging that individual directors of PHI breached their fiduciary
duties by entering into the merger transaction and that Exelon aided and abetted the individual directors’ breaches. The suits sought rescission of
the merger and unspecified damages and costs. On June 1, 2016, the parties executed a settlement to resolve all claims, subject to the approval of
the Delaware Court. A hearing had been scheduled for September 8, 2016 in the Delaware Court to consider whether to approve the
settlement. However, on August 19, 2016, the plaintiffs advised Exelon that they had determined to dismiss the case in its entirety and with
prejudice. On August 24, 2016, the Delaware Court issued an order approving the dismissal.
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 and in July and August, Exelon, PHI, the MDPSC, Prince George’s County and Montgomery County filed
responses opposing the motions to stay. The 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,
2016, the Sierra Club and CCAN filed a notice of appeal. On January 27, 2017, the Maryland Court of Special Appeals affirmed the Circuit Court’s
judgment. The OPC and Sierra Club have until the later of (i) 30 days from the date of the Court’s order or (ii) 15 days from the date the Court enters
its mandate, to file their petition for further review in the Court of Appeals. Exelon cannot predict if the petition will be filed.
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 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 September 9, 2016, the Court consolidated the appeals. The Court has issued a scheduling order, and a
decision is expected in the second or third quarter of 2017. Exelon believes the matters are without merit.
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Combined Notes to Consolidated Financial Statements—(Continued)
(Dollars in millions, except per share data unless otherwise noted)
Accounting for the Merger Transaction
The total purchase price consideration of approximately $7.1 billion for the PHI Merger consisted of cash paid to PHI shareholders, cash paid
for PHI preferred securities and cash paid for PHI stock-based compensation equity awards as follows:
(In millions of dollars, except per share data)
Cash paid to PHI shareholders at $27.25 per share (254 million shares outstanding at March 23, 2016)
Cash paid for PHI preferred stock (a)
Cash paid for PHI stock-based compensation equity awards (b)
Total purchase price
Total
Consideration
6,933
$
180
29
7,142
$
(a) As of December 31, 2015, the preferred stock was included in Other non-current assets on Exelon’s Consolidated Balance Sheets.
(b) 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.
PHI shareholders received $27.25 of cash in exchange for each share of PHI common stock outstanding as of the effective date of the merger.
In connection with the Merger Agreement, Exelon entered into a Subscription Agreement under which it purchased $180 million of a new class of
nonvoting, nonconvertible and nontransferable preferred securities of PHI prior to December 31, 2015. On March 23, 2016, the preferred securities
were cancelled for no consideration to Exelon, and accordingly, the $180 million cash consideration previously paid to acquire the preferred
securities was treated as purchase price consideration.
The valuations performed in the first quarter of 2016 to assess the fair value of certain assets acquired and liabilities assumed were considered
preliminary as a result of the short time period between the closing of the merger and the end of the first quarter of 2016. Accounting guidance
provides that the allocation of the purchase price may be modified up to one year from the date of the merger as more information is obtained about
the fair value of assets acquired and liabilities assumed. Exelon expects to finalize these amounts in the first quarter of 2017. During the second,
third and fourth quarters of 2016, certain modifications were made to preliminary valuation amounts for acquired property, plant and equipment,
unamortized energy contracts, current liabilities, long-term debt, deferred income taxes and pension and OPEB liabilities resulting in an $11 million
net decrease to goodwill. The preliminary amounts recognized are subject to further revision to the extent that additional information is obtained
about the facts and circumstances that existed as of the acquisition date. Any changes to the fair value assessments may affect the purchase price
allocation and could potentially impact goodwill.
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Combined Notes to Consolidated Financial Statements—(Continued)
(Dollars in millions, except per share data unless otherwise noted)
Exelon applied push-down accounting to PHI, and accordingly, the PHI assets acquired and liabilities assumed were recorded at their
estimated fair values on Exelon’s and PHI’s Consolidated Balance Sheets as of March 23, 2016, as follows:
Preliminary Purchase Price Allocation
Current assets
Property, plant and equipment
Regulatory assets
Other assets
Goodwill
Total assets
Current liabilities
Unamortized energy contracts
Regulatory liabilities
Long-term debt, including current maturities
Deferred income taxes
Pension and OPEB liabilities
Other liabilities
Total liabilities
Total purchase price
$ 1,441
11,088
5,015
248
4,005
$21,797
$ 2,752
1,515
297
5,636
3,447
821
187
$14,655
$ 7,142
On its successor financial statements, PHI has recorded, beginning March 24, 2016, Membership interest equity of $7.2 billion, which is
greater than the total $7.1 billion purchase price, reflecting the impact of a $59 million deferred tax liability recorded only at Exelon Corporate to
reflect unitary state income tax consequences of the merger.
The excess of the purchase price over the estimated fair value of the assets acquired and the liabilities assumed totaled $4.0 billion, which was
recognized as goodwill by PHI and Exelon at the acquisition 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. For purposes of
future required impairment assessments, the goodwill has been preliminarily assigned to PHI’s reportable units Pepco, DPL and ACE in the amounts
of $1.7 billion, $1.1 billion and $1.2 billion, respectively. None of this goodwill is tax deductible.
Immediately following closing of the merger, $235 million of net assets included in the table above associated with PHI’s unregulated business
interests were distributed by PHI to Exelon. Exelon contributed $163 million of such net assets to Generation.
The fair values of PHI’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, future market prices and
impacts of utility rate regulation. There were also judgments made to determine the expected useful lives assigned to each class of assets acquired.
Through its wholly-owned rate regulated utility subsidiaries, most of PHI’s assets and liabilities are subject to cost-of-service rate
regulation. Under such regulation, rates charged to customers are established by a regulator to provide for recovery of costs and a fair return on
invested capital, or rate
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Combined Notes to Consolidated Financial Statements—(Continued)
(Dollars in millions, except per share data unless otherwise noted)
base, generally measured at historical cost. In applying the acquisition method of accounting, for regulated assets and liabilities included in rate base
or otherwise earning a return (primarily property, plant and equipment and regulatory assets earning a return), no fair value adjustments were
recorded as historical cost is viewed as a reasonable proxy for fair value.
Fair value adjustments were applied to the historical cost bases of other assets and liabilities subject to rate regulation but not earning a return
(including debt instruments and pension and OPEB obligations). In these instances, a corresponding offsetting regulatory asset or liability was also
established, as the underlying utility asset and liability amounts are recoverable from or refundable to customers at historical cost (and not at fair
value) through the rate setting process. Similar treatment was applied for fair value adjustments to record intangible assets and liabilities, such as for
electricity and gas energy supply contracts as further described below. Regulatory assets and liabilities established to offset fair value adjustments
are amortized in amounts and over time frames consistent with the realization or settlement of the fair value adjustments, with no impact on reported
net income. See Note 3—Regulatory Matters for additional information regarding the fair value of regulatory assets and liabilities established by
Exelon and PHI.
Fair value adjustments were recorded at Exelon and PHI for the difference between the contract price and the market price of electricity and
gas energy supply contracts of PHI’s wholly-owned rate regulated utility subsidiaries. These adjustments are intangible assets and liabilities
classified as unamortized energy contracts on Exelon’s and PHI’s Consolidated Balance Sheets as of December 31, 2016. The difference between
the contract price and the market price at the acquisition date of the Merger was recognized for each contract as either an intangible asset or
liability. In total, Exelon and PHI recorded a net $1.5 billion liability reflecting out-of-the-money contracts. The valuation of the acquired intangible
assets and liabilities 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. In certain instances, the valuations were based upon certain unobservable inputs, which are considered Level 3
inputs, pursuant to applicable accounting guidance. Key estimates and inputs include forecasted power prices and the discount rate. The
unamortized energy contract fair value adjustment amounts and the corresponding offsetting regulatory asset and liability amounts are amortized
through Purchase power and fuel expense or Operating revenues, as applicable, over the life of the applicable contract in relation to the present
value of the underlying cash flows as of the merger date.
As mentioned, under cost-of-service rate regulation, 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.
The current impact of PHI, including its unregulated businesses, on Exelon’s Consolidated Statements of Operations and Comprehensive
Income includes Operating revenues of $3,785 million and Net loss of $(66) million during the year ended December 31, 2016.
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Combined Notes to Consolidated Financial Statements—(Continued)
(Dollars in millions, except per share data unless otherwise noted)
For the periods ended December 31, 2016 and 2015, Exelon and PHI have recognized expense to achieve the PHI acquisition as follows:
Acquisition, Integration and Financing Costs (a)
Exelon (b)
Generation
ComEd (c)
PECO
BGE (c)
Pepco (c)
DPL (c)
ACE
Acquisition, Integration and Financing Costs (a)
PHI (c)
For the Year Ended December 31,
2016
143
$
37
(6)
5
(1)
28
20
19
2015
87
$
24
9
4
5
3
2
1
Successor
March 24,
2016 to
December 31,
2016
Predecessor
January 1,
2016 to
March 23,
2016
For the Year
Ended
December 31,
2015
$
69
$
29
$
19
(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.
(b) Reflects costs (benefits) recorded at Exelon related to financing, including mark-to-market activity on forward-starting interest rate swaps.
(c) For the year ended December 31, 2016, includes the reversal of previously incurred acquisition, integration and financing costs of $8 million, $6 million, $11 million,
$4 million, and $16 million incurred at ComEd, BGE, Pepco, DPL and PHI, respectively, that have been deferred and recorded as a regulatory asset for anticipated
recovery. See Note 3—Regulatory Matters for more information.
Pro-forma Impact of the Merger
The following unaudited pro forma financial information reflects the consolidated results of operations of Exelon as if the merger with PHI 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 the future consolidated results of operations
of the combined company.
Total operating revenues
Net income attributable to common shareholders
Basic earnings per share
Diluted earnings per share
Year Ended
December 31,
2016 (a)
$32,342
1,562
1.69
$
1.69
2015 (b)
$33,823
2,618
2.85
$
2.84
(a) The amounts above exclude non-recurring costs directly related to the merger of $680 million and intercompany revenue of $171 million for year ended December 31,
2016.
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Combined Notes to Consolidated Financial Statements—(Continued)
(Dollars in millions, except per share data unless otherwise noted)
(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.
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. As of
December 31, 2016, Generation had remitted $235 million to ConEdison Solutions and the remaining balance of $22 million, which is included in
Other current liabilities on Exelon’s and Generation’s Consolidated Balance Sheets, will be paid during the first quarter of 2017.
The following table summarizes the acquisition-date fair value of the consideration transferred and the assets and liabilities assumed for the
ConEdison Solutions acquisition by Generation as of September 1, 2016:
Total consideration transferred
Identifiable assets acquired and liabilities assumed
Working capital assets
Property, plant and equipment
Mark-to-market derivative assets
Unamortized energy contract assets
Customer relationships
Other assets
Total assets
Mark-to-market derivative liabilities
Total liabilities
Total net identifiable assets, at fair value
$257
$204
2
6
100
9
1
$322
$ (65)
$ (65)
$257
The purchase price 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 December 31, 2016. The purchase accounting is preliminary, and, although not expected, may be further
adjusted from what is shown above. Accounting guidance provides that the allocation of the purchase price may be modified up to one year from the
date of the acquisition as more information is obtained about the fair value of assets acquired and liabilities assumed; however, Generation expects
to finalize these amounts by the first quarter of 2017.
The fair values of ConEdison Solutions’ 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.
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Combined Notes to Consolidated Financial Statements—(Continued)
(Dollars in millions, except per share data unless otherwise noted)
Proposed Acquisition of James A. FitzPatrick Nuclear Generating Station (Exelon and Generation)
On August 8, 2016, Generation executed a series of agreements with Entergy Nuclear FitzPatrick LLC (Entergy) to acquire the 838 MW single-
unit James A. FitzPatrick (FitzPatrick) nuclear generating station located in Scriba, New York for a cash purchase price of $110 million. As part of the
transaction, Generation would receive the FitzPatrick NDT fund assets and assume the obligation to decommission FitzPatrick. The NRC license for
FitzPatrick expires in 2034. In November 2015, Entergy had announced plans to early retire FitzPatrick at the end of the current fuel cycle in January
2017. Under the terms of the agreements, Generation will reimburse Entergy for approximately $200 million to $250 million of incremental costs to
prepare for and conduct the plant refueling outage as well as to operate and maintain the plant after the refueling outage, scheduled to end in
February 2017, through the closing date. These are costs which otherwise would have been avoided by FitzPatrick’s planned permanent shutdown
in January 2017. Generation will be entitled to all revenues from FitzPatrick’s electricity and capacity sales for the period commencing upon
completion of the refueling outage through the acquisition closing date. The agreements provide for certain termination rights, including the right of
either party to terminate if the transaction has not been consummated within 12 months due to failure to obtain the required regulatory approvals.
Closing of the transaction is currently anticipated to occur in the first half of 2017 and requires regulatory approval by FERC, NRC, and the
New York Public Service Commission (NYPSC). The transaction is also subject to the notification and reporting requirements of the HSR Act (which
had been completed) and other customary closing conditions. On November 17, 2016 the NYPSC issued an order approving the transaction. On
October 11, 2016, Public Citizen, Inc. filed a protest with FERC challenging Generation and Entergy’s application to FERC for the transfer of
ownership of FitzPatrick. No other party to the FERC proceeding filed any protests or comments. On December 7, 2016 FERC approved
Generation’s acquisition of the FitzPatrick facility and dismissed the Public Citizen protest. Public Citizen filed a request for rehearing on January 6,
2017. NRC is the final regulatory approval required to close the transaction and is anticipated during the first half of 2017.
The transaction is expected to be accounted for as a business combination. For accounting and financial reporting purposes, the costs for
which Generation reimburses Entergy as well as the revenue received from FitzPatrick prior to the closing of the transaction will be treated as part of
the purchase price consideration. Generation will record the fair value of the assets acquired and liabilities assumed as of the acquisition date. To
the extent the purchase price is greater than the fair value of the net assets acquired, goodwill will be recorded. To the extent the fair value of the net
assets acquired is greater than the purchase price, a bargain purchase gain will be recorded.
As of December 31, 2016, Generation has recorded $127 million of purchase price consideration in Other noncurrent assets on Exelon’s and
Generation’s Consolidated Balance Sheets. The cash outflows associated with these amounts are reflected within Acquisition of businesses on
Exelon’s and Generation’s Consolidated Statements of Cash Flows. In the event the acquisition does not close, these amounts would be subject to
potential write-off to Operating and maintenance expense in Exelon’s and Generation’s Consolidated Statements of Operations and Comprehensive
Income. For the year ended December 31, 2016, Exelon and Generation incurred $19 million of merger and integration related costs which are
included within Operating and maintenance 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)
Acquisition of Integrys Energy Services, Inc. (Exelon and Generation)
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. (IES) for a purchase price of $332 million
including net working capital. Generation has elected to account for the transaction as an asset acquisition for federal income tax purposes. The
generation and solar asset businesses of Integrys are excluded from the transaction. The Purchase Agreement also includes various
representations, warranties, covenants, indemnification and other provisions customary for a transaction of this nature.
Consistent with the applicable accounting guidance, the fair value of the assets acquired and liabilities assumed was determined as of the
acquisition date through the use of significant estimates and assumptions that are judgmental in nature. Some of the more significant estimates and
assumptions used include: projected future cash flows (including the amount and timing); discount rates reflecting the risk inherent in the future cash
flows; and future power and fuel market prices.
The following table summarizes the acquisition-date fair value of the consideration transferred and the assets and liabilities assumed for the
Integrys acquisition by Generation:
Total consideration transferred
Identifiable assets acquired and liabilities assumed
Working capital assets
Mark-to-market derivative assets
Unamortized energy contract assets
Customer relationships
Working capital liabilities
Mark-to-market derivative liabilities
Unamortized energy contract liabilities
Deferred tax liability
Total net identifiable assets, at fair value
Bargain purchase gain (after-tax)
$ 332
$ 390
184
115
50
(196)
(57)
(110)
(16)
$ 360
$ 28
The after-tax bargain purchase gain of $28 million is primarily the result of IES executing additional contract volumes between the date the
acquisition agreement was signed and the closing of the transaction resulting in an increase in the fair value of the net assets acquired as of the
acquisition date. The after-tax gain is included within Gain on consolidation and acquisition of businesses in Exelon’s and Generation’s Consolidated
Statements of Operations and Comprehensive Income.
IES’s operating revenues and net loss included in Exelon’s and Generation’s Consolidated Statements of Operations and Comprehensive
Income for the period from November 1, 2014 to December 31, 2014 were $386 million and $(42) million, respectively. The net loss for the period
from November 1, 2014 to December 31, 2014 includes pre-tax unrealized losses on derivative contracts of $108 million and the bargain purchase
gain of $28 million. It is impracticable to determine the overall financial statement impact of IES for 2015 and 2016 due to the integration of the
business into ongoing operations. For the years ended December 31, 2015, and 2014, Exelon and Generation incurred $5 million and $7 million,
respectively, of merger and integration related costs which are included within Operating and maintenance 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)
Asset Divestitures (Exelon, Generation, PHI, Pepco and DPL)
On November 10, 2015, Pepco completed the sale of a 3.5 acre parcel of unimproved land (held as non-utility property) in the Buzzard Point
area of southeast Washington, D.C., resulting in a pre-tax gain of $37 million.
On December 31, 2015, Pepco completed the sale of a 3.8 acre parcel of unimproved land (held as non-utility property) in the NoMa area of
northeast Washington, D.C., resulting in a pre-tax gain of $9 million. The purchase and sale agreement also provided the third party with a 90-day
option to purchase the remaining 1.8 acre land parcel.
On April 21, 2016, Generation completed the sale of the retired New Boston generating site, located in Boston, Massachusetts, resulting in a
pre-tax gain of approximately $32 million.
On May 2, 2016, Pepco completed the sale of the remaining 1.8 acre land parcel noted above, located in the NoMa area of northeast
Washington, D.C., resulting in a pre-tax gain of approximately $8 million at Pepco. Due to the fair value adjustments recorded at Exelon and PHI as
part of purchase accounting, no gain was recorded in Exelon’s and PHI’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 14—Debt and Credit Agreements for more 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 on Exelon’s
and Generation’s Consolidated Statements of Operations and Comprehensive Income for the year ended December 31, 2016.
In July 2016, DPL completed the sale of a 9 acre land parcel located on South Madison Street in Wilmington, DE, resulting in a pre-tax gain of
approximately $4 million. In December 2016, DPL completed the sale of a 48 acre land parcel located in Middletown, DE, resulting in a pre-tax gain
of approximately $5 million. Due to the fair value adjustments recorded at Exelon and PHI as part of purchase accounting, no gain was recorded in
Exelon’s and PHI’s Consolidated Statements of Operations and Comprehensive Income.
During the fourth quarter, as part of its continual assessment of growth and development opportunities, Generation has 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 sale
of assets and pre-tax impairment charges of $23 million were recorded within Operating and maintenance expense in Exelon’s and Generation’s
Consolidated Statements of Operations and Comprehensive Income.
5. Investment in Constellation Energy Nuclear Group, LLC (Exelon and Generation)
Generation owns a 50.01% interest in CENG, a nuclear generation business. Generation has historically had various agreements with CENG
to purchase power and to provide certain services. For further information regarding these agreements, see Note 27—Related Party Transactions.
On April 1, 2014, Generation and subsidiaries of Generation and CENG entered into a Nuclear Operating Services Agreement (NOSA)
pursuant to which Generation will operate the CENG nuclear
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Combined Notes to Consolidated Financial Statements—(Continued)
(Dollars in millions, except per share data unless otherwise noted)
generation fleet owned by CENG subsidiaries and provide corporate and administrative services for the remaining life of the CENG nuclear plants as
if they were a part of the Generation nuclear fleet, subject to EDF’s rights as a member of CENG (the Integration Transaction). CENG will reimburse
Generation for its direct and allocated costs for such services. As part of the arrangement, Nine Mile Point Nuclear Station, LLC, a subsidiary of
CENG, also assigned to Generation its obligations as Operator of Nine Mile Point Unit 2 under an operating agreement with Long Island Power
Authority, the Unit 2 co-owner. In addition, on April 1, 2014, the Power Services Agency Agreement (PSAA) was amended and extended until the
permanent cessation of power generation by the CENG generation plants.
In addition, on April 1, 2014, Generation made a $400 million loan to CENG, bearing interest at 5.25% per annum and payable out of specified
available cash flows of CENG or payable upon the maturity date of April 1, 2034. Immediately following receipt of the proceeds of such loan, CENG
made a $400 million special distribution to EDF. Unpaid principal and accrued interest on the loan was $316 million as of December 31, 2016.
Exelon, Generation, and subsidiaries of Generation, EDF and CENG also executed a Fourth Amended and Restated Operating Agreement for
CENG on April 1, 2014, pursuant to which, among other things, CENG committed to make preferred distributions to Generation (after repayment of
the $400 million loan and associated interest) quarterly out of specified available cash flows until Generation has received aggregate distributions of
$400 million plus a return of 8.5% per annum from April 1, 2014 (Preferred Distribution Rights).
Generation and EDF also 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. 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. As of the date these
financial statements were issued, EDF has not given notice to Generation that it is exercising its option.
On April 1, 2014, Generation also executed an Indemnity Agreement pursuant to which Generation indemnified 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.
In addition, on April 1, 2014, Generation, EDF, CENG and Nine Mile Point Nuclear Station, LLC entered into an Employee Matters Agreement
(EMA) that provides for the transfer of CENG employees to Exelon or one of its affiliates and Exelon’s assumption of the sponsorship of the
employee benefit plans (including certain incentive, health and welfare, and postemployment benefit plans, among others) and their related trusts by
Exelon as the plan sponsor as of July 14, 2014. The EMA also generally requires CENG to fund the obligation related to pre-transfer service of
employees, including the underfunded balance of the pension and other postretirement welfare benefit plans measured as of July 14, 2014 by
making periodic payments to Generation. These payments will be made on an agreed payment schedule or upon the occurrence of certain specified
events, such as EDF’s disposition of a
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Combined Notes to Consolidated Financial Statements—(Continued)
(Dollars in millions, except per share data unless otherwise noted)
majority of its interest in CENG. However, in the event that EDF exercises its rights under the Put Option, all payments not made as of the put
closing date shall accelerate to be paid immediately prior to such closing date.
As a condition to obtaining regulatory approval for the NOSA and related transactions from the NRC, Exelon executed a support agreement
pursuant to which Exelon may be required under specified circumstances to provide up to $245 million of financial support to CENG (Exelon Support
Agreement). The Exelon Support Agreement supersedes a previous support agreement under which Generation had agreed to provide up to
$205 million of financial support for CENG. In addition, Exelon executed a Guarantee pursuant to which Exelon may be required under specified
circumstances to provide up to $165 million in additional financial support for CENG. A previous support agreement executed by an affiliate of EDF
remains in effect under which the EDF affiliate may be required to provide up to approximately $145 million of financial support for CENG under
specified circumstances. The agreements were executed on April 1, 2014 when the NRC licenses were transferred to Generation. No liability has
been recognized by Exelon for the guarantees.
Prior to April 1, 2014, Exelon and Generation accounted for their investment in CENG under the equity method of accounting. From January 1,
2014, through March 31, 2014, Generation recorded $19 million of equity in losses of unconsolidated affiliates related to its investment in CENG and
recorded $17 million of revenues from CENG. The book value of Generation’s investment in CENG prior to the consolidation was $1.9 billion, and
the book value of the AOCI related to CENG prior to consolidation was $116 million, net of taxes of $77 million.
As a result of the consolidation of CENG on April 1, 2014, there are several additional transactions included in Exelon’s and Generation’s
Consolidated Financial Statements between CENG and Exelon’s affiliates that are considered related party transactions to Generation. As further
described in Note 27—Related Party Transactions, EDF and Generation had a PPA with CENG under which they purchased 15% and 85%,
respectively, of the nuclear output owned by CENG that was not sold to third parties under pre-existing PPAs through December 31, 2014.
Beginning January 1, 2015 and continuing through the life of the respective plants, EDF and Generation purchase 49.99% and 50.01%, respectively,
of the nuclear output owned by CENG not subject to other contractual agreements. Beginning April 1, 2014, CENG’s sales to Generation have been
eliminated in consolidation. For the years ended December 31, 2016, 2015, and 2014 Generation had sales to EDF of $376 million, $488 million,
and $137 million respectively. See discussion above and Note 2—Variable Interest Entities for additional information regarding other transactions
between CENG and EDF included within Exelon and Generation’s consolidated financial statements and for additional information about the
Registrants VIE’s.
Accounting for the Consolidation of CENG
The transfer of the nuclear operating licenses and the execution of the NOSA on April 1, 2014, resulted in the derecognition of the equity
method investment in CENG and the recording of all assets, liabilities and EDF’s noncontrolling interests in CENG at fair value on Exelon’s and
Generation’s Consolidated Balance Sheets. As a result of the consolidation, Exelon and Generation recorded a net gain of $261 million within their
respective Consolidated Statements of Operations and Comprehensive Income. This gain consists of approximately $136 million related to the step
up to fair value basis of Generation’s ownership interest in CENG, and approximately $132 million related to the settlement of pre-existing
transactions between CENG and Generation. The net gain on the consolidation of CENG of $261 million is net of a $7 million payment to EDF.
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Combined Notes to Consolidated Financial Statements—(Continued)
(Dollars in millions, except per share data unless otherwise noted)
The fair value of CENG’s assets and liabilities recorded in consolidation was 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 market prices. There were also judgments made to determine the expected useful lives assigned to each class of assets acquired and
duration of liabilities assumed.
The valuations necessary to assess the fair values of certain assets and liabilities were considered preliminary as a result of the short time
period between the execution of the NOSA and the end of the second quarter of 2014. The estimates of the fair value of assets and liabilities could
be modified for up to one year from April 1, 2014, as more information was obtained about the fair value of assets and liabilities. The principal items
that have been revised include the asset retirement obligation liabilities and related asset retirement costs. These items have been updated with
inputs from a third party engineering firm with corresponding adjustments recorded in 2014 and the first quarter of 2015. See Note 16—Asset
Retirement Obligations for discussion of the impacts of adjustments recorded during 2014 and 2015 related to updated estimates of the CENG asset
retirement obligation liabilities. In the period of such revisions, these and any other material changes to the fair value assessments have resulted in
adjustments to the amounts recorded upon consolidation. In addition, the asset or liability adjustments impacting depreciation and/or accretion
expense recorded after the consolidation date have impacted Generation’s post-consolidation results of operations.
Generation recorded the assets and liabilities of CENG at fair value as of April 1, 2014. The following assets and liabilities of CENG were
recorded within Generation’s Consolidated Balance Sheets as of the date of integration, adjusted for the modifications discussed above:
Fair Values
Current assets
Nuclear decommissioning trust fund
Property, plant and equipment
Nuclear fuel
Other assets
Total assets
Current liabilities
Asset retirement obligation
Pension and other employee benefit obligations
Unamortized energy contract liabilities
Other liabilities
Total liabilities
Total net assets
Exelon and
Generation
499
$
1,955
3,073
482
10
6,019
237
1,816
281
171
114
2,619
3,400
$
Generation also recorded the fair value of the noncontrolling interests on its Consolidated Balance Sheets of approximately $1.5 billion, net of
the fair value of $152 million for certain specified additional distribution rights under the Operating Agreement. In addition, the noncontrolling
interests was further reduced by the $400 million special cash distribution to EDF.
Due to the Preferred Distribution Rights that Generation has on CENG’s available cash, the earnings attributable to the noncontrolling interests
on the Statements of Operations and Comprehensive Income as well as the corresponding adjustment to Noncontrolling interests on the
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Combined Notes to Consolidated Financial Statements—(Continued)
(Dollars in millions, except per share data unless otherwise noted)
Consolidated Balance Sheets will not be in proportion to Generation’s and EDF’s equity ownership interests. Rather, the attribution will consider
Generation’s Preferred Distribution Rights and allocate net income based on each owner’s rights to CENG’s net assets. For the years ended
December 31, 2016 and 2015, Generation reduced by $20 million and $18 million, respectively, the amount of Net income attributable to
noncontrolling interests on Exelon’s and Generation’s Consolidated Statements of Operations and Comprehensive Income. As a result of the
consolidation, Exelon’s and Generation’s Consolidated Statements of Operations and Comprehensive Income includes CENG’s incremental
operating revenues of $548 million and $509 million and CENG’s net income (loss), prior to any intercompany eliminations and any adjustments for
noncontrolling interests, of $201 million and $(11) million during the years ended December 31, 2016 and 2015, respectively.
Exelon and Generation incurred no merger integration-related costs in 2016. However, in 2015 Exelon and Generation incurred $2 million of
merger related integration costs. The costs incurred are classified primarily within Operating and maintenance expense in Exelon’s and Generation’s
respective Consolidated Statements of Operations and Comprehensive Income.
6. Accounts Receivable (All Registrants)
Accounts receivable at December 31, 2016 and 2015 included estimated unbilled revenues, representing an estimate for the unbilled amount
of energy or services provided to customers, and is net of an allowance for uncollectible accounts as follows:
2016
Unbilled customer revenues
Allowance for uncollectible
accounts (b)
2015
Unbilled customer revenues
Allowance for uncollectible
accounts (b)
Exelon Generation
$1,673 $
ComEd PECO
910(a) $ 219 $ 140
BGE
$182 $
Successor
PHI
222
Pepco
$ 123
DPL
$ 58
ACE
$ 41
(334)
(91)
(70)
(61) (c)
(32)
(80) (d)
(29) (d)
(24) (d)
(27) (d)
Exelon Generation
$1,203 $
ComEd PECO
732(a) $ 218 $ 105
BGE
$148 $
PHI
(284)
(77)
(75)
(83) (c)
(49)
177
(56)
Pepco
$ 93
DPL
$ 45
ACE
$ 39
(17)
(17)
(17)
Predecessor
(a) Represents unbilled portion of retail receivables estimated under Exelon’s unbilled critical accounting policy.
(b)
(c) Excludes the non-current allowance for uncollectible accounts of $23 million and $8 million at December 31, 2016 and 2015, respectively, related to PECO’s current
Includes the allowance for uncollectible accounts on customer and other accounts receivable.
installment plan receivables described below.
(d) At December 31, 2016, as explained in Note 1—Significant Accounting Policies, PHI, Pepco, DPL and ACE estimated the allowance for uncollectible accounts on
customer receivables by applying loss rates to the outstanding receivable balance by risk segment. The change in estimate resulted in an overall increase of $30 million,
$14 million, $8 million, and $8 million in the allowance for uncollectible accounts with $20 million, $8 million, $4 million, and $8 million deferred as a regulatory asset on
PHI’s, Pepco’s, DPL’s and ACE’s Consolidated Balance Sheets at December 31, 2016, respectively. This also resulted in a $10 million, $6 million, and $4 million pre-tax
charge to provision for uncollectible accounts expense for the year ended December 31, 2016, which is included in Operating and maintenance expense on PHI’s,
Pepco’s, and DPL’s Consolidated Statements of Operations and Comprehensive Income, respectively.
PECO Installment Plan Receivables (Exelon and PECO). PECO enters into payment agreements with certain delinquent customers,
primarily residential, seeking to restore their service, as required by the PAPUC. Customers with past due balances that meet certain income criteria
are provided the option to enter into an installment payment plan, some of which have terms greater than
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Combined Notes to Consolidated Financial Statements—(Continued)
(Dollars in millions, except per share data unless otherwise noted)
one year, to repay past due balances in addition to paying for their ongoing service on a current basis. The receivable balance for these payment
agreement receivables is recorded in accounts receivable for the current portion and other deferred debits and other assets for the noncurrent
portion. The net receivable balance for installment plans with terms greater than one year was $9 million and $15 million at December 31, 2016 and
2015, respectively. The allowance for uncollectible accounts reserve methodology and assessment of the credit quality of the installment plan
receivables are consistent with the customer accounts receivable methodology discussed in Note 1—Significant Accounting Policies. The allowance
for uncollectible accounts balance associated with these receivables at December 31, 2016 of $13 million consists of $1 million, $3 million and
$9 million for low risk, medium risk and high risk segments, respectively. The allowance for uncollectible accounts balance associated with these
receivables at December 31, 2015 of $15 million consists of $1 million, $3 million and $11 million for low risk, medium risk and high risk segments,
respectively. The balance of the payment agreement is billed to the customer in equal monthly installments over the term of the agreement.
Installment receivables outstanding as of December 31, 2016 and 2015 include balances not yet presented on the customer bill, accounts currently
billed and an immaterial amount of past due receivables. When a customer defaults on its payment agreement, the terms of which are defined by
plan type, the entire balance of the agreement becomes due and the balance is reclassified to current customer accounts receivable and reserved
for in accordance with the methodology discussed in Note 1—Significant Accounting Policies.
7. 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, 2016 and 2015:
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
3-56
5-90
4-50
1-8
N/A
3-50
2016
2015
$45,698
27,193
4,642
1,312
6,546
4,306
1,027
90,724
19,169
$71,555
$32,546
25,615
3,864
1,149
6,384
3,075
1,181
73,814
16,375
$57,439
(a)
(b)
Includes nuclear fuel that is in the fabrication and installation phase of $1,326 million and $1,266 million at December 31, 2016 and 2015, respectively.
Includes Generation’s buildings under capital lease with a net carrying value of $10 million and $13 million at December 31, 2016 and 2015, respectively. The original cost
basis of the buildings was $52 million, and total accumulated amortization was $42 million and $39 million, as of December 31, 2016 and 2015, respectively. Also includes
ComEd’s buildings under capital lease with a net carrying value at both December 31, 2016 and 2015, 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, 2016 and 2015. Includes land held for future use and non utility property at ComEd, PECO,
BGE, Pepco, DPL, and ACE of $60 million, $21 million, $32 million, $66 million, $16 million, and $27 million, respectively, at December 31, 2016. At December 31, 2015
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Combined Notes to Consolidated Financial Statements—(Continued)
(Dollars in millions, except per share data unless otherwise noted)
these balances also include capitalized acquisition, development and exploration costs of $266 million related to oil and gas production activities at Generation, see Note 4
—Mergers, Acquisitions, and Dispositions for additional information regarding the sale of upstream assets. Includes the original cost and progress payments associated
with Generation’s turbine equipment held for future use with a carrying value of $17 million and $146 million at December 31, 2016 and 2015, respectively. See Note 8—
Impairment of Long-Lived Assets for additional information on the impairment of Generations turbine equipment.
Includes accumulated amortization of nuclear fuel in the reactor core at Generation of $3,186 million and $2,861 million as of December 31, 2016 and 2015, 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
Gas
Common—electric and gas
2016
2.73%
5.94% (a)
2.17%
7.41%
2015
2.83%
3.47%
2.17%
7.79%
2014
2.93%
3.50%
2.13%
7.32%
(a) See Note 9—Early Nuclear Plant Retirements for additional information on the accelerated net depreciation and amortization of Clinton and Quad Cities.
Generation
The following table presents a summary of property, plant and equipment by asset category as of December 31, 2016 and 2015:
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)
3-56
1-8
N/A
4
2016
2015
$27,193
6,546
2,332
76
36,147
10,562
$25,585
$25,615
6,384
2,017
466
34,482
8,639
$25,843
(a)
(b)
(c)
Includes nuclear fuel that is in the fabrication and installation phase of $1,326 million and $1,266 million at December 31, 2016 and 2015, respectively.
Includes buildings under capital lease with a net carrying value of $10 million and $13 million at December 31, 2016 and 2015, respectively. The original cost basis of the
buildings was $52 million, and total accumulated amortization was $42 million and $39 million, as of December 31, 2016 and 2015, respectively. At December 31, 2015
these balances also include capitalized acquisition, development and exploration costs of $266 million related to oil and gas production activities at Generation, see Note 4
—Mergers, Acquisitions, and Dispositions for additional information regarding the sale of upstream assets. Includes the original cost and progress payments associated
with Generation’s turbine equipment held for future use with a carrying value of $17 million and $146 million at December 31, 2016 and 2015, respectively. See Note 8—
Impairment of Long-Lived Assets for additional information on the impairment of Generations turbine equipment.
Includes accumulated amortization of nuclear fuel in the reactor core of $3,186 million and $2,861 million as of December 31, 2016 and 2015, respectively.
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Combined Notes to Consolidated Financial Statements—(Continued)
(Dollars in millions, except per share data unless otherwise noted)
The annual depreciation provisions as a percentage of average service life for electric generation assets were 5.94%, 3.47% and 3.50% for the
years ended December 31, 2016, 2015 and 2014, respectively. See Note 9—Early Nuclear Plant Retirements for additional information on the
accelerated net depreciation and amortization of Clinton and Quad Cities.
License Renewals. Generation’s depreciation provisions are based on the estimated useful lives of its generating stations, which assume the
renewal of the licenses for all nuclear generating stations (except for Oyster Creek and Clinton) and the hydroelectric generating stations. As a
result, the receipt of license renewals has no material impact on the Consolidated Statements of Operations and Comprehensive Income. Oyster
Creek depreciation provisions are based on the 2019 expected shutdown date. Clinton depreciation provisions are based on 2027 which is the last
year of the Illinois ZECs. See Note 3—Regulatory Matters for additional information regarding license renewals and the Illinois ZECs. See Note 9—
Early Nuclear Plant Retirements for additional information on the impacts of expected and potential early plant retirement.
ComEd
The following table presents a summary of property, plant and equipment by asset category as of December 31, 2016 and 2015:
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
37-50
2016
2015
$22,636
569
67
23,272
3,937
$19,335
$20,576
572
64
21,212
3,710
$17,502
(a)
(b)
Includes buildings under capital lease with a net carrying value at both December 31, 2016 and 2015 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, 2016 and 2015.
Includes 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 3.03%, 3.03%
and 3.05% for the years ended December 31, 2016, 2015 and 2014, respectively.
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PECO
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, 2016 and 2015:
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)
2016
2015
5-65
5-70
5-50
N/A
50
$ 7,591
2,348
670
188
21
10,818
3,253
$ 7,565
$ 7,230
2,206
631
154
21
10,242
3,101
$ 7,141
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
BGE
2016
2.32%
1.82%
5.11%
2015
2.39%
1.87%
5.16%
2014
2.55%
1.84%
5.16%
The following table presents a summary of property, plant and equipment by asset category as of December 31, 2016 and 2015:
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 land held for future use and non-utility property.
393
Average Service Life
(years)
2016
2015
5-90
5-90
5-40
N/A
20
$ 7,067
2,170
707
318
32
10,294
3,254
$ 7,040
$6,663
1,951
655
312
32
9,613
3,016
$6,597
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
PHI
2016
2.56%
2.45%
9.45%
2015
2.62%
2.50%
10.35%
2014
2.96%
2.47%
9.49%
The following table presents a summary of property, plant and equipment by asset category as of December 31, 2016 and 2015:
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)
Successor
Predecessor
2016
2015
5-86
5-75
4-40
N/A
3-43
$ 10,315
414
65
892
107
11,793
195
$ 11,598
$
$
14,563
547
164
591
339
16,204
5,340
10,864
(a) Represents plant held for future use and non-utility property. Utility plant is generally subject to a first mortgage lien.
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
394
2016
2.52%
2.57%
8.12%
2015
2.48%
2.55%
5.19%
2014
2.42%
2.48%
4.55%
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Pepco
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, 2016 and 2015:
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
Average Service Life
(years)
2016
2015
5-86
N/A
10-33
$8,018
537
66
8,621
3,050
$5,571
$7,682
318
91
8,091
2,929
$5,162
(a) Represents plant held for future use and non-utility property. Utility plant is generally subject to a first mortgage lien.
The annual depreciation provisions as a percentage of average service life for electric transmission and distribution assets were 2.17%, 2.13%
and 2.10% for the years ended December 31, 2016, 2015 and 2014, respectively.
DPL
The following table presents a summary of property, plant and equipment by asset category as of December 31, 2016 and 2015:
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
2016
2015
5-68
5-75
4-40
N/A
10-43
$3,574
580
115
163
16
4,448
1,175
$3,273
$3,431
547
108
107
16
4,209
1,139
$3,070
(a) Represents plant held for future use and non-utility property. Utility plant is generally subject to a first mortgage lien.
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
395
2016
2.49%
2.57%
4.99%
2015
2.44%
2.55%
4.24%
2014
2.41%
2.48%
4.08%
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ACE
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, 2016 and 2015:
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
Average Service Life
(years)
2016
2015
5-55
N/A
13-15
$3,341
169
27
3,537
1,016
$2,521
$3,105
158
28
3,291
969
$2,322
(a) Represents plant held for future use and non-utility property. Utility plant is generally subject to a first mortgage lien.
The annual depreciation provisions as a percentage of average service life for electric transmission and distribution assets were 2.45%, 2.46%
and 2.48% for the years ended December 31, 2016, 2015 and 2014, respectively.
See Note 1—Significant Accounting Policies for further information regarding property, plant and equipment policies and accounting for
capitalized software costs for the Registrants. See Note 14—Debt and Credit Agreements for further information regarding Exelon’s, ComEd’s, and
PECO’s property, plant and equipment subject to mortgage liens.
8. Impairment of Long-Lived Assets (Exelon and Generation)
Long-Lived Assets (Exelon and Generation)
Generation evaluates long-lived assets or asset groups for recoverability whenever events or changes in circumstances indicate that the
carrying amount may not be recoverable. In the second quarter of 2016, updates to the Company’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.
Also in the second quarter of 2016, updates to the Company’s long-term view, as described above, in conjunction with the retirement
announcements of the Quad Cities and Clinton nuclear plants in Illinois suggested that the carrying value of our Midwest asset group may be
impaired. Generation completed a comprehensive review of the estimated undiscounted future cash flows of the Midwest asset group and no
impairment charge was required.
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Combined Notes to Consolidated Financial Statements—(Continued)
(Dollars in millions, except per share data unless otherwise noted)
In 2015, the year over year change in fundamentals did not indicate any impairments. In 2014, the year over year change in fundamentals
suggested that the carrying value of certain merchant wind assets may be impaired. Generation concluded that the estimated undiscounted future
cash flows and fair value of twelve wind projects, primarily located in West Texas, were less than their respective carrying values at May 31, 2014.
As a result, long-lived assets held and used with a carrying amount of approximately $151 million were written down to their fair value of $65 million
and a pre-tax impairment charge of $86 million was recorded within Operating and maintenance expense in Exelon’s and Generation’s Consolidated
Statements of Operations and Comprehensive Income.
During 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 14—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
14—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 4—Mergers, Acquisitions,
and Dispositions for additional information.
During 2015 and 2014, significant declines in oil and gas prices suggested that the carrying value of certain Upstream assets may be impaired.
Generation concluded that the estimated undiscounted future cash flows and fair value of various Upstream properties, primarily located in
Oklahoma and Texas, were less than their respective carrying values at December 31, 2015 and 2014. As a result, pre-tax impairment charges of
$5 million and $124 million were recorded for the years ended December 31, 2015 and 2014, respectively, within Operating and maintenance
expense within Exelon’s and Generation’s Consolidated Statements of Operations and Comprehensive Income.
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.
In 2014, certain non-nuclear generating assets were identified as assets held for sale on Exelon’s and Generation’s Consolidated Balance
Sheets. When long-lived assets are held for sale, an impairment loss is recognized to the extent that the asset’s carrying value exceeds its estimated
fair value less costs to sell. Long-lived assets with a carrying amount of approximately $1 billion were written down to their fair value of $556 million
and a pre-tax impairment charge of $450 million was recorded within Operating and maintenance expense and is included in Exelon’s and
Generation’s Consolidated Statements of Operations and Comprehensive Income for the year ended December 31, 2014. See Note 4—Mergers,
Acquisitions, and Dispositions for further information on asset sales.
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Combined Notes to Consolidated Financial Statements—(Continued)
(Dollars in millions, except per share data unless otherwise noted)
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 accounting 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 under the income
approach, which uses a discounted cash flow analysis, which takes 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 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.
Based on the annual reviews performed in the second quarters of 2015 and 2014, the estimated residual value of Exelon’s direct financing
leases for the Georgia generating stations experienced other than temporary declines given increases in estimated long-term operating and
maintenance costs in the 2015 annual review and reduced long-term energy and capacity price expectations in the 2014 annual review. As a result,
Exelon recorded $24 million pre-tax impairment charges in both 2015 and 2014 for these stations. These impairment charges were recorded within
Investments and Operating and maintenance expense in Exelon’s Consolidated Balance Sheets and the Consolidated Statements of Operations
and Comprehensive Income, respectively. 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 February 26, 2014, UII and the City Public Service Board of San Antonio, Texas (CPS) finalized an agreement to terminate the leases on
the generating station located in Texas, as described above, prior to its expiration dates. As a result of the lease termination, UII received a net early
termination amount of $335 million from CPS and wrote down the net investment in the CPS long-term lease of $336 million in Investments in
Exelon’s Consolidated Balance Sheets in 2014; resulting in a pre-tax loss of $1 million being reflected in Operating and maintenance expense in the
Consolidated Statements of Operations and Comprehensive Income in 2014.
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 15—
Income Taxes for additional information.
As of December 31, 2016, all the long-term leases had been terminated and no residual and net investment value was outstanding. At
December 31, 2015, the components of the net investment in the
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Combined Notes to Consolidated Financial Statements—(Continued)
(Dollars in millions, except per share data unless otherwise noted)
long-term leases consisted of estimated residual value of $639 million, unearned income of $287 million and a resulting net investment of
$352 million.
9. Early Nuclear Plant Retirements (Exelon and Generation)
Exelon and Generation continue to evaluate the current and expected economic value of each of Generation’s nuclear plants. Factors that will
continue to affect the economic value of Generation’s nuclear plants include, but are not limited to: market power prices, results of capacity auctions,
potential legislative and regulatory solutions to ensure nuclear plants are fairly compensated for their carbon-free emissions, and the impact of final
rules from the EPA requiring reduction of carbon and other emissions and the efforts of states to implement those final rules.
In 2015, Generation identified the Quad Cities, Clinton and Ginna nuclear plants as having the greatest risk of early retirement based on
economic valuation and other factors. At that time, Exelon and Generation deferred retirement decisions on Clinton and Quad Cities until 2016 in
order to participate in the 2016-2017 MISO primary reliability auction and the 2019-2020 PJM capacity auctions held in April and May 2016,
respectively, as well as to provide Illinois policy makers with additional time to consider needed reforms and for MISO to consider market design
changes to ensure long-term power system reliability in southern Illinois.
In April 2016, Clinton cleared the MISO primary reliability auction as a price taker for the 2016-2017 planning year. The resulting capacity price
was insufficient to cover cash operating costs and a risk-adjusted rate of return to shareholders. In May 2016, Quad Cities did not clear in the PJM
capacity auction for the 2019-2020 planning year and will not receive capacity revenue for that period.
Based on these capacity auction results, and given the lack of progress on Illinois energy legislation and MISO market reforms, on June 2,
2016 Generation announced it would move forward to shut down the Clinton and Quad Cities nuclear plants on June 1, 2017 and June 1, 2018,
respectively. The current Nuclear Regulatory Commission (NRC) licenses for Clinton and Quad Cities expire in 2026 and 2032, respectively.
In June 2016, as a result of the retirement decision for Clinton and Quad Cities, Exelon and Generation recognized one-time charges in
Operating and maintenance expense of $146 million related to materials and supplies inventory reserve adjustments, employee-related costs and
construction work-in-progress (CWIP) impairments, among other items. In addition to these one-time charges, Exelon and Generation began
recognizing incremental non-cash charges to earnings stemming from shortening the expected economic useful life of Clinton and Quad Cities,
including accelerated depreciation of plant assets (along with any asset retirement costs (ARC)), accelerated amortization of nuclear fuel, and
additional asset retirement obligation (ARO) accretion expense associated with the changes in decommissioning timing and cost assumptions.
On December 7, 2016, Illinois FEJA was signed into law by the Governor of Illinois and included a ZES that provides compensation through
the procurement of ZECs targeted at preserving the environmental attributes of zero-emissions nuclear-powered generating facilities that meet
specific eligibility criteria, much like the solution implemented with the New York CES. The Illinois ZES will have a 10-year duration extending from
June 1, 2017 through May 31, 2027. See Note 3—Regulatory Matters for additional discussion on the Illinois FEJA and the ZES.
With the passage of the Illinois ZES, and subject to prevailing over any related potential administrative or legal challenges, in December 2016
Generation reversed its June 2016 decision to
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Combined Notes to Consolidated Financial Statements—(Continued)
(Dollars in millions, except per share data unless otherwise noted)
permanently cease generation operations at the Clinton and Quad Cities nuclear generating plants. Accordingly, in December 2016 Exelon and
Generation reversed approximately $120 million of the one-time charges initially recorded in June 2016 associated with the early retirements
primarily for employee-related costs and a materials and supplies inventory reserve adjustment. In addition, 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. See
Note 16—Asset Retirement Obligations for additional detail on changes to the Nuclear decommissioning ARO balances resulting from the initial
decision and subsequent reversal of the decision to early retire Clinton and Quad Cities.
Through December 31, 2016, Exelon’s and Generation’s results include a net incremental $688 million of pre-tax expense associated with the
initial early retirement decision for Clinton and Quad Cities, as summarized in the table below.
Income statement expense (pre-tax)
Depreciation and Amortization
Accelerated depreciation (a)
Accelerated nuclear fuel amortization
Operating and Maintenance
Increase ARO accretion, net of contractual offset (b)
Contractual offset for ARC depreciation (b)
Total
2016
$712
60
2
(86)
$688
(a) Reflects incremental accelerated depreciation of plant assets, including any ARC, for the period June 2, 2016, through December 6, 2016.
(b) For Quad Cities based on the regulatory agreement with the Illinois Commerce Commission, 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.
In New York, the Ginna and Nine Mile Point nuclear plants continue to face significant economic challenges and risk of retirement before the
end of each unit’s respective operating license period (2029 for Ginna and Nine Mile Point Unit 1, and 2046 for Nine Mile Point Unit 2). On August 1,
2016, the NYPSC issued an order adopting the CES, which would provide payments to Ginna and Nine Mile Point for the environmental attributes of
their production. On November 18, 2016 Ginna and Nine Mile Point executed the necessary contracts with NYSERDA, as required under the CES.
Subject to prevailing over any administrative or legal challenges, the CES will allow Ginna and Nine Mile Point to continue to operate at least through
the life of the program (March 31, 2029). The assumed useful life for depreciation purposes is through the end of their current operating licenses.
The approved RSSA currently requires Ginna to continue operating through the RSSA term expiring on March 31, 2017 and required notification to
the NYPSC if Ginna did not plan to retire shortly after the expiration of the RSSA. On September 30, 2016, Ginna filed the required notice with the
NYPSC of its intent to continue operating beyond the expiry of the RSSA. Refer to Note 3—Regulatory Matters for additional discussion on the
Ginna RSSA and the New York CES.
Assuming the successful implementation of the Illinois ZES and the New York CES and the continued effectiveness of these programs,
Generation and CENG, through its ownership of Ginna and
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Combined Notes to Consolidated Financial Statements—(Continued)
(Dollars in millions, except per share data unless otherwise noted)
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 results of operations, cash flows and
financial position.
The Three Mile Island (TMI) nuclear plant also did not clear in the May 2016 PJM capacity auction for the 2019-2020 planning year and will not
receive capacity revenue for that period. This is the second consecutive year that TMI failed to clear the capacity auction. Although the plant is
committed to operate through May 2019, the plant faces continued economic challenges and Exelon and Generation are exploring all options to
return it to profitability. While a portion of the Byron nuclear plant’s capacity did not clear the PJM 2019-2020 planning year capacity auction, the
plant is committed to run through May 2020. The Company’s other nuclear plants in PJM cleared in the auction, except Oyster Creek, which did not
participate in the auction given Exelon’s and Generation’s previous commitment to cease operation of the Oyster Creek nuclear plant by the end of
2019.
The following table provides the balance sheet amounts as of December 31, 2016 for significant assets and liabilities associated with TMI
currently considered by management to be at the greatest risk of early retirement due to current economic valuations and other factors.
(in millions)
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
TMI
$
39
83
1,015
37
(565)
2034
The precise timing of an early retirement date for any nuclear plant, and the resulting financial statement impacts, may be affected by a
number of 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 decommissioning trust fund requirements, 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, where
applicable, and just prior to its next scheduled nuclear refueling outage.
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Combined Notes to Consolidated Financial Statements—(Continued)
(Dollars in millions, except per share data unless otherwise noted)
10. Jointly Owned Electric Utility Plant (Exelon, Generation, PECO, BGE, PHI, Pepco, DPL and ACE)
Exelon’s, Generation’s, PECO’s, BGE’s, PHI’s and ACE’s undivided ownership interests in jointly owned electric plants and transmission
facilities at December 31, 2016 and 2015 were as follows:
Operator
Ownership interest
Exelon’s share at December 31, 2016:
Plant (e)
Accumulated depreciation (e)
Construction work in progress
Exelon’s share at December 31, 2015:
Plant (e)
Accumulated depreciation (e)
Construction work in progress
Quad Cities
Generation
Nuclear Generation
Peach
Bottom
Generation
Salem (a)
PSEG
Nuclear
Fossil Fuel
Generation
Nine Mile
Point Unit 2
Generation
Wyman
FP&L
Transmission
Other
PA (b)
First
Energy
NJ/DE (c)
PSEG/
DPL
Other (d)
various
75.00%
50.00%
42.59%
82.00%
5.89% various various various
$
$
$
$
1,054
515
—
1,035
309
11
$
$
1,384
407
16
1,345
368
18
$
$
596
186
41
566
167
40
$
$
830
68
37
756
42
56
$
$
3
3
—
3
3
—
27 $
15
—
27 $
15
—
97 $
52
—
93 $
52
—
15
13
—
15
13
—
(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
December 31, 2016 and 2015.
(b) PECO, BGE, Pepco, DPL and ACE own a 22%, 7%, 27%, 9% and 8% share, respectively, in 127 miles of 500kV lines located in Pennsylvania as well as a 20.72%,
10.56%, 9.72%, 3.72% and 3.83% share, respectively, of a 500kV substation immediately outside of the Conemaugh fossil generating station which supplies power to the
500kV 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 500kV lines located in New Jersey and Delaware Station. PECO, DPL and ACE
also own a 42.55%, 7.45% and 7.45% share, respectively, in 2.5 miles of 500kV line located over the Delaware River. ACE also has a 21.78% share in a 500kV New
Freedom Switching
(d) Generation, DPL and ACE own a 44.24%, 4.83% and 11.91% 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.
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
on Exelon’s and Generation’s Consolidated Statements of Operations and Comprehensive Income and in Operating and maintenance expenses on
PECO’s, BGE’s, Pepco, 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)
11. Intangible Assets (Exelon, Generation, ComEd, PECO, PHI, Pepco, DPL and ACE)
Goodwill
Exelon’s, Generation’s, ComEd’s, PHI’s, and DPL’s gross amount of goodwill, accumulated impairment losses and carrying amount of goodwill
for the years ended December 31, 2016 and 2015 were as follows:
Exelon
Gross amount
Accumulated impairment loss
Carrying amount
Generation
Gross amount
Carrying amount
ComEd (a)
Gross amount
Accumulated impairment loss
Carrying amount
DPL
Gross amount
Carrying amount
March 24, 2016 to December 31, 2016
PHI— Successor
Gross amount
Accumulated impairment loss
Carrying amount
January 1, 2016 to March 23, 2016
PHI— Predecessor
Gross amount
Accumulated impairment loss
Carrying amount
For the Year Ended December 31, 2015
PHI— Predecessor
Gross amount
Accumulated impairment loss
Carrying amount
Balance at
January 1,
2015
Impairment
losses
Balance at
December 31,
2015
Goodwill
from
business
combination
Impairment
losses
Measurement
period
adjustments
(b)
Balance at
December 31,
2016
$
4,655 $
1,983
2,672
47
47
4,608
1,983
2,625
8
8
— $
—
—
—
—
—
—
—
—
—
4,655 $
1,983
2,672
4,016 $
—
4,016
47
47
4,608
1,983
2,625
8
8
—
—
—
—
—
—
—
— $
—
—
—
—
—
—
—
—
—
(11) $
—
(11)
—
—
—
—
—
—
—
Beginning
Balance
$
—
—
—
1,418
12
1,406
1,425
18
1,407
Goodwill from
business
combination
Impairment
losses
Measurement
period
adjustments
(b)
$
$
4,016
—
4,016
—
—
—
—
—
—
$
—
—
—
—
—
—
(7)
(6)
(1)
(11)
—
(11)
—
—
—
—
—
—
8,660
1,983
6,677
47
47
4,608
1,983
2,625
8
8
Ending
Balance
$ 4,005
—
4,005
1,418
12
1,406
1,418
12
1,406
(a) Reflects goodwill recorded in 2000 from the PECO/Unicom (predecessor parent company of ComEd) merger net of amortization, resolution of tax matters and other
non-impairment-related changes as allowed under previous authoritative guidance.
(b) Represents various measurement period adjustments to the valuation of the fair value of the PHI assets acquired and liabilities assumed as a result of the merger.
403
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Combined Notes to Consolidated Financial Statements—(Continued)
(Dollars in millions, except per share data unless otherwise noted)
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 the Exelon, Generation, ComEd, PHI and DPL reporting unit below its carrying
amount. Under the authoritative guidance for goodwill, 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.
Generation’s operating segments are Mid-Atlantic, Midwest, New England, New York, ERCOT and all other power regions referred to collectively as
“Other Power Regions”, PHI’s operating segments are Pepco, DPL and ACE, and ComEd and DPL have a single operating segment. See Note 26—
Segment Information for additional information. There is no level below these operating segments for which operating results are regularly reviewed
by segment management. Therefore, the ComEd, Pepco, DPL and ACE operating segments are also considered reporting units for goodwill
impairment testing purposes. Exelon’s and ComEd’s $2.6 billion of goodwill has been assigned entirely to the ComEd reporting unit, while Exelon’s
and PHI’s $4 billion of goodwill has been assigned to the Pepco, DPL and ACE reporting units in the amounts of $1.7 billion, $1.1 billion and $1.2
billion, respectively. DPL’s $8 million of goodwill is assigned entirely to the DPL reporting unit.
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, Generation’s, ComEd’s, PHI’s and
DPL’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
accounting guidance in order to determine the implied fair value of goodwill. If the implied 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 Generation’s, 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.
2016 and 2015 Goodwill Impairment Assessment. Generation performed a qualitative test as of November 1, 2016, for its 2016 annual
goodwill impairment assessment. Generation previously completed its last quantitative assessment in the first quarter of 2015, and updated its
qualitative assessment as of November 1, 2015. Based on the qualitative factors above, Generation concluded that the fair value of the reporting unit
is more likely than not greater than the carrying amount, and no further testing was required.
404
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Combined Notes to Consolidated Financial Statements—(Continued)
(Dollars in millions, except per share data unless otherwise noted)
Exelon, ComEd, PHI, and DPL performed quantitative tests as of November 1, 2016, for their 2016 annual goodwill impairment assessments.
The first step of the tests comparing the estimated fair values of the ComEd, Pepco, DPL, and ACE reporting units to their carrying values, including
goodwill, indicated no impairments of goodwill; therefore, no second steps were 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, PHI’s
or DPL’s goodwill, which could be material. Based on the results of the annual goodwill test performed as of November 1, 2016, the estimated fair
values of the ComEd, Pepco, DPL and ACE reporting units would have needed to decrease by more than 30%, 10%, 10% and 10%, respectively,
for Exelon, ComEd and PHI to fail the first step of their respective impairment tests. The $8 million of goodwill recorded at DPL is related to DPL’s
1995 acquisition of the Conowingo Power Company and the fair value of the DPL reporting unit would have needed to decrease by more than 50%
for DPL to fail the first step of the impairment test.
As of November 1, 2015, Exelon, ComEd, and PHI qualitatively determined that the fair value of their reporting units was not more likely than
not less than their carrying value and, therefore, did not perform quantitative assessments. As part of their qualitative assessments, Exelon, ComEd
and PHI evaluated, among other things, management’s best estimate of projected operating and capital cash flows for their respective business, as
well as, 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.
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Table of Contents
Combined Notes to Consolidated Financial Statements—(Continued)
(Dollars in millions, except per share data unless otherwise noted)
Other Intangible Assets and Liabilities
Exelon’s, Generation’s, ComEd’s and PHI’s other intangible assets and liabilities, included in Unamortized energy contract assets and liabilities
and Other deferred debits and other assets in their Consolidated Balance Sheets, consisted of the following as of December 31, 2016:
Exelon
Software License Agreement (a)
Generation
Unamortized Energy Contracts (b)
Exelon Wind (c)
Antelope Valley (d)
Constellation (e)
CENG (f)
Integrys (g)
ConEdison (h)
Service Contract Backlog
PES (h)
Customer Relationships (i)
Constellation (e)
Integrys (g)
PES (h)
ConEdison (h)
Trade Names
Constellation (e)
ComEd
Weighted
Average
Amortization
Years (l)
Gross
Accumulated
Amortization
Net
2017
2018
2019
2020
2021
Estimated amortization expense
10.0 $
95 $
(15) $
80 $ 10 $ 10 $ 10 $ 10 $ 10
18.0
25
1.5
1.7
2.4
1.5
224
190
1,499
(97)
5
100
(83)
(28)
(1,440)
59
(3)
(53)
141
162
59
(38)
2
47
14
8
(21)
(15)
1
37
14
8
11
(18)
1
7
14
8
8
(15)
—
2
10
8
10
(8)
—
1
10
8
10
(4)
—
—
1.0
9
(7)
2
2
—
—
—
—
12.4
10.0
15.0
10.0
214
50
12
9
(94)
(11)
(1)
—
120
39
11
9
18
5
1
1
18
5
1
1
17
5
1
1
17
5
1
1
17
5
1
1
10.0
243
(125)
118
23
23
23
23
23
Chicago settlement—1999 agreement (j)
Chicago settlement—2003 agreement (k)
21.8
17.9
100
62
(86)
(47)
14
15
3
4
3
4
3
4
3
4
—
—
PHI
Unamortized Energy
Contracts (h)
Pepco
6.8
(1,515)
430
(1,085)
(335)
(189)
(119)
(115)
(92)
DC Sponsorship Agreement (m)
Total
0
25
$ 1,225 $
—
—
(1,504) $ (279) $(244) $(101) $ (38) $ (30) $ (11)
—
—
—
—
25
(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
intangible asset recognized as a result of these payments is being amortized on a straight-line basis over the contract term.
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Combined Notes to Consolidated Financial Statements—(Continued)
(Dollars in millions, except per share data unless otherwise noted)
(b)
(c)
(d)
Includes unamortized energy contract assets and liabilities on Exelon’s and Generation’s Consolidated Balance Sheets. Excludes $10 million of other miscellaneous
unamortized energy contracts that have been acquired at various points in time. The estimated amortization for these miscellaneous unamortized energy contracts is $(9)
million, $(7) million, $(6) million, $(2) million and $4 million for 2017, 2018, 2019, 2020 and 2021, respectively.
In December 2010, Generation acquired all of the equity interests of John Deere Renewables, LLC (later named Exelon Wind), adding 735 MWs of installed, operating
wind capacity located in eight states.
In September 2011, Generation acquired all of the interest in Antelope Valley Solar Ranch One, a 242 MW solar project in northern Los Angeles County, CA from First
Solar, Inc.
(e) On March 12, 2012, Constellation merged into Exelon with Exelon continuing as the surviving corporation pursuant to the transactions contemplated by the Agreement
and Plan of Merger. Since the merger transaction, Generation includes the former Constellation generation and customer supply operations.
(j)
(k)
(f) See Note 5—Investment in Constellation Energy Nuclear Group, LLC for additional information.
(g) On November 1, 2014, Generation acquired the competitive retail electric and natural gas business activities of Integrys Energy Group, Inc.
(h) See Note 4—Mergers, Acquisitions, and Dispositions for additional information.
(i)
Excludes $11 million of other miscellaneous customer relationships that have been acquired. The estimated amortization for these miscellaneous customer relationships is
$1 million in each of the years from 2017 to 2021.
In March 1999, ComEd entered into a settlement agreement with the City of Chicago associated with ComEd’s franchise agreement. Under the terms of the settlement,
ComEd agreed to make payments to the City of Chicago each year from 1999 to 2002. The intangible asset recognized as a result of these payments is being amortized
ratably over the remaining term of the franchise agreement, which ends in 2020.
In February 2003, ComEd entered into separate agreements with the City of Chicago and with Midwest Generation, LLC (Midwest Generation). Under the terms of the
settlement agreement with the City of Chicago, ComEd agreed to pay the City of Chicago a total of $60 million over a ten-year period, beginning in 2003. 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, which ends in
2020. As required by the settlement, ComEd also made a payment of $2 million to a third-party on the City of Chicago’s behalf. Under the terms of the agreement with
Midwest Generation, ComEd received payments of $32 million from Midwest Generation to relieve Midwest Generation’s obligation under the 1999 fossil sale agreement
with ComEd to build the generation facility in the City of Chicago. The payments received by ComEd, which have been recorded in Other deferred credits and other
liabilities, and other long-term liabilities on Exelon’s and ComEd’s Consolidated Balance Sheets are being recognized ratably (approximately $2 million annually) as an
offset to amortization expense over the remaining term of the franchise agreement.
(l) Weighted-average amortization period was calculated at the date of a) acquisition for acquired assets or b) settlement agreement.
(m)
In the third quarter of 2015, Pepco entered into a sponsorship agreement with the District of Columbia for future naming rights associated with public property within the
District of Columbia to be determined over time through future negotiations. Amortization of the intangible asset will begin once the terms of the naming rights are defined.
The following table summarizes the amortization expense related to intangible assets and liabilities for each of the years ended December 31,
2016, 2015 and 2014:
For the Year Ended December 31,
2016
2015
2014
Exelon
(a)
$
87
76
179
Generation
(a)
$
79
69
179
ComEd
7
$
7
7
(a) At Exelon, amortization of unamortized energy contracts totaling $35 million, $22 million and $135 million for the years ended December 31, 2016, 2015 and 2014,
respectively, was recorded in Operating revenues or Purchase power and fuel expense within Exelon’s Consolidated Statements of Operations and Comprehensive
Income. At Generation, amortization of unamortized energy contracts totaling $35 million, $22 million and $135 million for the years ended December 31, 2016, 2015 and
2014, respectively, was recorded in Operating revenues or Purchase power and fuel expense within 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)
Acquired Intangible Assets and Liabilities
Accounting guidance for business combinations requires 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 accounting 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 Purchase 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 accounting guidance. Key assumptions
include the customer attrition rate and the discount rate. The accounting 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.
Service Contract Backlog. The service contract backlog 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
contracts. The fair value is based upon certain unobservable inputs, which are considered Level 3 inputs, pursuant to applicable accounting
guidance. Key assumptions include estimated revenues and expenses to complete the contracts as well as the discount rate. The accounting
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 service contract backlog is 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
408
Table of Contents
Combined Notes to Consolidated Financial Statements—(Continued)
(Dollars in millions, except per share data unless otherwise noted)
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 accounting 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, ComEd, PECO, DPL and ACE)
Exelon’s, Generation’s, ComEd’s, PECO’s, DPL’s and ACE’s other intangible assets, included in Other current assets and Other deferred
debits and other assets on the Consolidated Balance Sheets, include RECs (Exelon, Generation, ComEd, 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 part of a bundled power sale is recognized when the power is produced and
delivered to the customer, otherwise, the revenue is recognized upon physical transfer of the REC. As of December 31, 2016, and 2015, PECO had
current AECs of $1 million and $2 million, respectively. PECO had no noncurrent AECs as of December 31, 2016 and 2015. As of December 31,
2016, and 2015, Generation had current RECs of $317 million and $251 million, respectively, and $29 million and $56 million of noncurrent REC’s,
respectively. ComEd had no current RECs as of December 31, 2016 and $5 million as of December 31, 2015. ComEd had no noncurrent RECs as
of December 31, 2016 and 2015. As of December 31, 2016 and 2015, DPL had current RECs of $11 million and $9 million, respectively. DPL had no
noncurrent RECs as of December 31, 2016 and 2015. As of December 31, 2016 and 2015, ACE had current RECs of $1 million. ACE had no
noncurrent RECs as of December 31, 2016 and 2015. See Note 3—Regulatory Matters and Note 24—Commitments and Contingencies for
additional information on RECs and AECs.
12. 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, 2016 and 2015:
Exelon
Short-term liabilities
Long-term debt (including amounts due within one year) (a)
Long-term debt to financing trusts (b)
SNF obligation
Carrying
Amount
$ 1,267
34,005
641
1,024
December 31, 2016
Fair Value
Level 1
$ —
1,113
—
—
Level 2
$ 1,267
31,741
—
732
Level 3
$ —
1,959
667
—
Total
$ 1,267
34,813
667
732
409
Table of Contents
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)
Long-term debt to financing trusts (b)
SNF obligation
Generation
Short-term liabilities
Long-term debt (including amounts due within one year) (a)
SNF obligation
Short-term liabilities
Long-term debt (including amounts due within one year) (a)
SNF obligation
ComEd
Long-term debt (including amounts due within one year) (a)
Long-term debt to financing trusts (b)
Short-term liabilities
Long-term debt (including amounts due within one year) (a)
Long-term debt to financing trusts (b)
PECO
Long-term debt (including amounts due within one year) (a)
Long-term debt to financing trusts
410
Carrying
Amount
$
536
25,145
641
1,021
December 31, 2015
Fair Value
Level 1
$
3
931
—
—
Level 2
$
533
23,644
—
818
Level 3
$ —
1,349
673
—
Total
$
536
25,924
673
818
Carrying
Amount
$
699
9,241
1,024
December 31, 2016
Fair Value
Level 1
$ —
—
—
Level 2
$ 699
7,482
732
Level 3
$ —
1,670
—
Total
$ 699
9,152
732
Carrying
Amount
$
29
8,959
1,021
December 31, 2015
Fair Value
Level 1
$ —
—
—
Level 2
$
29
7,767
818
Level 3
$ —
1,349
—
Total
$
29
9,116
818
Carrying
Amount
$ 7,033
205
December 31, 2016
Fair Value
Level 1
$ —
—
Level 2
$7,585
—
Level 3
$ —
215
Total
$7,585
215
Carrying
Amount
$
294
6,509
205
December 31, 2015
Fair Value
Level 1
$ —
—
—
Level 2
$ 294
7,069
—
Level 3
$ —
—
213
Total
$ 294
7,069
213
Carrying
Amount
$ 2,580
184
December 31, 2016
Fair Value
Level 1
$ —
—
Level 2
$2,794
—
Level 3
$ —
192
Total
$2,794
192
Table of Contents
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)
Long-term debt to financing trusts
BGE
Short-term liabilities
Long-term debt (including amounts due within one year) (a)
Long-term debt to financing trusts (b)
Short-term liabilities
Long-term debt (including amounts due within one year) (a)
Long-term debt to financing trusts (b)
PHI
Successor
Short-term liabilities
Long-term debt (including amounts due within one year) (a)
Predecessor
Short-term liabilities
Long-term debt (including amounts due within one year) (a)
Preferred stock
Pepco
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)
411
Carrying
Amount
$ 2,580
184
December 31, 2015
Fair Value
Level 1
$ —
—
Level 2
$2,786
—
Level 3
$ —
195
Total
$2,786
195
Carrying
Amount
$
45
2,322
252
December 31, 2016
Fair Value
Level 1
$ —
—
—
Level 2
$
45
2,467
—
Level 3
$ —
—
260
Total
$
45
2,467
260
Carrying
Amount
$
213
1,858
252
December 31, 2015
Fair Value
Level 1
$
3
—
—
Level 2
$ 210
2,044
—
Level 3
$ —
—
264
Total
$ 213
2,044
264
Carrying
Amount
$
522
5,898
Carrying
Amount
$
958
5,279
183
December 31, 2016
Fair Value
Level 1
$ —
—
Level 2
$ 522
5,520
Level 3
$ —
289
Total
$ 522
5,809
December 31, 2015
Fair Value
Level 1
$ —
—
—
Level 2
$ 958
5,231
—
Level 3
$ —
586
183
Total
$ 958
5,817
183
Carrying
Amount
$
23
2,349
Carrying
Amount
$
64
2,351
December 31, 2016
Fair Value
Level 1
$ —
—
Level 2
$
23
2,788
Level 3
$ —
8
Total
$
23
2,796
December 31, 2015
Fair Value
Level 1
$ —
—
Level 2
$
64
2,673
Level 3
$ —
—
Total
$
64
2,673
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)
Short-term liabilities
Long-term debt (including amounts due within one year) (a)
ACE
Long-term debt (including amounts due within one year) (a)
Short-term liabilities
Long-term debt (including amounts due within one year) (a)
Carrying
Amount
$ 1,340
December 31, 2016
Fair Value
Level 1
$ —
Level 2
$1,383
Level 3
$ —
Total
$1,383
Carrying
Amount
105
$
1,265
December 31, 2015
Fair Value
Level 1
$ —
—
Level 2
$ 105
1,185
Level 3
$ —
103
Total
$ 105
1,288
Carrying
Amount
$ 1,155
December 31, 2016
Fair Value
Level 1
$ —
Level 2
$1,007
Level 3
$ 280
Total
$1,287
Carrying
Amount
$
5
1,201
December 31, 2015
Fair Value
Level 1
$ —
—
Level 2
$
5
1,044
Level 3
$ —
280
Total
$
5
1,324
(a)
(b)
Includes unamortized debt issuance costs, which are not fair valued, of $200 million, $64 million, $46 million, $15 million, $15 million, $2 million, $30 million, $11 million,
and $6 million for Exelon, Generation, ComEd, PECO, BGE, PHI, Pepco, DPL, and ACE respectively, as of December 31, 2016. Includes unamortized debt issuance
costs, which are not fair valued, of $180 million, $70 million, $38 million, $15 million, $9 million, $49 million, $31 million, $10 million, and $6 million for Exelon, Generation,
ComEd, PECO, BGE, PHI, Pepco, DPL, and ACE respectively, as of December 31, 2015.
Includes unamortized debt issuance costs which are not fair valued of $7 million, $1 million and $6 million for Exelon, ComEd and BGE, respectively, as of December 31,
2016 and December 31, 2015.
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 bond or note. Due to low trading volume of private placement debt,
412
Table of Contents
Combined Notes to Consolidated Financial Statements—(Continued)
(Dollars in millions, except per share data unless otherwise noted)
qualitative factors such as market conditions, low volume of investors and investor demand, this debt is classified as Level 3. The fair value of
Exelon’s equity units (Level 1) are valued based on publicly traded securities issued by Exelon.
The fair value of Generation’s, Pepco’s and PHI’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 project 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 project 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 and 2025 as of December 31, 2016 and 2015, respectively. See Note 24—
Commitments and Contingencies for additional information regarding the change in estimated settlement date.
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.
Preferred Stock . The fair value of these securities is determined based on the carrying value of the shares per the Subscription Agreement
between PHI and Exelon. See Note 19—Mezzanine Equity for further details.
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.
413
Table of Contents
Combined Notes to Consolidated Financial Statements—(Continued)
(Dollars in millions, except per share data unless otherwise noted)
•
•
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.
Transfers in and out of levels are recognized as of the end of the reporting period when the transfer occurred. Given derivatives categorized
within Level 1 are valued using exchange-based quoted prices within observable periods, transfers between Level 2 and Level 1 were not material.
Additionally, there were no significant transfers between Level 1 and Level 2 during the year ended December 31, 2016 for cash equivalents, nuclear
decommissioning trust fund investments, pledged assets for Zion Station decommissioning, Rabbi trust investments, and deferred compensation
obligations. For derivative contracts, transfers into Level 2 from Level 3 generally occur when the contract tenor becomes more observable and due
to changes in market liquidity or assumptions for certain commodity contracts.
Generation and Exelon
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. See Note 1—Significant Accounting Policies for additional information.
414
Table of Contents
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 on Exelon’s and Generation’s Consolidated Balance
Sheets on a recurring basis and their level within the fair value hierarchy as of December 31, 2016 and 2015:
As of December 31, 2016
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)
Fixed income subtotal
Middle market lending
Private equity
Real estate
NDT fund investments subtotal (d)
Pledged assets for Zion Station decommissioning
110
3,551
—
1,291
—
—
—
1,291
—
—
—
4,952
Generation
Exelon
Level 1 Level 2 Level 3
Not
subject to
leveling
Total
Level 1 Level 2 Level 3
Not
subject to
leveling
Total
$
39 $ — $ — $
— $
39 $
373 $ — $ — $
— $
373
19
452
—
—
—
2,011
129
6,014
110
3,551
19
452
—
—
—
2,011
129
6,014
1,554
29
37
264
59
1,943
—
—
—
2,414
250
—
—
—
—
250
427
—
—
677
—
—
—
—
493
493
71
148
326
3,049
1,804
1,320
37
264
552
3,977
498
148
326
11,092
—
1,291
—
—
—
1,291
—
—
—
4,952
1,554
29
37
264
59
1,943
—
—
—
2,414
250
—
—
—
—
250
427
—
—
677
—
—
—
—
493
493
71
148
326
3,049
1,804
1,320
37
264
552
3,977
498
148
326
11,092
—
—
—
64
11
2
17
83
Cash equivalents
Equities
Fixed Income—U.S. Treasury and agencies
Middle market lending
11
—
16
—
—
2
1
—
—
—
—
19
—
—
—
64
11
2
17
83
11
—
16
—
—
2
1
—
—
—
—
19
Pledged assets for Zion Station
decommissioning subtotal (e)
Rabbi trust investments
Cash equivalents
Mutual funds
Fixed income
Life insurance contracts
Rabbi trust investments subtotal
Commodity derivative assets
Economic hedges
Proprietary trading
Effect of netting and allocation of
collateral (f)
Commodity derivative assets subtotal
Interest rate and foreign currency derivative assets
Derivatives designated as hedging instruments
Economic hedges
Proprietary trading
Effect of netting and allocation of collateral
Interest rate and foreign currency derivative assets
subtotal
Other investments
Total assets
27
3
19
64
113
27
3
19
64
113
2
19
—
—
21
—
—
—
18
18
—
—
—
—
—
—
—
—
—
—
2
19
—
18
39
74
50
—
—
124
—
—
16
64
80
—
—
—
20
20
—
—
—
—
—
74
50
16
84
224
1,356
3
2,505
50
1,229
23
—
—
5,090
76
1,358
3
2,505
50
1,229
23
—
—
5,092
76
(1,162)
197
(2,142)
413
(481)
771
—
—
(3,785)
1,381
(1,164)
197
(2,142)
413
(481)
771
—
—
(3,787)
1,381
—
—
3
(2)
—
28
2
(19)
—
—
—
—
—
—
—
—
—
28
5
(21)
—
—
3
(2)
16
28
2
(19)
—
—
—
—
—
—
—
—
16
28
5
(21)
1
—
5,237
11
—
2,859
—
42
1,509
—
—
3,113
12
42
12,718
1
—
5,674
27
—
2,937
—
42
1,529
—
—
3,113
28
42
13,253
415
Table of Contents
Combined Notes to Consolidated Financial Statements—(Continued)
(Dollars in millions, except per share data unless otherwise noted)
As of December 31, 2016
Liabilities
Commodity derivative liabilities
Economic hedges
Proprietary trading
Effect of netting and allocation of
collateral (f)
Commodity derivative liabilities subtotal
Interest rate and foreign currency derivative liabilities
Derivatives designated as hedging instruments
Economic hedges
Proprietary trading
Effect of netting and allocation of collateral
Interest rate and foreign currency derivative liabilities
subtotal
Deferred compensation obligation
Total liabilities
Total net assets
Generation
Exelon
Level 1 Level 2 Level 3
Not
subject to
leveling Total
Level 1 Level 2 Level 3
Not
subject to
leveling Total
(1,267) (2,378)
(50)
(3)
(794)
(26)
1,233 2,339
(89)
(37)
542
(278)
— (4,439) (1,267) (2,378) (1,052)
(26)
(3)
—
(50)
(79)
— (4,697)
(79)
—
— 4,114 1,233 2,339
(89)
—
(404)
(37)
542
(536)
— 4,114
(662)
—
—
—
(10) —
(21) —
(4) — —
19 —
4
—
—
—
—
(10) —
(21) —
(10) —
(21) —
(4) — —
19 —
4
(4)
23
—
—
(37)
(12) —
(34) —
(278)
$ 5,200 $ 2,724 $ 1,231 $
(135)
416
—
—
—
(12) —
(34) —
(37)
(136) —
(237)
3,113 $ 12,268 $ 5,637 $ 2,700 $
(536)
993 $
(450)
(12) —
—
—
—
—
(10)
(21)
(4)
23
—
(12)
(136)
(810)
3,113 $ 12,443
—
Table of Contents
Combined Notes to Consolidated Financial Statements—(Continued)
(Dollars in millions, except per share data unless otherwise noted)
As of December 31, 2015
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)
Fixed income subtotal
Middle market lending
Private equity
Real estate
Other
Nuclear decommissioning trust fund
investments subtotal (d)
Pledged assets for Zion Station decommissioning
Cash equivalents
Equities
Fixed income
U.S. Treasury and agencies
Corporate debt
Other
Fixed income subtotal
Middle market lending
Pledged assets for Zion Station
decommissioning subtotal (e)
Rabbi trust investments
Mutual funds
Life insurance contracts
Rabbi trust investments subtotal
Commodity derivative assets
Economic hedges
Proprietary trading
Effect of netting and allocation of collateral (f)
Commodity derivative assets subtotal
Interest rate and foreign currency derivative assets
Derivatives designated as hedging instruments
Economic hedges
Proprietary trading
Effect of netting and allocation of collateral
Interest rate and foreign currency derivative assets
subtotal
Other investments
Total assets
Generation
Exelon
Level 1 Level 2 Level 3
Not
subject to
leveling
Total
Level 1 Level 2 Level 3
Not
subject to
leveling
Total
$
104 $ — $ — $
— $
104 $ 5,766 $ — $ — $
— $ 5,766
219
3,008
92
—
—
—
—
1,894
311
4,902
219
3,008
92
—
—
—
—
1,894
311
4,902
—
1,323
—
—
—
1,323
—
—
—
—
1,824
15
61
326
147
2,373
—
—
—
—
242
—
—
—
—
242
428
—
—
—
—
—
—
—
390
390
—
125
35
216
2,066
1,338
61
326
537
4,328
428
125
35
216
—
1,323
—
—
—
1,323
—
—
—
—
1,824
15
61
326
147
2,373
—
—
—
—
242
—
—
—
—
242
428
—
—
—
—
—
—
—
390
390
—
125
35
216
2,066
1,338
61
326
537
4,328
428
125
35
216
4,550
2,465
670
2,660
10,345
4,550
2,465
670
2,660
10,345
—
1
17
5
—
—
6
—
—
6
—
2
46
1
49
—
—
—
—
—
22
—
—
—
—
—
—
105
17
6
—
1
17
5
—
—
8
46
1
55
127
6
—
—
6
—
2
46
1
49
—
—
—
—
—
22
—
—
—
—
—
—
105
17
6
8
46
1
55
127
7
71
22
105
205
7
71
22
105
205
17
—
17
—
13
13
—
—
—
—
—
—
17
13
30
48
—
48
—
36
36
—
—
—
1,922
36
(1,964)
(6)
3,467
64
(2,629)
902
1,707
30
(564)
1,173
—
—
—
—
7,096
130
(5,157)
2,069
1,922
36
(1,964)
(6)
3,467
64
(2,629)
902
1,707
30
(564)
1,173
—
—
10
(3)
—
20
5
(3)
—
—
—
—
—
—
—
—
—
20
15
(6)
—
—
10
(3)
25
20
5
(3)
—
—
—
—
—
—
—
48
36
84
—
—
—
—
7,096
130
(5,157)
2,069
—
—
—
—
25
20
15
(6)
7
—
4,679
22
—
3,473
—
33
1,898
—
—
2,765
29
33
12,815
7
—
10,372
47
—
3,521
—
33
1,898
—
—
2,765
54
33
18,556
417
Table of Contents
Combined Notes to Consolidated Financial Statements—(Continued)
(Dollars in millions, except per share data unless otherwise noted)
As of December 31, 2015
Liabilities
Commodity derivative liabilities
Economic hedges
Proprietary trading
Effect of netting and allocation of
collateral (f)
Commodity derivative liabilities subtotal
Interest rate and foreign currency derivative liabilities
Derivatives designated as hedging instruments
Economic hedges
Proprietary trading
Effect of netting and allocation of collateral
Interest rate and foreign currency derivative liabilities
subtotal
Deferred compensation obligation
Total liabilities
Total net assets
Generation
Exelon
Level 1 Level 2 Level 3
Not
subject to
leveling Total
Level 1 Level 2 Level 3
Not
subject to
leveling Total
(2,382) (3,348)
(57)
(33)
(850)
(37)
2,440 3,186
(219)
25
765
(122)
— (6,580) (2,382) (3,348) (1,097)
(37)
(33)
—
(127)
(57)
— (6,827)
(127)
—
— 6,391 2,440 3,186
(219)
—
(316)
25
765
(369)
— 6,391
(563)
—
—
—
(16) —
(3) —
(12) — —
3 —
12
—
—
—
—
(16) —
(3) —
(16) —
(3) —
(12) — —
3 —
12
(12)
15
—
—
25
(16) —
(30) —
(122)
$ 4,704 $ 3,208 $ 1,776 $
(265)
—
—
—
(16) —
(99) —
(369)
2,765 $ 12,453 $ 10,397 $ 3,187 $ 1,529 $
(16) —
(30) —
25
(334)
(362)
—
—
—
—
(16)
(3)
(12)
15
—
—
—
(16)
(99)
(678)
2,765 $ 17,878
(b)
(a) Generation excludes cash of $252 million and $329 million at December 31, 2016 and 2015 and restricted cash of $157 million and $121 million at December 31, 2016
and 2015. Exelon excludes cash of $360 million and $763 million at December 31, 2016 and 2015 and restricted cash of $180 million and $178 million at December 31,
2016 and 2015 and includes long term restricted cash of $25 million at December 31, 2016, which is reported in other deferred debits on the balance sheet.
Includes $29 million and $52 million of cash received from outstanding repurchase agreements at December 31, 2016 and 2015, respectively, and is offset by an
obligation to repay upon settlement of the agreement as discussed in (d) below.
Includes derivative instruments of $(2) million and $(8) million, which have a total notional amount of $933 million and $1,236 million at December 31, 2016 and 2015,
respectively. The notional principal amounts for these instruments provide one measure of the transaction volume outstanding as of the fiscal years ended and do not
represent the amount of the company’s exposure to credit or market loss.
(c)
(d) Excludes net liabilities of $(31) million and $(3) million at December 31, 2016 and 2015, 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 and $1 million at December 31, 2016 and 2015, respectively. These items consist of receivables related to pending securities
sales, interest and dividend receivables, and payables related to pending securities purchases.
(f) Collateral posted to/(received from) counterparties totaled $71 million, $197 million and $61 million allocated to Level 1, Level 2 and Level 3 mark-to-market derivatives,
respectively, as of December 31, 2016. Collateral posted to/(received from) counterparties totaled $476 million, $557 million and $201 million allocated to Level 1, Level 2
and Level 3 mark-to-market derivatives, respectively, as of December 31, 2015.
418
Table of Contents
ComEd, PECO and BGE
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 on 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, 2016 and 2015:
As of December 31, 2016
Assets
Cash equivalents (a)
Rabbi trust investments
Mutual funds
Life insurance contracts
Rabbi trust investments subtotal
Total assets
Liabilities
Deferred compensation obligation
Mark-to-market derivative liabilities (b)
Total liabilities
Total net assets (liabilities)
As of December 31, 2015
Assets
Cash equivalents (a)
Rabbi trust investments
Mutual funds
Life insurance contracts
Total assets
Liabilities
Deferred compensation obligation
Mark-to-market derivative liabilities (b)
Total liabilities
Total net assets (liabilities)
Level 1 Level 2 Level 3 Total Level 1 Level 2 Level 3 Total Level 1 Level 2 Level 3 Total
ComEd
PECO
BGE
$
20 $ — $ — $ 20 $
45 $ — $ — $ 45 $
36 $ — $ — $ 36
— — — —
— — — — —
7
— — — —
52
20
20 — —
7 — —
7
4
10 — 10 — — — —
10 — 17
4
40 — — 40
10 — 62
4 — —
4 — —
(8) —
—
— —
(8)
—
(8) $ (258) $ (246) $
20 $
$
(4)
(258) (258) — — — — — — — —
(4) —
(258) (266) —
(4)
(4) $ — $ 36
52 $
(11) — (11) —
40 $
(11) — (11) —
(1) $ — $ 51 $
(8) —
(4) —
PECO
Level 1 Level 2 Level 3 Total Level 1 Level 2 Level 3 Total Level 1 Level 2 Level 3 Total
ComEd
BGE
$
29 $ — $ — $ 29 $ 271 $ — $ — $ 271 $
25 $ — $ — $ 25
Rabbi trust investments subtotal — — — —
29
— — — —
— — — — —
8
279
29 — —
8 — —
8
4
12 — 12 — — — —
12 — 20
4
29 — — 29
12 — 291
4 — —
4 — —
(8) —
—
— —
(8)
—
(8) $ (247) $ (226) $ 279 $ — $ — $ 279 $
29 $
$
(4)
(247) (247) — — — — — — — —
(4) —
(4)
(247) (255) —
(4) $ — $ 25
(12) — (12) —
29 $
(12) — (12) —
(4) —
(8) —
(a) ComEd excludes cash of $36 million and $38 million at December 31, 2016 and 2015 and restricted cash of $2 million and $2 million at December 31, 2016 and 2015.
PECO excludes cash of $22 million and $27 million at December 31, 2016 and 2015. BGE excludes cash of $13 million and $6 million at December 31, 2016 and 2015
and restricted cash of less than $1 million and $2 million at December 31, 2016 and 2015 and includes long term restricted cash of $2 million at December 31, 2016,
which is reported in other deferred debits on the balance sheet.
419
Table of Contents
Combined Notes to Consolidated Financial Statements—(Continued)
(Dollars in millions, except per share data unless otherwise noted)
(b) The Level 3 balance consists of the current and noncurrent liability of $19 million and $239 million, respectively, at December 31, 2016, and $23 million and $224 million,
respectively, at December 31, 2015, related to floating-to-fixed energy swap contracts with unaffiliated suppliers.
PHI, Pepco, DPL and ACE
The following tables present assets and liabilities measured and recorded at fair value on 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, 2016 and December 31, 2015:
PHI
Assets
Cash equivalents (a)
Mark-to-market derivative assets (b)(c)
Effect of netting and allocation of collateral
Mark-to-market derivative assets subtotal
Rabbi trust investments
Cash equivalents
Fixed income
Life insurance contracts
Rabbi trust investments subtotal
Total assets
Liabilities
Deferred compensation obligation
Mark-to-market derivative liabilities (b)
Effect of netting and allocation of collateral
Mark-to-market derivative liabilities subtotal
Total liabilities
Total net assets
Successor
As of December 31, 2016
Predecessor
As of December 31, 2015
Level 1 Level 2 Level 3 Total Level 1 Level 2 Level 3 Total
$ 217 $ — $ — $217
2
2 — —
(2)
(2) — —
— — — —
42 $ — $ — $ 42
$
— —
18 18
— — — —
18 18
— —
73 — — 73
16 — 16
20 42
22
20 131
38
20 348
38
—
—
73
290
12 — — 12
15 — 15
19 46
27
19 73
42
37 133
42
—
—
12
54
—
(28) — (28)
— — — —
— — — —
— — — —
(28) — (28)
—
20 $320
10 $
$ 290 $
—
(30) — (30)
(2)
(2) — —
2 — —
2
— — — —
(30) — (30)
—
37 $103
12 $
54 $
$
420
Table of Contents
Combined Notes to Consolidated Financial Statements—(Continued)
(Dollars in millions, except per share data unless otherwise noted)
DPL
Level 1 Level 2 Level 3 Total Level 1 Level 2 Level 3 Total Level 1 Level 2 Level 3 Total
Pepco
ACE
$
33 $ — $ — $ 33 $
42 $ — $ — $ 42 $ 130 $ — $ — $ 130
— — — —
2 — —
2 — — — —
(2) — — — —
(2) — —
— — — —
— — — — — — — — — — — —
43 — — 43 — — — — — — — —
16 — 16 — — — — — — — —
19 41 — — — — — — — —
22
19 100 — — — — — — — —
38
130 — — 130
19 133
38
42 — — 42
—
—
43
76
—
—
76 $
$
(5) —
(5) —
33 $
(5) —
(5) —
42 $
19 $ 128 $
(1) —
(1) — — — —
(1) — — — —
(1) —
(1) $ — $ 41 $ 130 $ — $ — $ 130
DPL
Level 1 Level 2 Level 3 Total Level 1 Level 2 Level 3 Total Level 1 Level 2 Level 3 Total
Pepco
ACE
$
2 $ — $ — $
2 $ — $ — $ — $ — $
30 $ — $ — $ 30
As of December 31, 2016
Assets
Cash equivalents (a)
Mark-to-market derivative assets (b)
Effect of netting and allocation of collateral
Mark-to-market derivative assets subtotal
Rabbi trust investments
Cash equivalents
Fixed income
Life insurance contracts
Rabbi trust investments subtotal
Total assets
Liabilities
Deferred compensation obligation
Total liabilities
Total net assets (liabilities)
As of December 31, 2015
Assets
Cash equivalents (a)
Rabbi trust investments
Cash equivalents
Fixed income
Life insurance contracts
Rabbi trust investments subtotal
11 — — 11 — — — — — — — —
15 — 15 — — — — — — — —
19 42 — — — — — — — —
23
19 68 — — — — — — — —
38
30 — — 30
19 70 — — — —
38
—
—
11
13
Total assets
Liabilities
(1) — — — —
Deferred compensation obligation
Mark-to-market derivative liabilities (b)
(2) — — — —
Effect of netting and allocation of collateral
2 — — — —
Mark-to-market derivative liabilities subtotal — — — — — — — — — — — —
(1) — — — —
Total liabilities
30 $ — $ — $ 30
Total net assets (liabilities)
—
— — — —
— — — —
(1) —
(2) — —
2 — —
(6) —
19 $ 64 $ — $
(1) —
(1) $ — $ (1) $
(6) —
32 $
—
13 $
$
(6) —
(6) —
(a) PHI excludes cash of $19 million and $16 million at December 31, 2016 and 2015 and includes long term restricted cash of $23 million and $18 million at December 31,
2016 and 2015 which is reported in other deferred debits on the balance sheet. Pepco excludes cash of $9 million and $5 million at December 31, 2016 and 2015. DPL
excludes cash of $4 million and
421
Table of Contents
Combined Notes to Consolidated Financial Statements—(Continued)
(Dollars in millions, except per share data unless otherwise noted)
$5 million at December 31, 2016 and 2015. ACE excludes cash of $3 million and $3 million at December 31, 2016 and 2015 and includes long term restricted cash of
$23 million and $18 million at December 31, 2016 and 2015 which is reported in other deferred debits on the balance sheet.
(b) Represents natural gas futures purchased by DPL as part of a natural gas hedging program approved by the DPSC.
(c) Prior to the PHI Merger, PHI recorded derivative assets for the embedded call and redemption features on the shares of Preferred Stock outstanding as of December 31,
2015. See Note 19—Mezzanine Equity for additional information. As a result of the PHI Merger, the PHI preferred stock derivative was reduced to zero as of March 23,
2016.
The following tables present the fair value reconciliation of Level 3 assets and liabilities measured at fair value on a recurring basis during the
year ended December 31, 2016 and 2015:
Generation
ComEd
Successor
PHI (c)
Exelon
For the year ended
December 31, 2016
Balance as of January 1, 2016
Included due to merger
Total realized / unrealized gains (losses)
Included in net income
Included in noncurrent payables to affiliates
Included in regulatory assets/liabilities
Change in collateral
Purchases, sales, issuances and settlements
Purchases
Sales
Issuances
Settlements
Transfers into Level 3
Transfers out of Level 3
Balance as of December 31, 2016
The amount of total gains (losses) included in income attributed to
the change in unrealized gains (losses) related to assets and
liabilities as of December 31, 2016
$
$
$
670 $
—
7
16
—
—
143
(1)
—
(144)
—
(14)
677 $
NDT Fund
Investments
Pledged
Assets for
Zion Station
Decommissioning
Mark-to-
Market
Derivatives
1,051
—
22 $
—
Other
Investments
Total
Generation
Mark-to-
Market
Derivatives (a)
Life
Insurance
Contracts
$
33 $
—
1,776 $
—
—
—
—
—
2
(5)
—
—
—
—
19 $
(568) (b)
—
—
(141)
342(d)
(9)
—
—
1
(183)
493
$
1
—
—
—
7
—
—
—
1
—
42 $
(560)
16
—
(141)
494
(15)
—
(144)
2
(197)
1,231 $
Eliminated in
Consolidation Total
— $ 1,529
20
—
— $
20
3
—
—
—
—
—
—
(3)
—
—
—
20 $
—
(557)
(16) —
5
16
(141)
—
494
—
(15)
—
(3)
—
(144)
—
2
—
—
(197)
— $ 993
(247) $
—
—
—
(11)
—
—
—
—
—
—
—
(258) $
5 $
— $
109
$
— $
114 $
— $
2 $
— $ 116
422
Table of Contents
Combined Notes to Consolidated Financial Statements—(Continued)
(Dollars in millions, except per share data unless otherwise noted)
Generation
ComEd
Exelon
For the year ended
December 31, 2015
Balance as of January 1, 2015
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
Settlements
Transfers into Level 3
Transfers out of Level 3
Balance as of December 31, 2015
The amount of total gains included in income attributed to the change in
unrealized gains (losses) related to assets and liabilities held as of
December 31, 2015
NDT Fund
Investments
Pledged
Assets for
Zion Station
Decommissioning
Mark-to-
Market
Derivatives (d)
1,050
Other
Investments
Total
Generation
Mark-to-
Market
Derivatives (a)
Eliminated in
Consolidation Total
— $ 1,501
$
605 $
50 $
$
3 $
1,708 $
(207) $
4
18
—
—
—
146
(8)
(95)
4
(4)
670 $
—
—
(2)
—
—
2
(28)
—
—
—
22 $
22(b)
—
—
—
29
144
(25)
—
80
(249)
1,051
$
1
—
—
—
—
30
—
—
—
(1)
33 $
27
18
(2)
—
29
322
(61)
(95)
84
(254)
1,776 $
—
—
—
(40)
—
—
—
—
—
—
(247) $
27
—
(18) —
(2)
—
(22)
18
29
—
322
—
(61)
—
(95)
—
84
—
—
(254)
— $ 1,529
2 $
— $
856
$
— $
858 $
— $
— $ 858
$
$
(a)
(b)
Includes $29 million of decreases in fair value and an increase for realized losses due to settlements of $18 million recorded in purchased power expense associated with
floating-to-fixed energy swap contracts with unaffiliated suppliers for the year ended December 31, 2016. Includes $55 million of decreases in fair value and a reduction for
realized losses due to settlements of $(15) million for the year ended December 31, 2015.
Includes a reduction for the reclassification of $677 million and $834 million of realized gains due to the settlement of derivative contracts for the years ended
December 31, 2016 and 2015, respectively.
(c) Successor period represents activity from March 24, 2016 to December 31, 2016. See tables below for PHI’s predecessor periods, as well as activity for Pepco and DPL
for the year ended December 31, 2016.
Includes $168 million of fair value from contracts acquired as a result of portfolio acquisitions.
(d)
PHI
Beginning Balance
Total realized / unrealized gains (losses)
Included in net income
Purchases, sales, issuances and settlements
Issuances
Settlements
Ending Balance
The amount of total gains included in income attributed to the change in
unrealized gains (losses) related to assets and liabilities for the period
Predecessor
Successor
March 24,
2016 to
December 31,
2016
Life
Insurance
Contracts
January 1, 2016 to
March 23, 2016
Life
Insurance
Contracts
Stock
Preferred
December 31, 2015
Preferred
Stock
Life
Insurance
Contracts
19
$
20
$
18 $
19 $
3 $
3
(3)
—
20
(18)
1
15
—
—
$ — $
— —
— —
18 $
20 $
5
(3)
(2)
19
2
$ — $
1 $
15 $
3
$
$
423
Table of Contents
Combined Notes to Consolidated Financial Statements—(Continued)
(Dollars in millions, except per share data unless otherwise noted)
Balance as of December 31
Total realized / unrealized gains (losses)
Included in net income
Purchases, sales, issuances and settlements
Issuances
Settlements
Balance as of December 31
The amount of total gains included in income
attributed to the change in unrealized gains
related to assets and liabilities for the period
December 31, 2016
December 31, 2015
Pepco
Life Insurance
Contracts
DPL
Life Insurance
Contracts
Pepco
Life Insurance
Contracts
DPL
Life Insurance
Contracts
$
$
$
19
3
(3)
—
19
3
$
$
$
—
—
—
—
—
—
$
$
$
18
5
(3)
(1)
19
3
$
$
$
1
—
—
(1)
—
—
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, 2016 and 2015:
Total gains (losses) included in net income for the year
ended December 31, 2016
Change in the unrealized gains (losses) relating to
assets and liabilities held for the year ended
December 31, 2016
Total gains (losses) included in net income for the year
ended December 31, 2015
Change in the unrealized gains (losses) relating to
assets and liabilities held for the year ended
December 31, 2015
Operating
Revenues
$
$
(477)
154
Generation
Purchased
Power and
Fuel
Other,
net (a)
Operating
Revenues
Exelon
Purchased
Power and
Fuel
Other,
net (a)
$
$
(91)
(45)
$
$
7
5
$
$
(477)
154
$
$
(91)
$ 10
(45)
$
7
Operating
Revenues
Generation
Purchased
Power and
Fuel
Other,
net (a)
Operating
Revenues
Exelon
Purchased
Power and
Fuel
$
$
$
$
67
858
424
(45)
(2)
$
$
4
2
$
$
67
858
$
$
(45)
(2)
Other,
net (a)
$
$
4
2
Table of Contents
Combined Notes to Consolidated Financial Statements—(Continued)
(Dollars in millions, except per share data unless otherwise noted)
Total (losses) gains included in net income
Change in the unrealized gains (losses) relating to assets and
liabilities held
Successor
PHI
March 24,
2016 to
December 31,
2016
Other, net
$
3
2
Predecessor
PHI
Pepco
January 1,
2016 to
March 23,
2016
December 31,
2015
December 31,
2016
December 31,
2015
Other, net
$
(17) $
20 $
Other, net
3 $
1
18
3
5
3
(a) Other, net activity consists of realized and unrealized gains (losses) included in income for the NDT funds held by Generation and the life insurance contracts held by
Pepco.
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 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.
Preferred Stock Derivative (PHI). In connection with entering into the PHI Merger Agreement, as further described in Note 19—Mezzanine
Equity, PHI entered into a Subscription Agreement with Exelon dated April 29, 2014, pursuant to which PHI issued to Exelon shares of Preferred
stock. The Preferred stock contained embedded features requiring separate accounting consideration to reflect the potential value to PHI that any
issued and outstanding Preferred stock could be called and redeemed at a nominal par value upon a termination of the merger agreement under
certain circumstances due to the failure to obtain required regulatory approvals. The embedded call and redemption features on the shares of the
Preferred stock in the event of such a termination were separately accounted for as derivatives. These Preferred stock derivatives were valued
quarterly using quantitative and qualitative factors, including management’s assessment of the likelihood of a Regulatory Termination and therefore,
were categorized in Level 3 in the fair value hierarchy. As a result of the PHI Merger, the PHI Preferred stock derivative was reduced to zero as of
March 23, 2016. The write-off was charged to Other, net on the PHI Consolidated Statement of Operations and Comprehensive Income.
Nuclear Decommissioning Trust 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, Fixed
Income and Other. 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
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Table of Contents
Combined Notes to Consolidated Financial Statements—(Continued)
(Dollars in millions, except per share data unless otherwise noted)
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 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
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Table of Contents
Combined Notes to Consolidated Financial Statements—(Continued)
(Dollars in millions, except per share data unless otherwise noted)
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. 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 not highly observable.
As of December 31, 2016, Generation has outstanding commitments to invest in middle market lending, private equity investments and real
estate investments of approximately $284 million, $65 million, and $205 million, respectively. These commitments will be funded by Generation’s
existing nuclear decommissioning trust funds.
Concentrations of Credit Risk. Generation evaluated its NDT portfolios for the existence of significant concentrations of credit risk as of
December 31, 2016. 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, 2016, there were no significant concentrations (generally defined as greater than
10 percent) of risk in Generation’s NDT assets.
See Note 16—Asset Retirement Obligations for further discussion on the NDT fund investments.
Rabbi Trust Investments (Exelon, Generation, PECO, BGE, PHI, Pepco, DPL and ACE). The Rabbi trusts were established to hold assets
related to deferred compensation plans existing for certain active and retired members of Exelon’s executive management and directors. The Rabbi
trusts assets are included in investments in the Registrants’ Consolidated Balance Sheets and consist primarily of money market funds, mutual
funds, fixed income securities and life insurance policies. 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.
427
Table of Contents
Combined Notes to Consolidated Financial Statements—(Continued)
(Dollars in millions, except per share data unless otherwise noted)
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 predominately 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, which are typically designated as fair value hedges, 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. These interest rate derivatives are typically designated as cash flow hedges. 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 13—Derivative Financial Instruments for further discussion 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.
428
Table of Contents
Combined Notes to Consolidated Financial Statements—(Continued)
(Dollars in millions, except per share data unless otherwise noted)
Additional Information Regarding Level 3 Fair Value Measurements (Exelon, Generation, ComEd, PHI, Pepco and DPL)
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.
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. 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
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Table of Contents
Combined Notes to Consolidated Financial Statements—(Continued)
(Dollars in millions, except per share data unless otherwise noted)
market movements and not a change in the applied spread. The change in fair value associated with a change in the spread is generally immaterial.
An average spread calculated across all Level 3 power and gas delivery locations is approximately $2.65 and $0.34 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 13—Derivative Financial Instruments for more 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 table below discloses the significant inputs to the forward curve used to value these positions.
Type of trade
Mark-to-market derivatives—Economic hedges (Exelon and
Generation) (a)(c)
Fair Value at
December 31, 2016
435
$
Valuation
Technique
Discounted
Cash Flow
Mark-to-market derivatives—Proprietary trading (Exelon and
Generation) (a)(c)
Mark-to-market derivatives (Exelon and ComEd)
$
$
(3)
(258)
Option Model
Discounted
Cash Flow
Discounted
Cash Flow
Unobservable
Input
Forward power
price
Forward gas
price
Volatility
percentage
Forward power
price
Forward heat
rate (b)
Marketability
reserve
Renewable
factor
Range
$11 - $130
$1.72 - $9.20
8% - 173%
$19 - $79
8x - 9x
3% - 8%
89% - 121%
(a) The valuation techniques, unobservable inputs and ranges are the same for the asset and liability positions.
(b) Quoted forward natural gas rates are utilized to project the forward power curve for the delivery of energy at specified future dates. The natural gas curve is extrapolated
beyond its observable period to the end of the contract’s delivery.
(c) The fair values do not include cash collateral posted on level three positions of $61 million as of December 31, 2016.
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Table of Contents
Combined Notes to Consolidated Financial Statements—(Continued)
(Dollars in millions, except per share data unless otherwise noted)
Type of trade
Mark-to-market derivatives—Economic hedges (Exelon and
Generation) (a)(c)
Fair Value at
December 31, 2015
857
$
Valuation
Technique
Discounted
Cash Flow
Mark-to-market derivatives—
Proprietary trading (Exelon and Generation) (a)(c)
Mark-to-market derivatives (Exelon and ComEd)
$
$
(7)
(247)
Option Model
Discounted
Cash Flow
Discounted
Cash Flow
Unobservable
Input
Forward power
price
Forward gas
price
Volatility
percentage
Forward power
price
Forward heat
rate (b)
Marketability
reserve
Renewable
factor
Range
$11 - $88
$1.18 - $8.95
5% - 152%
$13 - $78
9x - 10x
3.5% - 7%
87% - 128%
(a) The valuation techniques, unobservable inputs and ranges are the same for the asset and liability positions.
(b) Quoted forward natural gas rates are utilized to project the forward power curve for the delivery of energy at specified future dates. The natural gas curve is extrapolated
beyond its observable period to the end of the contract’s delivery.
(c) The fair values do not include cash collateral posted on level three positions of $201 million as of December 31, 2015
The inputs listed above 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.
Nuclear Decommissioning Trust 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. Generation gains
an understanding of the fund managers’ inputs and assumptions used in preparing the valuations. Generation performed procedures to assess the
reasonableness of the valuations.
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Table of Contents
Combined Notes to Consolidated Financial Statements—(Continued)
(Dollars in millions, except per share data unless otherwise noted)
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. Exelon gains an
understanding of the types of inputs and assumptions used in preparing the valuations and performs procedures to assess the reasonableness of
the valuations.
13. Derivative Financial 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.
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 energy-related
products. The Registrants believe these instruments, which are classified as either economic hedges or non-derivatives, mitigate exposure to
fluctuations in commodity prices.
Derivative accounting 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 each period. 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 hedge and fair value hedge. For Generation, all derivative economic hedges
related to commodities are recorded at fair value through earnings for the combined company, referred to as economic hedges in the following
tables. The Registrants have applied the NPNS scope exception to certain derivative contracts for the forward sale of generation, power
procurement agreements, and natural gas supply agreements. Generation has also entered into bilateral long-term contractual obligations for sales
of energy to load-serving entities, including electric utilities, municipalities, electric cooperatives and retail load aggregators, as well as contractual
obligations to deliver energy to market participants who primarily focus on the resale of energy products for delivery. These non-derivative contracts
are accounted for primarily under the accrual method of accounting. 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.
Economic Hedging. The Registrants are exposed to commodity price risk primarily relating to changes in the market price of electricity, fossil
fuels, and other commodities 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. 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
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Combined Notes to Consolidated Financial Statements—(Continued)
(Dollars in millions, except per share data unless otherwise noted)
facilities, including power and gas sales, fuel and energy purchases, natural gas transportation and pipeline capacity agreements and other energy-
related products marketed and purchased. In order to manage these risks, Generation may enter into fixed-price derivative or non-derivative
contracts to hedge the variability in future cash flows from forecasted sales of energy and gas and purchases of fuel and energy. The objectives for
entering into such hedges include fixing the price for a portion of anticipated future electricity sales at a level that provides an acceptable return on
electric generation operations, fixing the price of a portion of anticipated fuel purchases for the operation of power plants, and fixing the price for a
portion of anticipated energy purchases to supply load-serving customers. The portion of forecasted transactions hedged may vary based upon
management’s policies and hedging objectives, the market, weather conditions, operational and other factors. 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.
In general, increases and decreases in forward market prices have a positive and negative impact, respectively, on Generation’s owned and
contracted generation positions that have not been hedged. Generation hedges commodity price risk on a ratable basis over three-year periods. As
of December 31, 2016, the proportion of expected generation hedged for the major reportable segments was 91%-94%, 56%-59% and 28%-31% for
2017, 2018, and 2019, 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.
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. 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 3—Regulatory Matters for additional
information.
PECO has contracts to procure electric supply that were executed through the competitive procurement process outlined in its PAPUC-
approved DSP Programs, which are further discussed in Note 3—Regulatory Matters. Based on Pennsylvania legislation and the DSP Programs
permitting PECO to recover its electric supply procurement costs from retail customers with no mark-up, PECO’s price risk related to electric supply
procurement is limited. PECO locked in fixed prices for a significant portion of its commodity price risk through full requirements contracts. PECO
has certain full requirements contracts that are considered derivatives and qualify for the NPNS scope exception under current derivative
authoritative guidance.
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 in order to achieve system supply
433
Table of Contents
Combined Notes to Consolidated Financial Statements—(Continued)
(Dollars in millions, except per share data unless otherwise noted)
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 2016 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 2016 PGC settlement, 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 25% 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 financial
position or results of operations 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. The administrative fee includes an
incremental cost component and a shareholder return component for commercial and industrial rate classes. BGE’s 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. All of 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 price risk related
to electric supply procurement is limited. Pepco locks in fixed prices for all of 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 costs. DPL
locks in fixed prices
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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 of its SOS requirements through full requirements contracts. DPL’s 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 versus the 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 fifty percent (50%) of estimated purchase requirements for each month, including estimated monthly
purchases for storage injections. The fifty percent (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 price risk related to electric supply procurement is limited. ACE locks in fixed prices for all of 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. Generation also enters into certain energy-related derivatives for proprietary trading purposes. Proprietary trading
includes all contracts entered into with the intent of benefiting from shifts or changes in market prices as opposed to those entered into with the intent
of hedging or managing risk. Proprietary trading activities are subject to limits established by Exelon’s RMC. The proprietary trading activities, which
included settled physical sales volumes of 6,179 GWh, 7,310 GWh and 10,571 GWh for the years ended December 31, 2016, 2015 and 2014, are a
complement to Generation’s energy marketing portfolio but represent a small portion of Generation’s revenue from energy marketing activities.
ComEd, PECO, BGE, PHI, Pepco, DPL and ACE do not enter into derivatives for proprietary trading purposes.
435
Table of Contents
Combined Notes to Consolidated Financial Statements—(Continued)
(Dollars in millions, except per share data unless otherwise noted)
Interest Rate and Foreign Exchange Risk (Exelon, Generation, ComEd, PECO, BGE and PHI)
The Registrants use a combination of fixed-rate and variable-rate debt to manage interest rate exposure. The Registrants utilize
fixed-to-floating interest rate swaps, which are typically designated as fair value hedges, as a means to manage their interest rate exposure. In
addition, the Registrants may utilize interest rate derivatives to lock in rate levels in anticipation of future financings, which are typically designated as
cash flow hedges. These strategies are employed to manage interest rate risks. At December 31, 2016, Exelon had $800 million of notional amounts
of fixed-to-floating hedges outstanding and Exelon and Generation had $659 million of notional amounts of floating-to-fixed hedges outstanding.
Assuming the fair value and cash flow interest rate hedges are 100% effective, a hypothetical 50 bps increase in the interest rates associated with
unhedged variable-rate debt (excluding Commercial Paper) and fixed-to-floating swaps would result in an approximately $7 million decrease in
Exelon Consolidated pre-tax income for the year ended December 31, 2016. 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 typically
designated as economic hedges. Below is a summary of the interest rate and foreign exchange hedge balances as of December 31, 2016:
Exelon
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
$
Generation
Economic
Hedges
Proprietary
Trading (a)
Collateral
and
Netting
(b)
Subtotal
— $
—
—
(7)
(3)
(10)
(10) $
17 $
11
28
(13)
(8)
(21)
7 $
4 $
1
5
(2)
(2)
(4)
1 $
(13) $
(8)
(21)
14
9
23
8 $
4
12
(8)
(4)
(12)
2 $ — $
Corporate Exelon
Derivatives
Designated
as Hedging
Instruments Total
8
— $
20
16
28
16
(8)
—
(4)
—
(12)
—
16
16 $
$
(a) Generation enters into interest rate derivative contracts to economically hedge risk associated with the interest rate component of commodity positions. The
characterization of the interest rate derivative contracts between the proprietary trading activity in the above table is driven by the corresponding characterization of the
underlying commodity position that gives rise to the interest rate exposure. Generation does not utilize proprietary trading interest rate derivatives with the objective of
benefiting from shifts or changes in market interest rates.
(b) Exelon and Generation net all available amounts allowed under the derivative accounting 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 accrued interest, 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.
436
Table of Contents
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, 2015:
Generation
Other
Exelon
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)
$
— $
—
—
(8)
(8)
(16)
(16) $
10 $
10
20
(2)
(1)
(3)
17 $
Derivatives
Designated
as Hedging
Instruments
$
Economic
Hedges
Proprietary
Trading (a)
Collateral
and
Netting (b) Subtotal
(5) $
(1)
(6)
11
15 $
14
29
(8)
10 $
5
15
(9)
Derivatives
Designated
as Hedging
Instruments Subtotal Total
15
— $ — $
39
25 $
25 $
54
25
25
(8)
— —
(3)
(12)
3 $
4
15
9 $
(8)
(16)
13 $
— —
— —
25 $
25 $
(8)
(16)
38
(a) Generation enters into interest rate derivative contracts to economically hedge risk associated with the interest rate component of commodity positions. The
characterization of the interest rate derivative contracts between the proprietary trading activity in the above table is driven by the corresponding characterization of the
underlying commodity position that gives rise to the interest rate exposure. Generation does not utilize proprietary trading interest rate derivatives with the objective of
benefiting from shifts or changes in market interest rates.
(b) Exelon and Generation net all available amounts allowed under the derivative accounting 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 accrued interest, 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.
437
Table of Contents
Combined Notes to Consolidated Financial Statements—(Continued)
(Dollars in millions, except per share data unless otherwise noted)
Fair Value Hedges . For derivative instruments that are designated and qualify 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 current earnings. Exelon includes the gain or loss
on the hedged items and the offsetting loss or gain on the related interest rate swaps in interest expense as follows:
Year Ended December 31,
Generation
Exelon
Income
Statement Location
Interest expense (a)
Interest expense
2016
2015
2014
Gain (Loss) on Swaps
$ — $ (1) $ (16) $ — $ — $
3 $ 14 $ 23 $ 14 $
$ (9) $
2016
2014
2015
Gain (Loss) on Borrowings
2
(1)
(a) For the years ended December 31, 2015 and 2014, the loss on Generation swaps included $(1) million and $(17) million realized in earnings, respectively, with an
immaterial amount and $4 million excluded from hedge effectiveness testing, respectively.
At December 31, 2016, Exelon had total outstanding fixed-to-floating fair value hedges related to interest rate swaps of $800 million, with a
derivative asset of $16 million. At December 31, 2015, Exelon had outstanding fixed-to-floating fair value hedges related to interest rate swaps of
$800 million, with a derivative asset of $25 million. During the years ended December 31, 2016 and 2015, the impact on the results of operations as
a result of ineffectiveness from fair value hedges was a $14 million gain and $17 million gain, respectively.
Cash Flow Hedges . During the second quarter of 2016, Exelon entered into $90 million of floating-to-fixed forward starting interest rate swaps
to manage a portion of the interest rate exposure associated with an anticipated debt issuance. The swaps were designated as cash flow hedges.
Exelon terminated the swaps during the third quarter of 2016 upon issuance of the debt. Exelon did not recognize a gain or loss as a result of the
termination.
During the first and second quarter of 2016, Exelon entered into $600 million and $100 million of floating-to-fixed forward starting interest rate
swaps, respectively, to manage a portion of the interest rate exposure associated with an anticipated debt issuance. The swaps were designated as
cash flow hedges. Exelon terminated the swaps during the second quarter of 2016 upon issuance of the debt. Exelon recognized a loss of $3 million
related to the swaps and $3 million of AOCI will be amortized into Other, net in Exelon’s Consolidated Statement of Operations and Comprehensive
Income over the term of the debt. See Note 14—Debt and Credit Agreements of the Combined Notes to Consolidated Financial Statements for
additional information.
During the first quarter of 2016, Exelon entered into a $100 million floating-to-fixed forward starting interest rate swaps to manage a portion of
the interest rate exposure associated with an anticipated debt issuance. The swap was designated as a cash flow hedge. Exelon terminated the
swap during the first quarter of 2016 upon issuance of the debt. Exelon did not recognize a gain or loss as a result of the termination of the swap and
an immaterial amount of AOCI will be amortized into Other, net in Exelon’s Consolidated Statement of Operations and Comprehensive Income over
the term of the debt.
During the third quarter of 2014, EGTP, a subsidiary of Generation, entered into a floating-to-fixed interest rate swap to manage a portion of its
interest rate exposure in connection with the long-term borrowing. See Note 14—Debt and Credit Agreements for additional information regarding
the financing. The swaps have a notional amount of $495 million as of December 31, 2016 and expire in 2019. The swap was designated as a cash
flow hedge in the fourth quarter of 2014. At December 31, 2016, the subsidiary had a $9 million derivative liability related to the swap.
438
Table of Contents
Combined Notes to Consolidated Financial Statements—(Continued)
(Dollars in millions, except per share data unless otherwise noted)
During the first quarter of 2014, EGR, a subsidiary of Generation, entered into floating-to-fixed interest rate swaps to manage a portion of its
interest rate exposure in connection with the long-term borrowings. See Note 14—Debt and Credit Agreements for additional information regarding
the financing. The swaps have a notional amount of $164 million as of December 31, 2016 and expire in 2020. The swaps are designated as cash
flow hedges. At December 31, 2016, the subsidiary had a $1 million derivative liability related to the swaps.
During the second quarter of 2002, PHI entered into treasury rate lock transactions in anticipation of the issuance of several series of fixed-rate
debt commencing in August 2002 to manage a portion of its interest rate exposure. Upon issuance of the fixed-rate debt in August 2002, the treasury
rate locks were terminated at a loss and the loss was deferred in AOCI. As a result of the PHI Merger, the remaining unamortized deferred loss
recorded in AOCI was adjusted to zero through application of purchase accounting.
During the years ended December 31, 2016 and 2015, the impact on the results of operations as a result of ineffectiveness from cash flow
hedges in continuing designated hedge relationships was immaterial.
Economic Hedges. During the third quarter of 2011, Sacramento PV Energy, a subsidiary of Generation, entered into floating-to-fixed interest
rate swaps to manage a portion of its interest rate exposure in connection with the long-term borrowings. See Note 14—Debt and Credit Agreements
for additional information regarding the financing. During the first quarter of 2016, upon the termination of debt, Generation terminated the swaps.
The total notional amount of the swaps were $25 million. No gain or loss was recognized as a result of the termination of the swaps.
During the third quarter of 2012, Constellation Solar Horizons, a subsidiary of Generation, entered into a floating-to-fixed interest rate swap to
manage a portion of its interest rate exposure in connection with the long-term borrowings. See Note 14—Debt and Credit Agreements for additional
information regarding the financing. During the first quarter of 2016, upon the termination of debt, Generation terminated the swap. The total notional
amount of the swap was $24 million. No gain or loss was recognized as a result of the termination of the swap.
During the second quarter 2015, upon the issuance of debt, Exelon terminated $2,400 million of floating-to-fixed forward starting interest rate
swaps. As a result of the termination of the swaps, Exelon realized a $64 million loss during the second quarter of 2015.
At December 31, 2016, Generation had no notional amounts of interest rate derivative contracts to economically hedge risk associated with the
interest rate component of commodity positions and $85 million in notional amounts of foreign currency exchange rate swaps that are
marked-to-market to manage the exposure associated with international purchases of commodities in currencies other than U.S. dollars.
Fair Value Measurement and Accounting for the Offsetting of Amounts Related to Certain Contracts (Exelon Generation, ComEd,
PECO, BGE, PHI and DPL)
Fair value accounting guidance and disclosures about offsetting assets and liabilities requires the fair value of derivative instruments to be
shown in the Notes to the 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
439
Table of Contents
Combined Notes to Consolidated Financial Statements—(Continued)
(Dollars in millions, except per share data unless otherwise noted)
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 initial margin on exchange positions, is aggregated in the collateral and netting column. As of December 31, 2016 and 2015,
$8 million of cash collateral held and $3 million of cash collateral posted, respectively, was not offset against derivative positions because such
collateral was not associated with any energy-related derivatives, were associated with accrual positions, or as of the balance sheet date there were
no positions to offset. 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 a non affiliate 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, is aggregated in the collateral and netting column.
440
Table of Contents
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 recorded by the Registrants as of December 31, 2016:
Derivatives
Mark-to-market derivative assets
Generation
ComEd
Economic
Proprietary
Collateral
and
Hedges
Trading
Netting (a) Subtotal (b)
Economic
Hedges (c)
Economic
Hedges (d)
DPL
Collateral
and
Netting (a) Subtotal Subtotal
Total
Derivatives
Successor
PHI
Exelon
(current assets)
$
3,623 $
55 $
(2,769) $
909 $
— $
2 $
(2) $ — $
— $
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
1,467
21
(1,016)
472
—
—
—
—
—
5,090
76
(3,785)
1,381
—
2
(2)
—
—
1,381
(3,165)
(54)
2,964
(255)
(19)
—
—
—
—
(274)
(1,274)
(25)
1,150
(149)
(239)
—
—
—
—
(388)
(4,439)
(79)
4,114
(404)
(258)
—
—
—
—
(662)
909
472
assets (liabilities)
$
651 $
(3) $
329 $
977 $
(258) $
2 $
(2) $ — $
— $
719
(a) Exelon, Generation, PHI and DPL net all available amounts allowed under the derivative accounting 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 $100 million and $72 million, respectively, and current and noncurrent liabilities are shown net of collateral of
$95 million and $62 million, respectively. The total cash collateral posted, net of cash collateral received and offset against mark-to-market assets and liabilities was
$329 million at December 31, 2016.
Includes current and noncurrent liabilities relating to floating-to-fixed energy swap contracts with unaffiliated suppliers.
(c)
(d) Represents natural gas futures purchased by DPL as part of a natural gas hedging program approved by the DPSC.
441
Table of Contents
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 recorded by the Registrants as of December 31, 2015:
Derivatives
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)
Generation
ComEd Exelon
Economic
Proprietary
Collateral
and
Hedges
Trading
Netting (a) Subtotal (b)
Economic
Hedges (c)
Total
Derivatives
Economic
Hedges (e)
DPL
Collateral
and
Netting (a) Subtotal Other (d)
Total
Derivatives
Predecessor
PHI
Corporate
PHI
$
5,236 $
108 $
(3,994) $
1,350 $
— $
1,350 $
— $
— $ — $
18 $
1,860
7,096
22
130
(1,163)
(5,157)
719
2,069
—
—
719
2,069
—
—
— —
— —
—
18
(4,907)
(94)
4,827
(174)
(23)
(197)
(2)
2 —
—
(1,673)
(6,580)
(33)
(127)
1,564
6,391
(142)
(316)
(224)
(247)
(366)
(563)
—
(2)
— —
2 —
—
—
18
—
18
—
—
—
$
516 $
3 $
1,234 $
1,753 $
(247) $
1,506 $
(2) $
2 $ — $
18 $
18
(a) Exelon, Generation, PHI and DPL net all available amounts allowed under the derivative accounting 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 $352 million and $180 million, respectively, and current and noncurrent liabilities are shown net of collateral of
$480 million and $222 million, respectively. The total cash collateral posted, net of cash collateral received and offset against mark-to-market assets and liabilities was
$1,234 million at December 31, 2015.
Includes current and noncurrent liabilities relating to floating-to-fixed energy swap contracts with unaffiliated suppliers.
(c)
(d) Prior to the PHI Merger, PHI recorded derivative assets for the embedded call and redemption features on the shares of Preferred Stock outstanding as of December 31,
2015. See Note 19—Mezzanine Equity for additional information. As a result of the PHI Merger, the PHI preferred stock derivative was reduced to zero as of March 23,
2016.
(e) Represents natural gas futures purchased by DPL as part of a natural gas hedging program approved by the DPSC.
442
Table of Contents
Combined Notes to Consolidated Financial Statements—(Continued)
(Dollars in millions, except per share data unless otherwise noted)
Cash Flow Hedges (Exelon and Generation). The tables below provide the activity of OCI related to cash flow hedges for the years ended
December 31, 2016 and 2015, containing information about the changes in the fair value of cash flow hedges and the reclassification from
Accumulated OCI into results of operations. The amounts reclassified from OCI, 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, 2016
AOCI derivative loss at December 31, 2015
Effective portion of changes in fair value
Reclassifications from AOCI to net income
AOCI derivative loss at December 31, 2016
For the Year Ended December 31, 2015
Accumulated OCI derivative loss at December 31, 2014
Effective portion of changes in fair value
Reclassifications from AOCI to net income
Reclassifications from AOCI to net income
Reclassifications from AOCI to net income
Accumulated OCI derivative loss at December 31, 2015
Income Statement
Location
Interest expense
Income Statement
Location
Other, net
Interest Expense
Operating Revenues
Total Cash Flow Hedge OCI Activity,
Net of Income Tax
Generation
Total Cash
Flow Hedges
(21)
$
(6)
8(a)
$
(19)
Exelon
Total Cash
Flow Hedges
(19)
(6)
8(a)
$
$
(17)
Total Cash Flow Hedge OCI Activity,
Net of Income Tax
Generation
Total Cash
Flow Hedges
(18)
$
(8)
—
7(c)
(2)
(21)
$
Exelon
Total Cash
Flow Hedges
(28)
(12)
16 (b)
7(c)
(2)
(19)
$
$
(a) Amount is net of related income tax expense of $5 million for the year ended December 31, 2016.
(b) Amount is net of related income tax expense of $10 million for the year ended December 31, 2015.
(c) Amount is net of related income tax expense of $4 million for the year ended December 31, 2015,
During the years ended December 31, 2015 and 2014, the effect of Exelon’s and Generation’s former energy-related cash flow hedge activity
on pre-tax earnings based on the reclassification adjustment from OCI to earnings was a $2 million and $195 million pre-tax gain, respectively.
Neither Exelon nor Generation will incur changes in cash flow hedge ineffectiveness in future periods relating to energy-related hedges positions as
all were de-designated prior to the Constellation merger date.
Economic Hedges (Exelon and Generation). These instruments represent hedges that economically mitigate exposure to fluctuations in
commodity prices and include financial options, futures, swaps, physical forward sales and purchases, but for which the fair value or cash flow hedge
elections were not made. Additionally, Generation enters into interest rate derivative contracts and foreign exchange currency swaps (“treasury”) to
manage the exposure related to the interest rate component of commodity positions and international purchases of commodities in currencies other
than U.S. Dollars. For the years ended December 31, 2016, 2015 and 2014, the following net pre-tax mark-to-market gains (losses) of certain
purchase and sale contracts were reported in Operating
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Combined Notes to Consolidated Financial Statements—(Continued)
(Dollars in millions, except per share data unless otherwise noted)
revenues or Purchased power and fuel expense, or Interest expense at Exelon and Generation 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. In the tables below, “Change in fair value” represents the change in fair value of the derivative contracts held at the reporting date. The
“Reclassification to realized at settlement” represents the recognized change in fair value that was reclassified to realized due to settlement of the
derivative during the period.
Year Ended December 31, 2016
Change in fair value of commodity positions
Reclassification to realized at settlement of commodity positions
Net commodity mark-to-market gains (losses)
Change in fair value of treasury positions
Reclassification to realized at settlement of treasury positions
Net treasury mark-to-market gains (losses)
Net mark-to-market gains (losses)
Year Ended December 31, 2015
Change in fair value of commodity positions
Reclassification to realized at settlement of commodity positions
Net commodity mark-to-market gains (losses)
Change in fair value of treasury positions
Reclassification to realized at settlement of treasury positions
Net treasury mark-to-market gains (losses)
Net mark-to-market gains (losses)
444
Operating
Revenues
5
$
(495)
(490)
(2)
(8)
(10)
(500)
$
Generation
Purchased
Power
and Fuel
208
$
251
459
—
—
—
459
$
Total
$ 213
(244)
(31)
(2)
(8)
(10)
$ (41)
Exelon
Total
$ 213
(244)
(31)
(2)
(8)
(10)
$ (41)
Operating
Revenues
759
$
(563)
196
13
(6)
7
203
$
Generation
Purchased
Power
and Fuel
(355)
$
409
54
—
—
—
54
$
Total
$ 404
(154)
250
13
(6)
7
$ 257
Exelon
Corporate
Exelon
Interest
Expense
$ —
—
—
36
64
100
100
$
Total
$ 404
(154)
250
49
58
107
$ 357
Table of Contents
Combined Notes to Consolidated Financial Statements—(Continued)
(Dollars in millions, except per share data unless otherwise noted)
Year Ended December 31, 2014
Change in fair value of commodity positions
Reclassification to realized at settlement of commodity positions
Net commodity mark-to-market gains (losses)
Change in fair value of treasury positions
Reclassification to realized at settlement of treasury positions
Net treasury mark-to-market gains (losses)
Net mark-to-market gains (losses)
Operating
Revenues
(413)
$
231
(182)
10
(2)
8
(174)
$
Generation
Purchased
Power
and Fuel
(194)
$
(223)
(417)
—
—
—
(417)
$
Interest
Expense
$ —
—
—
(2)
—
(2)
(2)
$
Total
$(607)
8
(599)
8
(2)
6
$(593)
Exelon
Corporate
Exelon
Interest
Expense
$ —
—
—
(100)
—
(100)
(100)
$
Total
$ (607)
8
(599)
(92)
(2)
(94)
$ (693)
Proprietary Trading Activities (Exelon and Generation). For the years ended December 31, 2016, 2015, and 2014 Exelon and Generation
recognized the following net unrealized mark-to-market gains (losses), net realized mark-to-market gains (losses) and total net mark-to-market gains
(losses), before income taxes, relating to mark-to-market activity on commodity derivative instruments entered into for proprietary trading purposes
and interest rate and foreign exchange derivative contracts 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. In the tables below, “Change in fair value” represents the change in fair value
of the derivative contracts held at the reporting date. The “Reclassification to realized at settlement” represents the recognized change in fair value
that was reclassified to realized due to settlement of the derivative during the period.
Change in fair value of commodity positions
Reclassification to realized at settlement of commodity positions
Net commodity mark-to-market gains (losses)
Change in fair value of treasury positions
Reclassification to realized at settlement of treasury positions
Net treasury mark-to market gains (losses)
Net mark-to market gains (losses)
Credit Risk (All Registrants)
For the Years Ended
December 31,
2016
$ 23
(21)
2
(1)
—
(1)
1
$
2015
$ 8
(14)
(6)
8
(10)
(2)
$ (8)
2014
$ (1)
(29)
(30)
1
3
4
$(26)
The Registrants would be exposed to credit-related losses in the event of non-performance by counterparties that enter into derivative
instruments. The credit exposure of derivative contracts, before
445
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Combined Notes to Consolidated Financial Statements—(Continued)
(Dollars in millions, except per share data unless otherwise noted)
collateral, is represented by the fair value of contracts at the reporting date. For energy-related derivative instruments, 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, 2016. 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 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 $14 million, $33 million $26 million, $44 million, $16 million and $9 million as of
December 31, 2016, respectively.
Rating as of December 31, 2016
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
Total
Exposure
Before Credit
Collateral
$
$
995
118
352
72
1,537
Credit
Collateral
(a)
$ —
16
1
8
25
$
Net
Exposure
995
$
102
351
64
$ 1,512
Number of
Counterparties
Greater than 10%
of Net Exposure
1
—
Net Exposure of
Counterparties
Greater than 10%
of Net Exposure
328
$
—
—
—
1
$
—
—
328
December 31, 2016
116
$
689
636
71
1,512
$
(a) As of December 31, 2016, credit collateral held from counterparties where Generation had credit exposure included $9 million of cash and $16 million of letters of credit.
The credit collateral does not include non-liquid collateral.
446
Table of Contents
Combined Notes to Consolidated Financial Statements—(Continued)
(Dollars in millions, except per share data unless otherwise noted)
ComEd’s power procurement contracts provide suppliers with a certain amount of unsecured credit. The credit position is based on 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, the suppliers are required to 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. As of December 31, 2016, ComEd’s net credit exposure to suppliers was
approximately $1 million.
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 3—Regulatory Matters for additional information.
PECO’s supplier master agreements that govern the terms of its electric supply procurement contracts, which define a supplier’s performance
assurance requirements, allow a supplier to meet its credit requirements 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 PECO’s net credit exposure. As of December 31, 2016, PECO had no net credit exposure to suppliers.
PECO is permitted to recover its costs of procuring electric supply through its PAPUC-approved DSP Program. PECO’s counterparty credit
risk is mitigated by its ability to recover realized energy costs through customer rates. See Note 3—Regulatory Matters for additional information.
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. PECO does not obtain collateral from suppliers under its natural
gas supply and asset management agreements. As of December 31, 2016, 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 3—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. 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, subject to an unsecured credit cap. 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
447
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Combined Notes to Consolidated Financial Statements—(Continued)
(Dollars in millions, except per share data unless otherwise noted)
unsecured credit used by the suppliers represents BGE’s net credit exposure. The seller’s credit exposure is calculated each business day. As of
December 31, 2016, BGE had no net credit exposure to suppliers.
BGE’s regulated gas business is exposed to market-price risk. This market-price risk is mitigated by BGE’s recovery of its costs to procure
natural gas through a gas cost adjustment clause approved by the MDPSC. BGE does make off-system sales after BGE has satisfied its customers’
demands, which are not covered by the gas cost adjustment clause. At December 31, 2016, BGE had credit exposure of $8 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, 2016, 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 3—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, 2016, DPL had no credit exposure under its natural gas supply and asset management agreements with investment grade suppliers.
Collateral and Contingent-Related Features (All Registrants)
As part of the normal course of business, Generation routinely enters into physical or financially settled contracts for the purchase and sale of
electric capacity, energy, fuels, emissions allowances and other energy-related products. Certain of Generation’s derivative instruments contain
provisions that require Generation to post collateral. Generation also enters into commodity transactions on exchanges (i.e. NYMEX, ICE). 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
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Combined Notes to Consolidated Financial Statements—(Continued)
(Dollars in millions, except per share data unless otherwise noted)
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,
2016
2015
$
$
(960)
627
(333)
$
$
(932)
684
(248)
(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 $347 million and letters of credit posted of $284 million, and cash collateral held of $24 million and
letters of credit held of $28 million as of December 31, 2016 for external counterparties with derivative positions. Generation had cash collateral
posted of $1,267 million and letters of credit posted of $497 million and cash collateral held of $21 million and letters of credit held of $78 million at
December 31, 2015 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 $1.9 billion and $2.0 billion as of December 31, 2016
and 2015, 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, 2016, Generation’s swaps had an immaterial fair value and Exelon’s swaps were in an asset position with a
fair value of $16 million.
449
Table of Contents
Combined Notes to Consolidated Financial Statements—(Continued)
(Dollars in millions, except per share data unless otherwise noted)
See Note 26—Segment Information for further 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, 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, 2016, ComEd held approximately $3 million in collateral from suppliers in association with energy procurement
contracts. Under the terms of ComEd’s annual renewable energy contracts, collateral postings are required to cover a fixed value for RECs only. In
addition, 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, 2016, ComEd held approximately $19 million in the form of cash and letters of credit as margin for both the annual and
long-term REC obligations. If ComEd lost its investment grade credit rating as of December 31, 2016, it would have been required to post
approximately $19 million of collateral to its counterparties. See Note 3—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, 2016, PECO was not required to post collateral for any of these
agreements. If PECO lost its investment grade credit rating as of December 31, 2016, PECO could have been required to post approximately
$31 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 full requirements wholesale power agreements that govern the terms of its electric supply procurement contracts do not contain
provisions that would require BGE 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, 2016, BGE was not required to post collateral for any of these agreements.
If BGE lost its investment grade credit rating as of December 31, 2016, BGE could have been required to post approximately $62 million of collateral
to its counterparties.
Pepco’s full requirements wholesale power agreements that govern the terms of its electric supply procurement contracts do not contain
provisions that would require Pepco to post collateral.
DPL’s full requirements wholesale power agreements that govern the terms of its electric supply procurement contracts do not contain
provisions that would require DPL to post collateral.
450
Table of Contents
Combined Notes to Consolidated Financial Statements—(Continued)
(Dollars in millions, except per share data unless otherwise noted)
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, 2016, DPL could have been required to post an additional amount of approximately
$10 million of collateral to its natural gas counterparties.
ACE’s full requirements wholesale power agreements that govern the terms of its electric supply procurement contracts do not contain
provisions that would require ACE to post collateral.
14. Debt and Credit Agreements (All Registrants)
Short-Term Borrowings
Exelon, ComEd, and BGE meet their short-term liquidity requirements primarily through the issuance of commercial paper. Generation and
PECO meet their short-term liquidity requirements primarily through the issuance of commercial paper and borrowings from the Exelon intercompany
money pool. PHI meets its short-term liquidity requirement primarily through the issuance of short-term notes and the Exelon intercompany money
pool. Pepco, DPL and ACE meet their short-term liquidity requirements primarily through the issuance of commercial paper and short-term notes.
The Registrants may use their respective credit facilities for general corporate purposes, including meeting short-term funding requirements and the
issuance of letters of credit.
Commercial Paper
The following table reflects the Registrants’ commercial paper programs supported by the revolving credit agreements and bilateral credit
agreements at December 31, 2016 and December 31, 2015:
Commercial Paper Issuer
Exelon Corporate
Generation
ComEd
PECO
BGE
PHI Corporate
Pepco
DPL
ACE
Total
Maximum
Program Size at
December 31,
2016
(a)(b )
$ 600
5,300
1,000
600
600
—
500
500
350
$9,450
2015 (a)
(b)
$
500
5,450
1,000
600
600
875
500
500
350
$10,375
Outstanding
Commercial
Paper at
December 31,
2016
$ —
620
—
—
45
—
23
—
—
$688
2015
$ —
—
294
—
210
484
64
105
5
$1,162
Average Interest Rate on
Commercial Paper Borrowings for
the Year Ended December 31,
2016
2015
0.70%
0.94%
0.77%
n.a
0.77%
1.03%
0.71%
0.68%
0.65%
n.a.
0.49%
0.53%
n.a.
0.48%
0.80%
0.44%
0.47%
0.46%
(a) Excludes $500 million and $275 million in bilateral credit facilities that do not back Generation’s commercial paper program at December 31, 2016 and 2015, respectively.
(b) Excludes additional credit facility agreements for Generation, ComEd, PECO, BGE, Pepco, DPL and ACE with aggregate commitments of $50 million, $34 million,
$34 million, $5 million, $2 million, $2 million and $2 million, respectively, arranged with minority and community banks located primarily within utilities’ service territories.
These facilities expire on October 13, 2017. These facilities are solely utilized to issue letters of credit. As of December 31, 2016, letters of credit issued under these
facilities totaled $7 million, $12 million, $21 million and $2 million for Generation, ComEd, PECO 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)
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.
At December 31, 2016, the Registrants had the following aggregate bank commitments, credit facility borrowings and available capacity under
their respective credit facilities:
Available Capacity at
December 31, 2016
Borrower
Exelon Corporate
Generation
Generation
ComEd
PECO
BGE
Pepco
DPL
ACE
Total
Facility Type
Syndicated Revolver
Syndicated Revolver
Bilaterals
Syndicated Revolver
Syndicated Revolver
Syndicated Revolver
Syndicated Revolver
Syndicated Revolver
Syndicated Revolver
Aggregate Bank
Commitment (a)(b)
600
$
5,300
500
1,000
600
600
300
300
300
9,500
$
Facility Draws
—
$
—
75
—
—
—
—
—
—
75
$
Outstanding
Letters of Credit (c)
29
$
1,170
306
2
2
—
—
—
1
1,510
$
Actual
$ 571
4,130
119
998
598
600
300
300
299
$7,915
To Support
Additional
Commercial
Paper (d)
$
$
571
3,510
—
998
598
555
277
300
299
7,108
(a) Excludes additional credit facility agreements for Generation, ComEd, PECO, BGE, Pepco, DPL and ACE with aggregate commitments of $50 million, $34 million,
$34 million ,$5 million, $2 million, $2 million and $2 million, respectively, arranged with minority and community banks located primarily within utilities’ service territories.
These facilities expire on October 13, 2017. These facilities are solely utilized to issue letters of credit. As of December 31, 2016, letters of credit issued under these
facilities totaled $7 million, $12 million, $21 million and $2 million for Generation, ComEd, PECO and BGE, respectively.
(b) 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.
(c) Excludes nonrecourse debt letters of credit, see discussion below on Continental Wind.
(d) Excludes $500 million in bilateral credit facilities that do not back Generation’s commercial paper program.
As of December 31, 2016, there was $75 million of borrowings under Generation’s bilateral credit facilities.
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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, BGE, PHI, Pepco, DPL and ACE during 2016,
2015 and 2014. PECO did not have any short-term borrowings during 2016, 2015 or 2014.
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
BGE
Average borrowings
Maximum borrowings outstanding
Average interest rates, computed on a daily basis
Average interest rates, computed at December 31
PHI
Average borrowings
Maximum borrowings outstanding
Average interest rates, computed on a daily basis
Average interest rates, computed at December 31
2016
$1,125
3,076
0.88%
1.12%
2015
$ 499
739
0.53%
0.88%
2014
$ 571
1,164
0.32%
0.53%
2016
$ 536
1,735
0.94%
1.14%
2015
1
$
50
0.49%
n.a.
2014
$ 93
552
0.32%
n.a.
2016
$ 256
755
0.77%
n.a.
2015
$ 461
684
0.53%
0.89%
2014
$ 415
597
0.33%
0.50%
2016
$ 143
369
0.77%
0.95%
2015
$ 37
210
0.48%
0.87%
2014
$ 64
180
0.29%
0.61%
Successor
2016
$
153
559
1.03%
n.a.
Predecessor
2015
$ 444
784
0.90%
1.22%
2014
$ 153
369
0.56%
0.78%
453
Table of Contents
Pepco
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
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
2016
4
$
73
0.71%
0.90%
2015
$ 34
190
0.44%
0.68%
2014
$ 37
209
0.28%
0.46%
2016
$ 33
116
0.68%
n.a.
2015
$ 81
179
0.47%
0.79%
2014
$ 69
177
0.26%
0.42%
2016
$ —
5
0.65%
n.a.
2015
$ 175
253
0.46%
0.65%
2014
$ 112
259
0.27%
0.52%
On July 30, 2015, PHI entered into a $300 million term loan agreement. 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, loans made thereunder bear interest at a variable rate equal
to LIBOR plus 0.95%, and all indebtedness thereunder is unsecured. On April 4, 2016, PHI repaid $300 million of its term loan in full.
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, and the aggregate
principal amount of all loans, together with any accrued but unpaid interest due under the Loan Agreement, must be repaid in full on or before
March 27, 2017. The loan agreement is reflected in Exelon’s and PHI’s Consolidated Balance Sheets within Short-term borrowings.
On February 22, 2016, Generation and EDF entered into separate member revolving promissory notes with CENG to finance short-term
working capital needs. The notes are scheduled to mature on January 31, 2017 and bear interest at a variable rate equal to LIBOR plus 1.75%. On
July 25, 2016, CENG paid off the outstanding balances under each note.
Credit Agreements
On January 5, 2016, Generation entered into a credit agreement establishing a $150 million bilateral credit facility, scheduled to mature in
January of 2019. This facility will solely be utilized by Generation to issue lines of credit. This facility does not back Generation’s commercial paper
program.
454
Table of Contents
Combined Notes to Consolidated Financial Statements—(Continued)
(Dollars in millions, except per share data unless otherwise noted)
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. 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.
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
Exelon Generation ComEd PECO
0.0
27.5
90.0
127.5
7.5
107.5
27.5
127.5
BGE Pepco
7.5
107.5
0.0
100.0
DPL
7.5
107.5
ACE
7.5
107.5
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.
An event of default under any of the Registrants’ credit agreements would not constitute an event of default under any of the other Registrants’
credit agreements, 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 under its credit agreement would constitute an event of default under the Exelon Corporation
credit agreement.
Each credit agreement 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 ratios exclude revenues and interest expenses attributable to securitization debt, certain
changes in working capital, distributions on preferred securities of subsidiaries and, in the case of Exelon and Generation, interest on the debt of its
project subsidiaries. The following table summarizes the minimum thresholds reflected in the credit agreements for the year ended December 31,
2016:
Credit agreement threshold
Exelon
2.50 to 1
Generation
3.00 to 1
ComEd
2.00 to 1
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, 2016, the interest coverage ratios at the Registrants were as follows:
Interest coverage ratio
Exelon Generation ComEd PECO
8.77
6.89
7.03
11.81
455
BGE Pepco DPL ACE
5.84
6.24
8.42
10.47
Table of Contents
Combined Notes to Consolidated Financial Statements—(Continued)
(Dollars in millions, except per share data unless otherwise noted)
Through May 26, 2016, when Pepco, DPL and ACE entered into a new restated credit agreement, as mentioned above, PHI, Pepco, DPL and
ACE had maintained an unsecured syndicated credit facility to provide for their respective liquidity needs, including obtaining letters of credit,
borrowing for general corporate purposes and supporting their commercial paper programs. The termination date of this credit facility was August 1,
2018.
The aggregate borrowing limit under the amended and restated credit facility was $1.5 billion, all or any portion of which could have been used
to obtain loans and up to $500 million of which could have been used to obtain letters of credit. The facility also included a swingline loan
sub-facility, pursuant to which each company could have made same day borrowings in an aggregate amount not to exceed 10% of the total amount
of the facility. Any swingline loan had to be repaid by the borrower within fourteen days of receipt. The credit sublimit was $750 million for PHI and
$250 million for each of Pepco, DPL and ACE. The sublimits could have been increased or decreased by the individual borrower during the term of
the facility, except that (i) the sum of all of the borrower sublimits following any such increase or decrease had to equal the total amount of the facility
and (ii) the aggregate amount of credit used at any given time by (a) PHI could not exceed $1.25 billion and (b) each of Pepco, DPL or ACE could
not exceed the lesser of $500 million and the maximum amount of short-term debt the company was permitted to have outstanding by its regulatory
authorities. The total number of the sublimit reallocations could not exceed eight per year during the term of the facility.
The interest rate payable by each company on utilized funds was, at the borrowing company’s election, (i) the greater of the prevailing prime
rate, the federal funds effective rate plus 0.5% and the one-month London Interbank Offered Rate (LIBOR) plus 1.0%, or (ii) the prevailing Eurodollar
rate, plus a margin that varies according to the credit rating of the borrower.
In order for a borrower to use the facility, certain representations and warranties had to be true and correct, and the borrower had to be in
compliance with specified financial and other covenants, including (i) the requirement that each borrowing company maintain a ratio of total
indebtedness to total capitalization of 65% or less, computed in accordance with the terms of the credit agreement, which calculation excluded from
the definition of total indebtedness certain trust preferred securities and deferrable interest subordinated debt (not to exceed 15% of total
capitalization), (ii) with certain exceptions, a restriction on sales or other dispositions of assets, and (iii) a restriction on the incurrence of liens on the
assets of a borrower or any of its significant subsidiaries other than permitted liens. The credit agreement contained certain covenants and other
customary agreements and requirements that, if not complied with, resulted in an event of default and the acceleration of repayment obligations of
one or more of the borrowers thereunder.
The absence of a material adverse change in PHI’s business, property, results of operations or financial condition was not a condition to the
availability of credit under the credit agreement. The credit agreement did not 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
456
Table of Contents
Combined Notes to Consolidated Financial Statements—(Continued)
(Dollars in millions, except per share data unless otherwise noted)
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 December 31, 2016 and December 31, 2015, $105 million in variable rate demand bonds
issued by DPL were outstanding and are included in the Long-term debt due within one year on Exelon’s, PHI’s and DPL’s Consolidated Balance
Sheet.
Long-Term Debt
The following tables present the outstanding long-term debt at the Registrants as of December 31, 2016 and 2015:
Exelon
Long-term debt
Rate stabilization bonds
First mortgage bonds (a)
Senior unsecured notes
Unsecured bonds
Pollution control notes
Nuclear fuel procurement contracts
Notes payable and other (b)(c)
Junior subordinated notes
Contract payment - junior subordinated notes
Long-term software licensing agreement
Unsecured Tax-Exempt Bonds
Medium-Terms Notes (unsecured)
Transition bonds
Nonrecourse debt:
Fixed rates
Variable rates
Total long-term debt
Unamortized debt discount and premium, net
Unamortized debt issuance costs
Fair value adjustment
Long-term debt due within one year
Long-term debt
Long-term debt to financing trusts (d)
Subordinated debentures to ComEd
Financing III
Subordinated debentures to PECO Trust III
Subordinated debentures to PECO Trust IV
Subordinated debentures to BGE Capital Trust II
Total long-term debt to financing trusts
Unamortized debt issuance costs
Long-term debt to financing trusts
Rates
Maturity
Date
December 31,
2016
2015
41 $
2017 $
120
5.82% — 5.82%
1.70% — 7.90% 2017-2046 14,123 9,019
1.55% — 7.60% 2017-2046 11,868 9,803
2.40% — 6.35% 2021-2046 2,300 1,750
435
2.50% — 2.70% 2025-2036
127
3.15% — 3.35% 2018-2020
1.43% — 7.83% 2017-2053
314
2024 1,150 1,150
6.50%
64
2017
2.50%
19
111
2024
3.95%
103
112 —
2031
5.40%
40 —
6.81% — 7.72% 2017-2027
124 —
5.05% — 5.55% 2020-2023
435
105
576
2.29% — 6.00% 2031-2037 1,400 1,162
915 1,058
3.18% — 5.00% 2019-2021
33,311 25,113
(63)
(180)
275
(2,430) (1,500)
$31,575 $23,645
(68)
(200)
962
6.35%
7.38%
5.75%
6.20%
2033 $
2028
2033
2043
$
206 $
81
103
258
648
(7)
641 $
206
81
103
258
648
(7)
641
457
Table of Contents
Combined Notes to Consolidated Financial Statements—(Continued)
(Dollars in millions, except per share data unless otherwise noted)
(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)
(c)
their respective mortgage indentures.
Includes capital lease obligations of $69 million and $29 million at December 31, 2016 and 2015, respectively. Lease payments of $17 million, $18 million, $20 million,
$5 million, $1 million, and $8 million will be made in 2017, 2018, 2019, 2020, 2021 and thereafter, respectively.
Includes financing related to Albany Green Energy, LLC (AGE), which is a consolidated variable interest entity (see Note 2—Variable Interest Entities for additional
information). The agreement is scheduled to expire on November 17, 2017, at a variable rate equal to LIBOR plus 1.25%. As of December 31, 2016, $198 million was
outstanding.
(d) Amounts owed to these financing trusts are recorded as Long-term debt to financing trusts within Exelon’s Consolidated Balance Sheets.
Generation
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
Total long-term debt
Fair value adjustment
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,
2016
2015
2.00% — 7.60%
2.50% — 2.70%
3.15% — 3.35%
1.43% — 7.83%
2017-2042
2025-2036
2018-2020
2017-2035
2.29% — 6.00%
3.18% — 5.00%
2031-2037
2019-2021
$ 5,971
435
105
382
1,400
915
9,208
115
(17)
(65)
(1,117)
$ 8,124
$5,971
435
127
166
1,162
1,058
8,919
127
(17)
(70)
(90)
$8,869
(a)
(b)
Includes Generation’s capital lease obligations of $22 million and $21 million at December 31, 2016 and 2015, respectively. Generation will make lease payments of
$5 million, $5 million, $6 million and $5 million and $1 million in 2017, 2018, 2019, 2020 and 2021 respectively. The capital lease matures in 2020.
Includes financing related to Albany Green Energy, LLC (AGE), which is a consolidated variable interest entity (see Note 2—Variable Interest Entities for additional
information). The agreement is scheduled to expire on November 17, 2017, at a variable rate equal to LIBOR plus 1.25%. As of December 31, 2016, $198 million was
outstanding.
458
Table of Contents
ComEd
Combined Notes to Consolidated Financial Statements—(Continued)
(Dollars in millions, except per share data unless otherwise noted)
Rates
Maturity
Date
December 31,
2016
2015
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
Long-term debt to financing trust (c)
2.15% — 6.45%
6.95% — 7.49%
Subordinated debentures to ComEd Financing III
6.35%
Total long-term debt to financing trusts
Unamortized debt issuance costs
Long-term debt to financing trusts
2017-2046 $ 6,954 $ 6,419
148
2018-2053
6,567
(20)
(38)
(665)
$ 6,608 $ 5,844
147
7,101
(22)
(46)
(425)
2033 $ 206 $ 206
206
206
(1)
(1)
$ 205 $ 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, 2016 and 2015, respectively. Lease payments of less than $1 million will be made from
2017 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.
PECO
Long-term debt
First mortgage bonds (a)
Total long-term debt
Unamortized debt discount and premium, net
Unamortized debt issuance costs
Long-term debt due within one year
Long-term debt
Long-term debt to financing trusts (b)
Subordinated debentures to PECO Trust III
Subordinated debentures to PECO Trust IV
Long-term debt to financing trusts
Rates
Maturity
Date
December 31,
2016
2015
1.70% — 5.95%
2018-2044
$2,600
2,600
(5)
(15)
—
$2,580
$2,600
2,600
(5)
(15)
(300)
$2,280
7.38%
5.75%
2028
2033
$
81
103
$ 184
$
81
103
$ 184
(a) Substantially all of PECO’s assets are subject to the lien of its mortgage indenture.
(b) Amounts owed to this financing trust are recorded as Long-term debt to financing trusts within PECO’s Consolidated Balance Sheets.
459
Table of Contents
BGE
Combined Notes to Consolidated Financial Statements—(Continued)
(Dollars in millions, except per share data unless otherwise noted)
Rates
Maturity
Date
December 31,
2016
2015
Long-term debt
Rate stabilization bonds
Senior unsecured notes
Total long-term debt
Unamortized debt discount and premium, net
Unamortized debt issuance costs
Long-term debt due within one year
Long-term debt
Long-term debt to financing trusts (a)
5.82% — 5.82%
2.40% — 6.35%
2017
2021-2046
Subordinated debentures to BGE Capital Trust II
6.20%
2043
Total long-term debt to financing trusts
Unamortized debt issuance costs
Long-term debt to financing trusts
(a) Amount owed to this financing trust is recorded as Long-term debt to financing trust within BGE’s Consolidated Balance Sheets.
$
41
2,300
2,341
(4)
(15)
(41)
$ 2,281
$ 258
258
(6)
$ 252
$ 120
1,750
1,870
(3)
(9)
(378)
$ 1,480
$ 258
258
(6)
$ 252
PHI
Long-term debt
Notes (unsecured)
First mortgage bonds
Unsecured Tax-Exempt Bonds
Medium-Terms Notes (unsecured)
Transition bonds (a)
Notes payable and other (b)
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
Successor
Predecessor
December 31,
2016
2015
6.13% — 7.45%
3.05% — 7.90%
5.40%
6.81% — 7.72%
5.05% — 5.55%
6.20% — 8.88%
2017-2032
2018-2045
2031
2017-2027
2020-2023
2019-2021
$
266
4,569
112
40
124
46
5,157
1
(2)
742
(253)
$ 5,645
$
$
456
4,495
112
40
171
57
5,331
(2)
(50)
—
(456)
4,823
(a) Transition bonds are recorded as part of Long-term debt within ACE’s Consolidated Balance Sheets.
(b)
Includes Pepco’s capital lease obligations of $39 million and $50 million at December 31, 2016 and 2015, respectively.
460
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,
2016
2015
3.05% — 7.90%
6.20% — 8.88%
2022-2043
2019-2021
$ 2,335
46
2,381
(2)
(30)
(16)
$ 2,333
$ 2,335
50
2,385
(3)
(31)
(11)
$ 2,340
(a) Substantially all of Pepco’s assets are subject to the lien of its respective mortgage indenture.
(b)
Includes capital lease obligations of $39 million and $50 million at December 31, 2016 and 2015, respectively. Lease payments of $12 million, $13 million and $14 million
will be made in 2017, 2018 and 2019, respectively.
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
(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
(a) Substantially all of ACE’s assets are subject to the lien of its respective mortgage indenture.
461
Rates
Maturity
Date
December 31,
2016
2015
3.50% — 4.15%
5.40%
6.81% — 7.72%
2023-2045
2031
2017-2027
$ 1,196
112
40
1,348
2
(10)
(119)
$ 1,221
$ 1,121
112
40
1,273
2
(10)
(204)
$ 1,061
Rates
Maturity
Date
December 31,
2016
2015
3.38% — 7.75%
5.05% — 5.55%
2018-2036
2020-2023
$1,038
124
1,162
(1)
(6)
(35)
$1,120
$1,039
171
1,210
(1)
(8)
(48)
$1,153
Table of Contents
Combined Notes to Consolidated Financial Statements—(Continued)
(Dollars in millions, except per share data unless otherwise noted)
(b) Maturities of ACE’s Transition Bonds outstanding at December 31, 2016 are $35 million in 2017, $31 million in 2018, $18 million in 2019, $19 million in 2020 and
$21 million in 2021.
Long-term debt maturities at Exelon, Generation, ComEd, PECO, BGE, PHI, Pepco, DPL and ACE in the periods 2017 through 2021 and
thereafter are as follows:
Year
2017
2018
2019
2020
2021
Thereafter
Total
Exelon
$ 2,430
1,742
1,060
3,331
2,400
22,996(a)
Generation ComEd
1,117 $ 425
$
840
300
500
350
4,892(b)
104
606
1,912
888
4,581
9,208 $7,307
PECO
$ —
500
—
—
300
1,984(c)
$33,959
$
$
BGE
41
—
—
—
300
2,258(d)
$2,784
$2,599
PHI
Pepco
16
13
124
—
2
2,226
ACE
35
253
281
298
18
154
19
19
260
262
4,171
549
5,157 $2,381 $1,348 $1,162
DPL
119
4
12
—
—
1,213
(a)
(b)
(c)
(d)
Includes $648 million due to ComEd, PECO and BGE financing trusts.
Includes $206 million due to ComEd financing trust.
Includes $184 million due to PECO financing trusts.
Includes $258 million due to BGE financing trust.
PHI Merger Financing
In May 2014, concurrently and in connection with entering into the agreement to acquire PHI, Exelon entered into a credit facility to which the
lenders committed to provide Exelon a 364-day senior unsecured bridge credit facility of $7.2 billion to support the contemplated transaction and
provide flexibility for timing of permanent financing. In June 2015, the remaining $3.2 billion bridge credit facility was terminated as a result of
Exelon’s issuance of $4.2 billion of long-term debt to fund a portion of the purchase price and related costs and expenses for the pending PHI
merger and for general corporate purposes.
In connection with the $4.2 billion issuance of Senior Unsecured Notes in 2015, the tranches due in 2025, 2035, and 2045 had to be redeemed
at the principal amount plus a 1% premium of principal on December 31, 2015, if the PHI merger was not consummated or terminated prior to such
date (“Special Mandatory Redemption”). Exelon also had the option to redeem those notes earlier at a 1% premium of principal, if Exelon determined
that the merger would not be completed before December 31, 2015.
On October 29, 2015, Exelon commenced a private exchange offer (Exchange Offer) to certain eligible holders whereby, for those that took
part, the outstanding Senior Unsecured Notes in the 2025, 2035 and 2045 tranches were exchanged for new Senior Unsecured Notes.
On December 2, 2015, Exelon exchanged $1.9 billion of the Senior Unsecured Notes and paid a consent fee of approximately $5 million,
which has been deferred on Exelon’s Consolidated Balance Sheet and $4 million of third-party debt issuance costs, which were charged to earnings
within Other, net on Exelon’s Consolidated Statement of Operations and Comprehensive Income. On December 2, 2015, Exelon also redeemed
$0.9 billion of Senior Unsecured Notes not exchanged in the Exchange Offer resulting in the payment of $9 million of redemption premium and the
acceleration of the unamortized original issuance discount and deferred financing costs associated with the redeemed debt of $9 million, which were
charged to earnings within Other, net on Exelon’s Consolidated Statement of Operations and Comprehensive Income.
462
Table of Contents
Junior Subordinated Notes
Combined Notes to Consolidated Financial Statements—(Continued)
(Dollars in millions, except per share data unless otherwise noted)
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. Net proceeds from the issuance were $1.11 billion, net of a $35 million underwriter fee. The net proceeds were used to finance a portion of the
merger and related costs and expenses for the pending PHI merger and for general corporate purposes. Each equity unit represents an undivided
beneficial ownership interest in Exelon’s 2.50% junior subordinated notes due in 2024 and a forward equity purchase contract which settles in 2017.
The junior subordinated notes are expected to be remarketed in 2017.
At the time of issuance, Exelon determined that the forward equity purchase contract had no value and therefore the entire $1.15 billion of
junior subordinated notes were allocated to debt and recorded within Long-term debt on Exelon’s Consolidated Balance Sheet. Additionally, at the
time of issuance, the present value of the contract payments of $131 million (“Contract Payment Obligation”) were recorded to Long-term debt,
representing the obligation to make contract payments, with an offsetting reduction to Common stock. The obligation for the contract payments is
accreted to interest expense over the 3 year period ending in 2017 in Exelon’s Consolidated Statement of Operations and Comprehensive Income.
During 2016, contract payments of $45 million related to the Contract Payment Obligation were included within Retirements of long-term debt in
Exelon’s Consolidated Statements of Cash Flows. During 2015, contract payments of $44 million related to the Contract Payment Obligation were
included within Retirements of long-term debt in Exelon’s Consolidated Statements of Cash Flows. During 2014, the Contract Payment Obligation
was considered a non-cash financing transaction that was excluded from Exelon’s Consolidated Statements of Cash Flows. Until settlement of the
equity purchase contract, earnings per share dilution resulting from the equity unit issuance will be determined under the treasury stock method.
Nonrecourse Debt
Exelon and Generation have issued nonrecourse debt financing, in which approximately $2.8 billion of generating assets have been pledged
as collateral at December 31, 2016. 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, 2016, $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
463
Table of Contents
Combined Notes to Consolidated Financial Statements—(Continued)
(Dollars in millions, except per share data unless otherwise noted)
Holdings. The commitment level can be decreased if the assets no longer support the current borrowing base, which may result in repayment of a
portion or all of the outstanding balance, or potential foreclosure of the assets. The commitment can be increased up to $500 million million if the
assets support a higher borrowing base and CEU Holdings is able to obtain additional commitments from lenders. Calculations of the borrowing
base are impacted by projected production and commodity prices. The facility was amended and extended on January 14, 2014 through January
2019. As of December 31, 2015, $68 million was outstanding under the facility with interest payable monthly at a variable rate equal to LIBOR plus
2.50% and the borrowing base committed under the facility was $85 million. The outstanding balance was classified as Long-term debt on Exelon’s
and Generation’s Consolidated Balance Sheets.
In February 2016, as part of their semi-annual borrowing base re-determination testing, the RBL lenders notified CEU Holdings that the RBL
borrowing base was decreased to $45 million, resulting in a “borrowing base deficiency” under the RBL of $23 million. Given the decline in value of
the Upstream assets resulting from lower commodity prices, CEU Holdings chose not to provide the lenders with a formal plan for curing the
borrowing base deficiency by March 31, 2016, as was required by the RBL. The lenders sent CEU Holdings a notice of event of default and demand
for cure.
On June 16, 2016, CEU Holdings executed a forbearance agreement with the lenders which included terms stipulating roles and
responsibilities governing a sales process, approval of the sale of the assets to be at the discretion of the lenders, and a sales timetable.
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 of $6 million are being held in escrow and will be released
at final settlement. 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 with interest payable monthly at a variable rate equal to LIBOR plus 2.75%. Upon disposition of all of the assets and the satisfaction of
certain other conditions, 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, 2016, the
outstanding debt balance of $22 million was classified within Long term debt due within one year on Exelon’s and Generation’s Consolidated
Balance Sheets. See Note 4—Mergers, Acquisitions, and Dispositions and Note 8—Impairment of Long-Lived Assets 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, 2016, $9 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 the first half of 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, 2016, $552 million was outstanding. In
addition, Generation has issued letters of credit to support its equity investment in the project. As of December 31, 2016, Generation had
$106 million in letters of credit outstanding related to the project.
464
Table of Contents
Combined Notes to Consolidated Financial Statements—(Continued)
(Dollars in millions, except per share data unless otherwise noted)
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 667MW. The net proceeds were distributed to Generation for its
general business purposes. The notes are scheduled to mature on February 28, 2033. The notes bear interest at a fixed rate of 6.00% with interest
payable semi-annually. As of December 31, 2016, $543 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, 2016, the Continental Wind letter of
credit facility had $108 million in letters of credit outstanding related to the project.
ExGen Renewables I. In February 2014, EGR, an indirect subsidiary of Exelon and Generation, borrowed $300 million aggregate principal
amount pursuant to a nonrecourse senior secured loan. The proceeds were distributed to Generation for its general business purposes. The loan is
scheduled to mature on February 6, 2021. The loan bears interest at a variable rate equal to LIBOR plus 4.25%, subject to a 1% LIBOR floor with
interest payable quarterly. EGR indirectly owns Continental Wind. As of December 31, 2016, $234 million was outstanding. In addition to the
financing, EGR entered into interest rate swaps with an initial notional amount of $240 million at an interest rate of 2.03% to manage a portion of the
interest rate exposure in connection with the financing. See Note 13—Derivative Financial Instruments for additional information regarding interest
rate swaps.
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 is
scheduled to mature on September 18, 2021. The term loan bears interest at a variable rate equal to LIBOR plus 4.75%, subject to a 1% LIBOR
floor with interest payable quarterly. As of December 31, 2016, $660 million was outstanding. As part of the agreement, a revolving credit facility was
established for the amount of $20 million available through, and scheduled to mature on September 18, 2019. 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. See Note 13—Derivative Financial Instruments for
additional information regarding interest rate swaps.
EGTP’s operating cash flows have been negatively impacted by certain market conditions including, but not limited to: low power prices, higher
fuel prices and the seasonality of its cash flows. Despite the declining operating cash flows, EGTP remains in compliance with its covenants related
to the project specific financing. Management continues to monitor the project entity’s short term liquidity needs.
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, 2016, $141 million was outstanding.
465
Table of Contents
Combined Notes to Consolidated Financial Statements—(Continued)
(Dollars in millions, except per share data unless otherwise noted)
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,
2016, $148 million was outstanding.
15. Income Taxes (All Registrants)
Income tax expense (benefit) from continuing operations is comprised of the following components:
For the Year Ended December 31, 2016
Exelon Generation ComEd PECO BGE Pepco DPL ACE
Successor
March 24,
2016 to
December 31,
2016
PHI
Predecessor
January 1,
2016 to
March 23,
2016
PHI
Included in operations:
Federal
Current
Deferred
Investment tax credit amortization
State
Current
Deferred
Total
Included in operations:
Federal
Current
Deferred
Investment tax credit amortization
State
Current
Deferred
Total
Included in operations:
Federal
Current
Deferred
Investment tax credit amortization
State
Current
Deferred
Total
$
60 $
607
(24)
39
79
513 $ (135) $ 63 $ 51 $ (118) $ (88) $ (26) $
22
88
(247)
—
(1)
(20)
136
—
72
—
97
—
379
(2)
$ 761 $
290 $ 301 $ 149 $ 174 $
45
(1)
(4)
63
9
5
5
31
1
12
—
7
16
—
41 $ 22 $ (4) $
(281) $
283
(1)
(11)
13
3 $
—
10
—
—
7
17
Predecessor
For the Year Ended December 31, 2015
Exelon Generation ComEd PECO BGE Pepco DPL ACE
PHI
$ 407 $
566
(22)
(86)
208
$ 1,073 $
546 $
16
(19)
(80) $ 64 $ 25 $ (54) $ (27) $ (2) $
310
(2)
126
—
69
—
126
(1)
27
—
73
—
(90)
49
—
39
502 $ 280 $ 143 $ 189 $ 102 $ 49 $ 33 $
(10)
20
7
45
6
24
2
1
3
5
12
103
(1)
17
32
163
Exelon Generation ComEd PECO BGE Pepco DPL ACE
PHI
For the Year Ended December 31, 2014
Predecessor
$ 121 $
576
(20)
42
(53)
$ 666 $
360 $ (171) $ 28 $ 24 $ (79) $ (45) $ (6) $
90
(35)
(1)
(16)
150
—
87
—
31
(1)
98
(1)
395
(2)
35
(137)
207 $ 268 $ 114 $ 140 $
—
27
7
39
(2)
1
—
13
(2)
24
93 $ 65 $ 30 $
(1)
7
(153)
261
(1)
(10)
41
138
466
Table of Contents
Combined Notes to Consolidated Financial Statements—(Continued)
(Dollars in millions, except per share data unless otherwise noted)
The effective income tax rate from continuing operations varies from the U.S. Federal statutory rate principally due to the following:
For the Year Ended December 31, 2016
Successor
March 24,
2016 to
December 31,
2016
Predecessor
January 1,
2016 to
March 23,
2016
Exelon
Generation
ComEd
PECO
BGE
Pepco
DPL
(a)
ACE
(a)
PHI (a)
PHI
35.0%
35.0%
35.0%
35.0%
35.0%
35.0%
35.0%
35.0%
35.0%
35.0%
U.S. Federal statutory rate
Increase (decrease) due to:
State income taxes, net of
Federal income tax benefit (b)
3.3
3.3
5.6
1.3
5.0
15.7
52.7
6.2
Qualified nuclear
decommissioning trust fund
loss
Domestic production activities
deduction
Health care reform legislation
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 (c)
Effective income tax rate
3.4
7.8
—
—
—
—
—
—
—
—
—
—
—
—
—
—
—
—
—
—
—
—
—
—
(1.2)
(4.8)
(3.6)
(0.2)
(0.4)
1.9
5.5
(0.6)
38.3%
(2.3)
—
(8.2)
(0.3)
(1.7)
—
1.1
(1.5)
33.2%
(0.3)
(0.6)
(0.1)
(9.6)
(0.1)
(2.7)
(0.2)
(22.8)
(3.7)
(25.5)
0.8
10.3
—
—
—
4.5
—
0.1
44.3%
—
—
—
—
—
(1.2)
25.4%
—
—
—
—
—
—
37.2%
—
—
—
—
23.5
(1.8)
49.4%
—
—
—
—
112.9
(2.2)
169.2%
—
—
—
—
(44.9)
1.3
8.7%
5.8
—
—
—
1.4
39.0
—
—
—
(0.7)
(89.0)
3.3
(5.2)%
11.9
—
—
—
(0.9)
(13.5)
—
—
—
—
11.1
3.6
47.2%
U.S. Federal statutory rate
Increase (decrease) due to:
State income taxes, net of Federal income
tax benefit
Qualified nuclear decommissioning trust
fund income
Domestic production activities deduction
Health care reform legislation
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
Other (d)
Effective income tax rate
Exelon
Generation
ComEd
PECO
BGE
Pepco
DPL
ACE
PHI
35.0%
35.0%
35.0%
35.0%
35.0%
35.0% 35.0%
35.0%
35.0%
For the Year Ended December 31, 2015
Predecessor
3.7
1.0
4.9
1.0
5.3
6.7
1.7
5.7
(0.4)
(0.7)
—
(0.9)
(1.5)
(1.9)
0.3
(1.4)
—
32.2%
(0.8)
(1.3)
—
—
—
—
—
—
—
—
—
0.1
—
—
—
—
—
—
—
—
—
(1.5)
—
(3.4)
0.5
(2.4)
—
27.1%
(0.3)
(0.1)
—
—
—
0.2
39.7%
(0.1)
(8.7)
—
—
—
0.2
27.4%
(0.1)
(0.7)
—
—
—
—
39.6%
—
—
—
(0.1) (0.4)
(5.8) (2.3)
—
—
—
(0.5) 5.2
35.3% 39.2%
(0.6)
(1.3)
—
—
—
6.4
45.2%
467
6.6
—
—
—
(0.2)
(4.3)
—
—
—
(3.2)
33.9%
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
Increase (decrease) due to:
State income taxes, net of Federal income tax
Exelon
Generation
ComEd
PECO
BGE
Pepco
DPL
ACE
Predecessor
PHI
35.0%
35.0%
35.0%
35.0%
35.0%
35.0%
35.0%
35.0%
35.0%
For the Year Ended December 31, 2014
benefit
1.3
(1.9)
4.5
(0.1)
5.0
5.4
4.8
5.8
Qualified nuclear decommissioning trust fund
income
Domestic production activities deduction
Health care reform legislation
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
Other
Effective income tax rate
2.4
(2.0)
0.1
(1.1)
(1.9)
(2.4)
(1.8)
(2.6)
(0.2)
26.8%
4.8
(4.1)
—
—
—
0.2
—
—
—
—
—
0.2
—
—
—
—
—
—
—
—
—
(2.0)
—
(4.8)
(3.7)
(5.3)
(1.1)
16.9%
(0.3)
(0.1)
—
—
—
0.3
39.6%
(0.1)
(10.4)
—
—
—
0.1
24.5%
(0.3)
0.2
—
—
—
(0.2)
39.9%
(0.1)
(4.9)
—
—
—
(0.2)
35.2%
(0.3)
(2.4)
—
—
—
1.4
38.5%
(0.6)
(0.5)
—
—
—
(0.2)
39.5%
5.3
—
—
—
(0.3)
(4.5)
—
—
—
0.8
36.3%
(a) 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.
(b)
(c) At PECO, includes a cumulative adjustment related to an anticipated gas repairs tax return accounting method change.
(d)
Includes impacts of the PHI Global Settlement for Pepco, DPL, ACE, and PHI
The tax effects of temporary differences and carryforwards, which give rise to significant portions of the deferred tax assets (liabilities), as of
December 31, 2016 and 2015 are presented below:
As of December 31, 2016
Successor
Exelon Generation ComEd
BGE
(4,192) $ (5,034) $ (3,095) $ (1,977) $ (1,678) $ (973) $ (869) $
DPL ACE
Pepco
PECO
Plant basis differences
Accrual based contracts
Derivatives and other financial instruments
Deferred pension and postretirement obligation
Nuclear decommissioning activities
Deferred debt refinancing costs
Regulatory assets and liabilities
Tax loss carryforward
Tax credit carryforward
Investment in CENG
Other, net
Deferred income tax liabilities (net)
Unamortized investment tax credits
Total deferred income tax liabilities (net) and
unamortized investment tax credits
$ (17,966) $
434
(179)
2,287
(509)
325
(3,319)
189
446
(650)
1,485
$ (17,457) $
(115)
(162)
(316)
(509)
44
—
61
493
(650)
403
—
—
(43)
—
(3)
(240)
22
—
—
27
(4,943) $ (5,349) $ (3,005) $ (2,214) $ (1,908) $ (1,053) $ (913) $
—
(3)
(453)
—
(13)
(226)
29
—
—
351
—
—
(122)
—
(7)
(194)
27
—
—
66
—
—
(18)
—
(1)
10
—
—
—
99
—
—
(74)
—
(4)
(75)
39
—
—
34
—
—
(21)
—
(2)
(69)
14
—
—
34
PHI
(3,586)
548
(1)
(111)
—
293
(1,205)
77
—
—
225
(3,760)
(9)
(658)
(626)
(15)
(1)
(5)
(2)
(3)
(4)
$ (18,115) $
(5,569) $ (5,364) $ (3,006) $ (2,219) $ (1,910) $ (1,056) $ (917) $
(3,769)
468
Table of Contents
Combined Notes to Consolidated Financial Statements—(Continued)
(Dollars in millions, except per share data unless otherwise noted)
As of December 31, 2015
Predecessor
Plant basis differences
Accrual based contracts
Derivatives and other financial
instruments
Deferred pension and postretirement
obligation
Nuclear decommissioning activities
Deferred debt refinancing costs
Regulatory assets and liabilities
Tax loss carryforward
Tax credit carryforward
Investment in CENG
Other, net
Deferred income tax liabilities (net)
Unamortized investment tax credits
Total deferred income tax liabilities (net) and
(136)
(203)
1,801
(592)
133
(1,706)
103
327
(595)
1,112
Exelon Generation ComEd PECO BGE Pepco DPL ACE
$ (13,393) $
(4,269) $ (4,424) $ (2,901) $ (1,821) $ (1,599) $ (915) $ (791) $
—
—
—
—
—
—
(136)
PHI
(3,342)
—
(181)
(4)
—
—
—
—
—
(1)
(371)
(592)
48
—
56
374
(595)
425
(505)
—
(15)
(219)
—
—
—
270
(9)
—
(1)
16
—
—
—
105
(47)
—
(4)
(264)
33
—
—
27
(95)
—
(8)
(202)
141
—
—
42
(82)
—
(4)
(91)
122
—
—
29
(20)
—
(3)
(93)
8
—
—
18
$ (13,149) $
(5,241) $ (4,897) $ (2,790) $ (2,076) $ (1,721) $ (941) $ (881) $
(622)
(598)
(17)
(2)
(5)
(2)
(4)
(4)
(92)
—
(15)
(414)
378
6
—
103
(3,377)
(15)
unamortized investment tax credits
$ (13,771) $
(5,839) $ (4,914) $ (2,792) $ (2,081) $ (1,723) $ (945) $ (885) $
(3,392)
The following table provides the Registrants’ carryforwards and any corresponding valuation allowances as of December 31, 2016.
Exelon
Generation
ComEd PECO BGE
Pepco
DPL
ACE
Successor
PHI
Federal
Federal net operating
loss
$ 282(a) $
11
$
82 $ — $ —
$ 44
$ 38
$ 18
$
121
Deferred taxes on
Federal net operating
loss
Federal general business
credits carryforwards
State
State net operating
losses and credit
carryforwards
Deferred taxes on state
tax attributes (net)
Valuation allowance on
state tax attributes
99
4
29
— —
15
13
6
511(b)
509
1
—
1
—
—
—
42
—
3,501(c)
1,245(c)
—
— 425(d)
360(e)
639(f)
272(g)
1,522(h)
186
20
65
—
— 23
20
36
16
9
—
—
1
—
—
—
86
10
(a) Exelon’s federal net operating loss will begin expiring in 2032.
(b) Exelon’s federal general business credit carryforwards will begin expiring in 2033.
(c) Exelon’s and Generation’s state net operating losses and credit carryforwards, which are presented on a post-apportioned basis, will begin expiring in 2017.
(d) BGE’s state net operating loss carryforwards, which are presented on a post-apportioned basis, will begin expiring in 2026.
(e) Pepco’s state net operating loss carryforwards, which are presented on a post-apportioned basis, will begin expiring in 2028.
(f) DPL’s state net operating loss carryforwards, which are presented on a post-apportioned basis, will begin expiring in 2023.
(g) ACE’s state net operating loss carryforwards, which are presented on a post-apportioned basis, will begin expiring in 2032.
(h) PHI’s state net operating loss carryforwards, which are presented on a post-apportioned basis, will begin expiring in 2023.
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Combined Notes to Consolidated Financial Statements—(Continued)
(Dollars in millions, except per share data unless otherwise noted)
Tabular reconciliation of unrecognized tax benefits
The following tables provide a reconciliation of the Registrants’ unrecognized tax benefits as of December 31, 2016, 2015 and 2014:
Unrecognized tax benefits at January 1,
2016
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
Decrease from settlements with taxing
authorities
Decreases from expiration of statute of
limitations
Unrecognized tax benefits at December 31,
Exelon
Generation
ComEd
PECO
BGE
Pepco
DPL
ACE
Successor
PHI
$1,078
22
$
534
5
$ 142
—
$ —
—
$120
—
$
8
—
$
3
—
$ —
—
$
108
(332)
88
(21)
(27)
10
(12)
—
(154)
—
—
—
—
21
—
16
—
22
—
—
—
—
—
51
18
—
(20)
—
—
—
—
—
—
(27)
—
—
—
—
—
—
—
—
—
—
—
—
—
—
22
(5)
59
—
96
—
—
—
2016
$ 916
$
490
$ (12)
$ —
$120
$ 80
$ 37
$ 22
$
172
Predecessor
Exelon Generation ComEd PECO BGE Pepco DPL ACE
$1,829 $
Unrecognized tax benefits at January 1, 2015
Increases based on tax positions related to 2015
Change to positions that only affect timing
Increases based on tax positions prior to 2015
Decreases based on tax positions prior to 2015
Decrease from settlements with taxing authorities
Decreases from expiration of statute of limitations
Unrecognized tax benefits at December 31, 2015
108
(705)
79
(116)
(31)
(86)
$1,078 $
1,357 $ 149 $ 44 $ — $ — $ — $ — $
106
—
14
—
—
—
—
(659)
65
(112)
(31)
(86)
534 $ 142 $ — $120 $
—
—
—
—
—
—
3 $ — $
—
(7)
—
—
—
—
—
—
8
—
—
—
—
(44)
—
—
—
—
—
—
3
—
—
—
8 $
PHI
702
—
(688)
11
—
—
(3)
22
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Table of Contents
Combined Notes to Consolidated Financial Statements—(Continued)
(Dollars in millions, except per share data unless otherwise noted)
Predecessor
Exelon Generation ComEd PECO BGE Pepco DPL ACE
$2,175 $
Unrecognized tax benefits at January 1, 2014
Increases based on tax positions related to 2014
Change to positions that only affect timing
Increases based on tax positions prior to 2014
Decreases based on tax positions prior to 2014
Decreases from settlements with taxing authorities
Decreases from expiration of statute of limitations
Unrecognized tax benefits at December 31, 2014
15
(255)
18
(1)
(35)
(88)
$1,829 $
3 $
1,415 $ 324 $ 44 $ — $ 45 $
—
—
—
—
—
—
—
—
—
—
—
—
1,357 $ 149 $ 44 $ — $ — $ — $ — $
—
(175)
—
—
—
—
—
(45)
—
—
—
—
—
(3)
—
—
—
—
—
(3)
—
—
—
—
15
33
18
(2)
(34)
(88)
3 $
PHI
743
—
(41)
—
—
—
—
702
Exelon, Generation, and ComEd have $83 million, $7 million, and $(12) million of unrecognized tax benefits balance 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.
Exelon, Generation, and ComEd had $415 million, $20 million, and $142 million of unrecognized tax benefits at December 31, 2015 for which
the ultimate tax benefit is highly certain, but for which there is uncertainty about the timing of such benefits
Exelon, Generation, ComEd, PECO, and PHI had $1,122 million, $680 million, $149 million, $43 million, and $686 million of unrecognized tax
benefits at December 31, 2014 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.
Unrecognized tax benefits that if recognized would affect the effective tax rate
Exelon, Generation, PHI, Pepco, ACE, and DPL have $633 million, $483 million, $93 million, $21 million, $22 million, and $16 million,
respectively, of unrecognized tax benefits at December 31, 2016 that, if recognized, would decrease the effective tax rate. BGE, PHI, Pepco, and
DPL have $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.
Exelon, Generation, and PHI had $538 million, $509 million, and $11 million, respectively, of unrecognized tax benefits at December 31, 2015
that, if recognized, would decrease the effective tax rate. BGE, PHI, Pepco, and DPL had $120 million, $11 million, $8 million, and $3 million of
unrecognized tax benefits at December 31, 2015 that, if recognized, may be included in future base rates and that portion would have no impact to
the effective tax rate.
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Combined Notes to Consolidated Financial Statements—(Continued)
(Dollars in millions, except per share data unless otherwise noted)
Exelon, Generation, and PHI had $701 million, $672 million, and $15 million, respectively, of unrecognized tax benefits at December 31, 2014
that, if recognized, would decrease the effective tax rate.
Reasonably possible that total amount of unrecognized tax benefits could significantly increase or decrease within 12 months after
the reporting date
Settlement of Income Tax Audits and Litigation
As of December 31, 2016, Exelon, Generation, PHI, Pepco, ACE and DPL have approximately $146 million, $19 million, $59 million,
$21 million, $22 million and $16 million, respectively, of unrecognized federal and state tax benefits that will decrease in the first quarter of 2017 due
to the receipt in January of favorable IRS guidance as to whether certain business expenses should be capitalized or deducted. The recognition of
these unrecognized tax benefits will decrease the effective tax rate in the first quarter of 2017.
As of December 31, 2016, Exelon, Generation, BGE, PHI, Pepco, and DPL have approximately $244 million, $44 million, $120 million,
$80 million, $59 million, and $21 million, respectively, of unrecognized state tax benefits that could significantly decrease within the 12 months after
the reporting date as a result of completing audits, potential settlements, and expected statute of limitation expirations. Of the above unrecognized
tax benefits, Exelon and Generation have $44 million that, if recognized, would decrease the effective tax rate. The unrecognized tax benefit related
to BGE, Pepco, and DPL 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
December 31, 2016
December 31, 2015
Net penalties receivable (payable) as of
December 31, 2016
December 31, 2015
PHI
Net interest receivable (payable)
Net penalties receivable (payable)
Exelon Generation ComEd
46 $ (384)
$ (507)
(210)
80
(288)
$
PECO BGE
8 $ (1)
$
(1)
3
Pepco
$
DPL ACE
1 $ — $ 1
24
3
20
Exelon Generation ComEd PECO BGE Pepco DPL ACE
— $ (86) $ — $ — $ — $ — $ —
$ (106) $
—
—
—
—
—
—
—
—
Successor
December 31,
2016
$
2
—
Predecessor
December 31,
2015
$
(34)
—
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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 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, 2016
December 31, 2015
December 31, 2014
Net penalty expense (income) for the years ended
December 31, 2016
December 31, 2015
December 31, 2014
Exelon Generation ComEd PECO BGE Pepco DPL ACE
6 $ — $ (1)
$ 165 $
—
(4)
(1)
(1)
(13) $ 117 $ — $ — $
(31)
(50)
—
—
—
—
—
1
(13)
(36)
7
6
Exelon Generation ComEd PECO BGE Pepco DPL ACE
86 $ — $ — $ — $ — $ —
$ 106 $
—
—
—
—
— $
—
—
—
—
—
—
—
—
—
—
—
—
PHI
Net interest expense (income)
Net penalty expense (income)
Successor
March 24, 2016 to
December 31, 2016
(2)
$
—
January 1, 2016 to
$
March 23, 2016
—
—
Predecessor
December 31,
2015
December 31,
2014
$
(34)
—
$
—
—
Description of tax years that remain open to assessment by major jurisdiction
Taxpayer
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
Various separate company (excluding PECO) Pennsylvania corporate net income tax returns
PECO Pennsylvania separate company returns
DPL Delaware separate company returns
ACE New Jersey separate company returns
Various separate company Maryland corporate net income tax returns
Washington D.C. corporate income tax returns
Other Tax Matters
Like-Kind Exchange
Open Years
1999, 2001-2015
2013-2015
2010-2015
2010-March 2012
2011-2015
2011-2015
2010-2015
Same as Federal
2012-2015
Same as Federal
2013-2015
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 electric generation facilities which were properly leased back to the municipalities.
The IRS disagreed with this position and asserted that the entire gain of approximately $1.2 billion was taxable in 1999. Exelon was unable to
reach agreement with the IRS regarding the dispute over
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Combined Notes to Consolidated Financial Statements—(Continued)
(Dollars in millions, except per share data unless otherwise noted)
the like-kind exchange position. The IRS asserted that the Exelon purchase and leaseback transaction was substantially similar to a leasing
transaction, known as a SILO, which the IRS does not respect as the acquisition of an ownership interest in property. A SILO is a “listed transaction”
that the IRS has identified as a potentially abusive tax shelter under guidance issued in 2005. Accordingly, the IRS asserted that the sale of the fossil
plants followed by the purchase and leaseback of the municipal owned generation facilities did not qualify as a like-kind exchange and the gain on
the sale is fully subject to tax. The IRS also asserted a penalty of approximately $90 million for a substantial understatement of tax.
In accordance with applicable accounting standards, Exelon was required to assess whether it was more-likely-than-not that to prevail in
litigation. In light of the outcome of another case involving a listed transaction and Exelon’s determination that settlement was unlikely, Exelon
concluded that subsequent to December 31, 2012, it was no longer more-likely-than-not that its position would be sustained. As a result, in the first
quarter of 2013 Exelon recorded a non-cash charge to earnings of approximately $265 million, which represented the amount of interest expense
(after-tax) and incremental state income tax expense for periods through March 31, 2013, that would be payable in the event that Exelon is
unsuccessful in litigation. Of this amount, approximately $172 million was recorded at ComEd. Exelon has agreed to hold ComEd harmless from any
unfavorable impacts on ComEd’s equity of the after-tax interest or penalty amounts. As a result, ComEd recorded on its consolidated balance sheet
as of March 31, 2013, a $172 million receivable and non-cash equity contributions from Exelon. Based on applicable case law and the facts of the
transaction, Exelon did not believe it was likely a penalty would be assessed. Accordingly, no charge was recorded for the penalty asserted nor for
after-tax interest that could be due on the asserted penalty.
On September 30, 2013, the IRS issued a notice of deficiency to Exelon for the like-kind exchange position. Exelon filed a petition on
December 13, 2013 to initiate litigation in the United States Tax Court and the trial took place in August of 2015. Exelon was not required to remit
any part of the asserted tax or penalty in order to litigate the issue.
On September 19, 2016, the Tax Court rejected Exelon’s position in the case and ruled that Exelon was not entitled to defer gain on the
transaction. In addition, contrary to Exelon’s evaluation that the penalty was unwarranted, the Tax Court ruled that Exelon is liable for the penalty
and interest due on the asserted penalty. In the second quarter of 2017, Exelon expects to timely appeal this decision to the U.S. Court of Appeals
for the Seventh Circuit.
While it has strong arguments on appeal with respect to both the merits and the penalty, Exelon has determined that, pursuant to accounting
standards, it is no longer more-likely-than-not to avoid the penalty. As a result, in the third quarter of 2016, Exelon and ComEd recorded a charge to
earnings of approximately $106 million and $86 million, respectively, of penalty and approximately $94 million and $64 million, respectively, of
after-tax interest. Exelon and ComEd recorded the penalty and pre-tax interest due on the asserted penalty to Other, net and Interest expense, net,
respectively, on their Consolidated Statements of Operations. Consistent with Exelon’s agreement to continue to hold ComEd harmless from any
unfavorable impact on its equity, ComEd recorded on its Consolidated Balance Sheets as of September 30, 2016, a $150 million receivable and
non-cash equity contributions from Exelon.
In order to appeal the decision, Exelon is required to pay the tax, penalty and interest at the time Exelon files its appeal (expected in the
second quarter of 2017). While the final calculation of tax, penalty and interest has not yet been finalized by the IRS, Exelon estimates that a
payment of
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Combined Notes to Consolidated Financial Statements—(Continued)
(Dollars in millions, except per share data unless otherwise noted)
approximately $1.4 billion related to the like-kind exchange will be due, including $300 million from ComEd, in the second quarter of 2017. While
Exelon will receive a tax benefit of $400 million associated with the deduction for the interest, Exelon expects to have a net operating loss
carryforward and thus does not expect to realize the cash benefit until 2018. After taking into account these interest deduction tax benefits, the total
estimated net cash outflow for the like-kind exchange is $1 billion, of which approximately $300 million is attributable to ComEd after giving
consideration to Exelon’s agreement to hold ComEd harmless from any unfavorable impacts of after-tax interest or penalty amounts on ComEd’s
equity. Upon a final appellate decision, which could take up to several years, Exelon expects to receive $80 million related to final interest
computations.
Of the above amounts payable, Exelon deposited with the IRS approximately $1.25 billion in October of 2016. The remaining amount will be
paid in the second quarter of 2017 at the time Exelon files its appeal of the Tax Court decision. Exelon funded the $1.25 billion deposit with a
combination of cash on hand and short-term borrowings. The deposit is reflected as a current asset and the related liabilities for the tax, penalty, and
interest are included on Exelon’s balance sheet as current obligations.
As of December 31, 2016, ComEd has a total receivable from Exelon pursuant to the hold harmless agreement of $345 million, which is
included in Current Receivables from Affiliates on ComEd’s Consolidated Balance Sheet. Under the agreement, Exelon will settle this receivable with
ComEd no later than the time that the payments related to the like-kind exchange are due to the IRS, currently anticipated in the second quarter of
2017. Exelon will not seek recovery from ComEd customers for any interest or penalty amounts associated with the like-kind exchange tax position.
As previously disclosed, in the first quarter of 2014, Exelon entered into an agreement to terminate its investment in one of the three municipal-
owned electric generation properties in exchange for a net early termination amount of $335 million. On March 31, 2016, Exelon entered into an
agreement to terminate its interests in the remaining two municipal-owned electric generation properties in exchange for $360 million.
PHI Global Tax Settlement
On November 18, 2015, PHI entered into a settlement with the IRS and the DOJ (the Global Tax Settlement) to primarily provide for the
resolution of the uncertain tax treatment of its previously held cross-border energy lease investments involving public utility assets located outside of
the United States structured as sale-in, lease-out, or SILO, transactions.
As a result of the Global Tax Settlement in the fourth quarter of 2015, PHI re-measured uncertain tax positions resulting in the recognition of a
tax benefit of $35 million, including $26 million related to continuing operations and $9 million related to discontinued operations. PHI also recorded
an interest benefit, net of tax, of $21 million. Pepco recorded a tax benefit of $6 million and interest benefit, net of tax, of $3 million. ACE and DPL
recorded a tax expense of $3 million and $3 million, respectively.
Long-Term State Tax Apportionment (Exelon, Generation and PHI)
Exelon, Generation and PHI periodically review events that may significantly impact how income is apportioned among the states and,
therefore, the calculation of their respective deferred state income taxes. Events that may require Exelon, Generation and PHI to update their long-
term state tax apportionment include significant changes in tax law and/or significant operational changes, such as
475
Table of Contents
Combined Notes to Consolidated Financial Statements—(Continued)
(Dollars in millions, except per share data unless otherwise noted)
the merger with PHI. As a result of the merger, Exelon and Generation reevaluated their long-term state tax apportionment for all states where they
have state income tax obligations, which include Delaware, Illinois, Maryland, New Jersey, Pennsylvania, and Washington D.C., as well as other
states. The total effect of revising the long-term state tax apportionment resulted in the recording of deferred state tax benefit in the amount of
$1 million and $6 million, net of tax, for Exelon and Generation, respectively. Further, Exelon and PHI recorded deferred state tax liabilities of
$59 million and $8 million, net of tax, respectively, as part of purchase accounting during the first quarter of 2016. The long-term state tax
apportionment was revised in the fourth quarter of 2016 pursuant to Exelon’s long-term state tax apportionment policy, resulting in the recording of a
deferred state tax expense for Exelon and Generation of $8 million and $14 million, net of tax.
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 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, 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.
During 2015, Generation, PECO, and BGE recorded an allocation of Federal tax benefits from Exelon under the Tax Sharing Agreement of
$57 million, $16 million, and $7 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.
During 2014, Generation and PECO recorded an allocation of Federal tax benefits from Exelon under the Tax Sharing Agreement of
$55 million and $25 million, respectively. ComEd and BGE did not record an allocation of Federal tax benefits from Exelon under the Tax Sharing
Agreement as a result of tax net operating losses.
16. 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.
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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 provides a rollforward of the nuclear decommissioning ARO reflected on Exelon’s and Generation’s Consolidated Balance
Sheets, from January 1, 2015 to December 31, 2016:
Nuclear decommissioning ARO at January 1, 2015
Accretion expense
Net increase for changes in and timing of estimated future cash flows
Costs incurred related to decommissioning plants
Nuclear decommissioning ARO at December 31, 2015 (a)
Accretion expense
Net increase for changes in and timing of estimated future cash flows
Costs incurred related to decommissioning plants
Nuclear decommissioning ARO at December 31, 2016 (a)
Exelon and
Generation
6,961
$
387
901
(3)
8,246
436
61
(9)
8,734
$
(a)
Includes $10 million and $7 million as the current portion of the ARO at December 31, 2016 and 2015, respectively, which is included in Other current liabilities on
Exelon’s and Generation’s Consolidated Balance Sheets.
During 2016, Generation’s total nuclear ARO increased by approximately $488 million, primarily reflecting year-to-date accretion of the ARO
liability of approximately $436 million due to the passage of time and impacts of ARO updates completed during 2016 to reflect changes in amounts
and timing of estimated decommissioning cash flows.
The $61 million increase in the ARO during 2016 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 increases of $288 million resulting from the
change in the assumed DOE spent fuel acceptance date for disposal from 2025 to 2030 as well as increases resulting from updates to the cost
studies of Oyster Creek, Zion, Calvert Cliffs, R.E. Ginna and Nine Mile Point. These increases were partially offset by a decrease of $165 million
resulting from changes to the decommissioning scenarios and their probabilities as well as reductions in estimated cost escalation rates, primarily for
labor, energy and waste burial costs. Most of the increase to the ARO resulting from the June 2, 2016, announcement to early retire Clinton and
Quad Cities was reversed pursuant to the December 7, 2016, enactment of the Illinois FEJA. See Note 9—Early Nuclear Plant Retirements for
additional information.
The financial statement impact related to changes in the ARO, on an individual unit basis, due to the changes in, and timing of, estimated cash
flows primarily resulted in a corresponding change in the unit’s ARC within Property, plant and equipment on Exelon’s and Generation’s
Consolidated Balance Sheets. If the ARO decreases for a unit that does not have any remaining ARC, the corresponding change is recorded as a
credit to income in Operating and maintenance expense within Exelon’s and Generation’s Consolidated Statements of Operations and
Comprehensive Income. Approximately $89 million of the 2016 adjustment resulted in a credit to income, which is included in Operating and
maintenance expense within Exelon’s and Generation’s Consolidated Statements of Operations and Comprehensive Income.
During 2015, Generation’s ARO increased by approximately $1.3 billion. The increase was primarily driven by an increase of approximately
$630 million for costs expected to be incurred for required site security during the decommissioning periods in which SNF remains on-site and until
major reactor components and buildings have been dismantled and removed. This projected increase was based on emerging industry experience
at nuclear sites in the planning or early stage of decommissioning indicating greater than originally expected numbers of security personnel 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)
be on site during these decommissioning periods. Generation will continue to monitor emerging security cost trends, including potential strategies to
limit such costs by, for example, optimizing the transfer of SNF when DOE starts taking possession of SNF or increasing the use of dry SNF storage,
and will adjust the ARO liability accordingly. The 2015 increase in the ARO included an increase of approximately $285 million for the impacts of a
change implemented in the 2015 annual assessment of Generation’s SNF storage and disposal cost estimation methodology to better align the
projected timing of SNF transfers to the DOE with assumed plant shutdown dates as well as higher assumed probabilities of early retirements of
certain economically challenged nuclear plants (See Note 9—Early Nuclear Plant Retirements for additional information) and further accretion of the
obligation. These increases were partially offset by reductions in estimated cost escalation rates, primarily for labor and energy costs.
Nuclear Decommissioning Trust Fund Investments
NDT funds have been established for each generating 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. The most recent rate adjustment occurred on January 1, 2013, and the effective rates currently yield annual collections of approximately
$24 million. The next five-year adjustment is expected to be reflected in rates charged to PECO customers effective January 1, 2018. Aside from the
former PECO units, Generation does not currently collect any amounts, nor is there any mechanism by which Generation can seek to collect
additional amounts, from utility customers. Apart from the contributions made to the NDT funds from amounts previously collected from ComEd and
currently collected from PECO customers, Generation has not made contributions to the NDT funds.
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
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Combined Notes to Consolidated Financial Statements—(Continued)
(Dollars in millions, except per share data unless otherwise noted)
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 nuclear decommissioning trust 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, 2016, and 2015, Exelon and Generation had NDT fund investments totaling $11,061 million and $10,342 million,
respectively. For additional information related to the NDT fund investments, refer to Note 12—Fair Value of Financial Assets and Liabilities.
The following table provides unrealized gains on NDT funds for 2016, 2015 and 2014:
Exelon and Generation
For the Years Ended December 31,
2015
2016
2014
Net unrealized gains (losses) on decommissioning trust funds—Regulatory Agreement Units
(a)
Net unrealized gains (losses) on decommissioning trust funds—Non-Regulatory Agreement
Units (b)(c)
$
216
$
(282)
$
180
194
(197)
134
(a) Net unrealized gains (losses) related to Generation’s NDT funds associated with Regulatory Agreement Units are included in Regulatory liabilities on Exelon’s
Consolidated Balance Sheets and Noncurrent payables to affiliates on Generation’s Consolidated Balance Sheets.
(b) Excludes $(1) million, $7 million and $29 million of net unrealized gains (losses) related to the Zion Station pledged assets in 2016, 2015 and 2014, respectively. Net
unrealized gains related to Zion Station pledged assets are included in the Payable for Zion Station decommissioning on Exelon’s and Generation’s Consolidated Balance
Sheets.
(c) Net unrealized gains (losses) 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.
Interest and dividends on NDT fund investments are recognized when earned and are included in Other, net in Exelon’s and Generation’s
Consolidated Statements of Operations and Comprehensive Income. Interest and dividends earned on the NDT fund investments for the Regulatory
Agreement Units are eliminated within Other, net in Exelon’s and Generation’s Consolidated Statement of Operations and Comprehensive Income.
Accounting Implications of the Regulatory Agreements with ComEd and PECO . Based on the regulatory agreement with the ICC that dictates
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, as long as funds held in the NDT funds are expected to exceed the total estimated decommissioning obligation, 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
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Combined Notes to Consolidated Financial Statements—(Continued)
(Dollars in millions, except per share data unless otherwise noted)
and Generation’s Consolidated Statements of Operations and Comprehensive Income. 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 and an adjustment to the regulatory liabilities at Exelon. Likewise, ComEd has 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 results of operations and
financial position could be material. As of December 31, 2016, 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.
Based on the regulatory agreement supported by the PAPUC that dictates Generation’s rights and obligations related to the shortfall or excess
of trust funds necessary for decommissioning the former PECO units, regardless of whether the funds held in the NDT funds are expected to exceed
or fall short of the total estimated decommissioning obligation, 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 Statement of Operations and Comprehensive Income results in an equal adjustment to the noncurrent payables to affiliates at
Generation and an adjustment to the regulatory liabilities at Exelon. Likewise, PECO has recorded an equal noncurrent affiliate receivable from
Generation and a corresponding regulatory liability. 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 results of operations and financial position 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.
Refer to Note 3—Regulatory Matters and Note 27—Related Party Transactions for information regarding regulatory liabilities at ComEd and
PECO and intercompany balances between Generation, ComEd and PECO reflecting the obligation to refund to customers any decommissioning-
related assets in excess of the related decommissioning obligations.
Zion Station Decommissioning
On September 1, 2010, Generation completed an Asset Sale Agreement (ASA) with EnergySolutions Inc. and its wholly owned subsidiaries,
EnergySolutions, LLC (EnergySolutions) and ZionSolutions under which ZionSolutions has assumed responsibility for decommissioning Zion Station,
which is located in Zion, Illinois and ceased operation in 1998. Specifically, 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
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Combined Notes to Consolidated Financial Statements—(Continued)
(Dollars in millions, except per share data unless otherwise noted)
dispose of SNF and decommission the SNF dry storage facility, 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 its decommissioning efforts at Zion Station. During
2013, EnergySolutions entered a definitive acquisition agreement and was acquired by another Company. Generation reviewed the acquisition as it
relates to the ASA to decommission Zion Station. Based on that review, Generation determined that the acquisition will not adversely impact
decommissioning activities under the ASA.
ZionSolutions is subject to certain restrictions on its ability to request reimbursements from the Zion Station NDT funds as defined within the
ASA. Therefore, the transfer of the Zion Station assets did not qualify for asset sale accounting treatment and, as a result, the related NDT funds
were reclassified to Pledged assets for Zion Station decommissioning 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. Additionally, the transferred ARO for decommissioning
was replaced with a Payable for Zion Station decommissioning in Generation’s and Exelon’s Consolidated Balance Sheets. Changes in the value of
the Zion Station NDT assets, net of applicable taxes, will be 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 approximately $111 million, which is included within the nuclear decommissioning ARO at
December 31, 2016. 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 the
pledged assets and payables to ZionSolutions, and withdrawals by ZionSolutions at December 31, 2016 and 2015:
Carrying value of Zion Station pledged assets
Payable to Zion Solutions (a)
Current portion of payable to Zion Solutions (b)
Cumulative withdrawals by Zion Solutions to pay decommissioning costs (c)
Exelon and Generation
2016
113
$
104
90
878
2015
206
$
189
99
786
(a) Excludes a liability recorded within Exelon’s and Generation’s Consolidated Balance Sheets related to the tax obligation on the unrealized activity associated with the Zion
Station NDT Funds. The NDT Funds will be utilized to satisfy the tax obligations as gains and losses are realized.
Included in Other current liabilities within Exelon’s and Generation’s Consolidated Balance Sheets.
Includes project expenses to decommission Zion Station and estimated tax payments on Zion Station NDT fund earnings.
(b)
(c)
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
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Combined Notes to Consolidated Financial Statements—(Continued)
(Dollars in millions, except per share data unless otherwise noted)
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 $173 million in
November 2016 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.
NRC Minimum Funding Requirements
NRC regulations require that licensees of nuclear generating facilities demonstrate reasonable assurance that funds will be available in
specified minimum amounts to decommission the facility at the end of its life. The estimated decommissioning obligations as calculated using the
NRC methodology differ from the ARO recorded on 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, 2016 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 Oyster Creek); (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, 2016 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 four 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 5.3% to 5.9% (as compared to a historical 5-year annual average pre-tax return of approximately 8%).
482
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Combined Notes to Consolidated Financial Statements—(Continued)
(Dollars in millions, except per share data unless otherwise noted)
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 position may be
significantly adversely affected.
Generation filed its biennial decommissioning funding status report with the NRC on March 31, 2015. This report reflects the status of
decommissioning funding assurance for all units as of December 31, 2014. Due to increased cost estimates received in the second half of 2014,
Braidwood Unit 1, Braidwood Unit 2, and Byron Unit 2 did not meet the NRC’s minimum funding assurance criteria as of December 31, 2014. NRC
guidance provides licensees with two years or by the time of submitting the next biennial report (on or before March 31, 2017) to resolve funding
assurance shortfalls. On February 4, 2016, Generation submitted an updated decommissioning funding status report with the NRC for Braidwood
Units 1 and 2, and Byron Unit 2. This report reflected the approved license renewals for these units, and showed adequate decommissioning funding
assurance for each of the three units.
On March 31, 2016, Generation submitted its NRC required annual decommissioning funding status report as of December 31, 2015 for
reactors that have been shut down or are within five years of shut down (Dresden Unit 1, Oyster Creek, Zion and Peach Bottom Unit 1), except for
Zion Station which is included in a separate report to the NRC submitted by EnergySolutions (see Zion Station Decommissioning above). The status
report demonstrated adequate decommissioning funding assurance for all these 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. As
discussed under Nuclear Decommissioning Trust Fund Investments above, the amount collected from PECO ratepayers will be adjusted in the next
filing to the PAPUC with new rates effective January 1, 2018.
Generation will file its next decommissioning funding status report with the NRC by March 31, 2017. This report will reflect the status of
decommissioning funding assurance as of December 31, 2016.
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. PHI and 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.
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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 rollforward of the non-nuclear AROs reflected on the Registrants’ Consolidated Balance Sheets from January 1,
2015 to December 31, 2016:
Non-nuclear AROs at
January 1, 2015
Net (decrease) increase due to changes in, and timing
of, estimated future cash flows (a)
Development projects (b)
Accretion expense (c)
Sale of generating assets (d)
Payments
Non-nuclear AROs at December 31, 2015 (e)
Merger with PHI (g)
Net increase (decrease) due to changes in, and timing
of, estimated future cash flows (a)
Development projects (b)
Accretion expense (c)
Sale of generating assets (d)
Payments
Non-nuclear AROs at December 31, 2016 (e)
Non-nuclear AROs at January 1, 2015
Accretion expense (c)
Non-nuclear AROs at December 31, 2015
Non-nuclear AROs at March 23, 2016
Exelon Generation ComEd PECO BGE
Pepco DPL ACE
Successor
PHI (f)
$ 346 $
194 $ 104 $ 30 $ 18 $ — $ — $ — $ —
(10)
10
16
(2)
(5)
355
8
34
11
18
(22)
(11)
(12)
10
10
(2)
(3)
197
1
6
—
5
—
(2)
113
—
8
11
10
(22)
(6)
4
—
7
—
(3)
(4)
—
1
—
—
27
—
1
—
1
—
(1)
—
—
—
—
—
18
—
7
—
—
—
(1)
$ 393 $
199 $ 121 $ 28 $ 24 $
—
—
—
—
—
—
—
—
—
—
—
—
—
—
2
—
—
—
—
14
—
—
—
—
14 $
—
—
—
—
—
—
—
9
—
—
—
—
—
—
—
—
—
—
—
3
—
—
—
—
3
2 $
9 $
Predecessor
PHI (f)
$
$
$
7
1
8
8
(a) During the year ended December 31, 2016, Generation recorded an increase of $1 million in Operating and maintenance expense. ComEd, PECO and BGE did not
record any adjustments in Operating and maintenance expense for the year ended December 31, 2016. During the year ended December 31, 2015, Generation recorded
a decrease of $(2) million in Operating and maintenance expense. ComEd, PECO and BGE did not record any adjustments in Operating and maintenance expense for the
year ended December 31, 2015.
(b) Relates to new AROs recorded due to the construction of solar, wind and other non-nuclear generating sites.
(c) For ComEd, PECO, and BGE, the majority of the accretion is recorded as an increase to a regulatory asset due to the associated regulatory treatment.
(d) Reflects a reduction to the ARO resulting primarily from the sales of the New Boston generating site and Upstream business in 2016 and Schuylkill generating station in
2015. See Note 4—Mergers, Acquisitions, and Dispositions for further information.
(e) Excludes $1 million, $2 million and $3 million as the current portion of the ARO at December 31, 2016 for Generation, ComEd and BGE, respectively. Excludes $5 million,
$2 million and $1 million as the current portion of the ARO at December 31, 2015 for Generation, ComEd and BGE, respectively. This is included in Other current liabilities
on the Registrants’ respective Consolidated Balance Sheets.
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Combined Notes to Consolidated Financial Statements—(Continued)
(Dollars in millions, except per share data unless otherwise noted)
(f)
For PHI, the successor period includes activity for the period of March 24, 2016 through December 31, 2016. The PHI predecessor periods include activity for the year
ended December 31, 2015 and the period January 1, 2016 through March 23, 2016.
(g) Following the completion of the PHI merger on March 23, 2016, PHI’s AROs related to its unregulated business interests were transferred to Exelon and Generation.
17. Retirement Benefits (All Registrants)
As of December 31, 2016, Exelon sponsored defined benefit pension plans and other postretirement benefit plans for essentially all
employees.
Effective March 23, 2016, Exelon became the sponsor of all of PHI’s defined benefit pension and other postretirement benefit plans, and
assumed PHI’s benefit plan obligations and related assets. As a result, PHI’s benefit plan net obligation and related regulatory assets were
transferred to Exelon and remeasured at the merger date using current assumptions, including discount rates.
The table below shows the pension and other postretirement benefit plans in which employees of each operating company participated at
December 31, 2016.
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)
485
Operating Company (e)
Generation ComEd PECO BGE BSC PHI Pepco DPL ACE
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)
Name of Plan:
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)
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)
Pepco Holdings LLC Welfare Plan for Retirees (d)
Operating Company (e)
Generation ComEd PECO BGE BSC PHI Pepco DPL ACE
X
X
X
X
X
X
X
X
X
X X
X X
X
X
X
X
X X X
X X
X
X
X
X
X X X
X
X
X
X
X
X
X
X
X
X X X
X X X
X X X
X X X
X X
X
X
X X X
X
X
X
X
X
X
X X
X X
X
X
X X X
(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.
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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 traditional and cash balance pension plans are intended to be tax-qualified defined benefit plans. Substantially all non-union
employees and electing union employees hired on or after January 1, 2001 participate in cash balance pension plans. Effective January 1, 2009,
substantially all newly-hired union-represented employees participate in cash balance pension plans. 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 2016, Exelon received an updated valuation of its legacy Exelon, CEG and CENG pension and other postretirement
benefit obligations to reflect actual census data as of January 1, 2016. This valuation resulted in an increase to the pension obligation of $35 million
and a decrease to the other postretirement benefit obligation of $8 million. Additionally, accumulated other comprehensive loss increased by
approximately $2 million (after tax), regulatory assets increased by approximately $27 million, and regulatory liabilities increased by approximately
$3 million.
The legacy PHI pension and other postretirement benefit plans were initially remeasured on February 29, 2016 as a result of the short time
between the merger close and the end of the first quarter of 2016, using current assumptions, including the discount rate. Exelon updated these
amounts in the second quarter of 2016 to reflect assumptions at March 31, 2016 resulting in a $25 million reduction in the net obligation.
487
Table of Contents
Combined Notes to Consolidated Financial Statements—(Continued)
(Dollars in millions, except per share data unless otherwise noted)
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:
Net benefit obligation at beginning of year
Service cost
Interest cost
Plan participants’ contributions
Actuarial (gain) loss
Plan amendments
Acquisitions/divestitures (a)
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
Acquisitions/divestitures (a)
Settlements
Fair value of net plan assets at end of year
Pension Benefits
Other
Postretirement Benefits
2016(b)
2015
2016(b)
2015
$17,753
354
830
—
567
(60)
2,667
—
(1,051)
$21,060
$ 18,256
326
710
—
(582)
—
—
(34)
(923)
$ 17,753
$ 3,938
107
185
54
(136)
—
589
—
(280)
$ 4,457
$
$
4,197
119
167
42
(341)
(23)
—
—
(223)
3,938
Pension Benefits
2016(b)
2015
Other
Postretirement Benefits
2015
2016(b)
$14,347
1,061
347
—
(1,051)
2,087
—
$16,791
$ 14,874
(32)
462
—
(923)
—
(34)
$ 14,347
$ 2,293
128
50
54
(280)
333
—
$ 2,578
$
$
2,430
4
40
42
(223)
—
—
2,293
488
Table of Contents
Combined Notes to Consolidated Financial Statements—(Continued)
(Dollars in millions, except per share data unless otherwise noted)
PHI
Change in benefit obligation:
Net benefit obligation at beginning of the period
Service cost
Interest cost
Actuarial (gain) loss
Gross benefits paid
Net benefit obligation at end of the period
PHI
Change in plan assets:
Fair value of net plan assets at beginning of the period
Actual return on plan assets
Employer and plan participant contributions
Gross benefits paid by plan
Fair value of net plan assets at end of the period
Pension Benefits
Predecessor
Other
Postretirement Benefits
January 1,
2016 to
March 23,
2016
$
$
2,490
12
26
(30)
(2)
2,496
2015
$2,638
57
109
(151)
(163)
$2,490
January 1,
2016 to
March 23,
2016
$
$
563
1
6
(5)
(1)
564
2015
$
$
632
7
24
(61)
(39)
563
Pension Benefits
Predecessor
Other
Postretirement Benefits
January 1,
2016 to
March 23,
2016
$
$
2,018
—
4
(2)
2,020
2015
$ 2,236
(61)
6
(163)
$ 2,018
January 1,
2016 to
March 23,
2016
$
$
348
—
1
(1)
348
2015
$
$
367
1
5
(25)
348
(a) Effective March 23, 2016, Exelon became the sponsor of PHI’s defined benefit pension and other postretirement benefit plans.
(b) 2016 amounts include PHI for the period of March 24, 2016 through December 31, 2016.
Exelon and PHI present their benefit obligations and plan assets net on their balance sheet within the following line items:
Other
Exelon
Other current liabilities
Pension obligations
Non-pension postretirement benefit obligations
Unfunded status (net benefit obligation less plan assets)
Pension Benefits
2016(a)
$
21
4,248
—
$4,269
2015
$
21
3,385
—
$ 3,406
489
Postretirement Benefits
2015
27
$
—
1,618
1,645
2016(a)
$
31
—
1,848
$ 1,879
$
Table of Contents
Combined Notes to Consolidated Financial Statements—(Continued)
(Dollars in millions, except per share data unless otherwise noted)
PHI
Other current liabilities
Pension obligations
Non-pension postretirement benefit obligations
Unfunded status (net benefit obligation less plan assets)
Pension
Benefits
Predecessor
2015
$
$
6
466
—
472
Other
Postretirement Benefits
Predecessor
2015
$
$
—
—
215
215
(a) Effective March 23, 2016, Exelon became the sponsor of PHI’s defined benefit pension and other postretirement benefit plans, and assumed PHI’s benefit plan obligations
and related assets.
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
2016
$21,060
16,791
2015
$17,753
14,347
Exelon
2016
$21,060
19,930
16,791
2015
$17,753
16,792
14,347
Predecessor
PHI
2015
$
2,490
2,018
Predecessor
PHI
2015
$
2,490
2,275
2,018
On a PBO basis, the Exelon plans were funded at 80% and 81% at December 31, 2016 and December 31, 2015, respectively, and the PHI
plans were funded at 81% at December 31, 2015. On an ABO basis, the Exelon plans were funded at 84% and 85% at December 31, 2016 and
December 31, 2015, respectively, and the PHI plans were funded at 89% at December 31, 2015. 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 2016 pension benefit cost for the legacy Exelon, CEG and CENG plans is calculated using an expected long-term rate of
return on plan assets of 7.00% and a discount rate of 4.29%. The majority of the 2016 other postretirement benefit cost for the legacy Exelon, CEG
and CENG plans is calculated using an expected long-term rate of return on plan assets of 6.71% for funded plans and a discount rate of 4.29%.
The majority of the 2016 pension benefit cost of the legacy PHI plans is calculated using an expected long-term rate of return on plan assets of
6.50% and a discount rate of 3.96%. The 2016 other postretirement benefit cost for the legacy PHI plan is calculated using an expected long-term
rate of return on plan assets of 6.75% and a discount rate of 3.80%.
490
Table of Contents
Combined Notes to Consolidated Financial Statements—(Continued)
(Dollars in millions, except per share data unless otherwise noted)
A portion of the net periodic benefit cost for all pension and OPEB plans is capitalized within each of the Registrants’ Consolidated Balance
Sheets. The following tables present the components of Exelon’s net periodic benefit costs, prior to any capitalization, for the years ended
December 31, 2016, 2015 and 2014 and the components of PHI’s predecessor net periodic benefit costs, prior to any capitalization, for the years
ended December 31, 2015 and 2014, and the period 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 (b)
Net periodic benefit cost
(a) 2016 amounts include PHI for the period of March 24, 2016 through December 31, 2016.
(b) 2016 amount includes an additional termination benefit for PHI.
Pension Benefits
Other
Postretirement Benefits
2016 (a)
2015
2014
2016 (a)
2015
2014
$
354
830
(1,141)
$
326
710
(1,026)
14
554
2
613
13
571
2
596
$
$
$ 293
749
(994)
14
420
2
$ 484
$ 107
185
(162)
(185)
63
—
8
$
$ 119
167
(151)
(174)
80
—
$ 41
$ 117
186
(154)
(122)
50
—
$ 77
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
Predecessor
January 1,
2016 to
March 23,
2016
Pension Benefits
For the Year
Ended
December 31,
2015
For the Year
Ended
December 31,
2014
Other
Postretirement Benefits
January 1,
2016 to
March 23,
2016
For the Year
Ended
December 31,
2015
For the Year
Ended
December 31,
2014
$
$
12 $
26
(30)
—
14
22 $
491
57 $
109
(140)
2
65
93 $
44 $
109
(141)
2
45
59 $
1 $
6
(5)
(3)
2
1 $
7 $
24
(22)
(13)
8
4 $
7
26
(24)
(13)
3
(1)
Table of Contents
Combined Notes to Consolidated Financial Statements—(Continued)
(Dollars in millions, except per share data unless otherwise noted)
Components of AOCI and Regulatory Assets
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, 2016,
2015 and 2014 for all plans combined and the components of PHI’s predecessor AOCI and regulatory assets (liabilities) for the years ended
December 31, 2015 and 2014, and 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 loss (gain)
Amortization of actuarial loss
Current year prior service (credit) cost
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
2016 (a)
2015
2014
2016 (a)
2015
2014
(571)
—
(13)
(2)
—
(554)
(60)
(14)
—
994
$ 644 $ 476 $1,639 $ (101) $(194) $
(420)
—
(14)
(2)
—
561
(50)
(1,012)
122
—
—
$ 1,010 $(110) $1,203 $ 115 $(123) $ (379)
20 $ (63) $ (162)
$
51 $ (64) $ 788 $
95 $ (60) $ (217)
$ 959 $ (46) $ 415 $
(63)
—
185
—
94
(80)
(23)
174
—
—
PHI
Changes in plan assets and benefit obligations recognized
in AOCI and regulatory assets (liabilities):
Predecessor
January 1,
2016 to
March 23,
2016
Pension Benefits
For the Year
Ended
December 31,
2015
For the Year
Ended
December 31,
2014
Other
Postretirement Benefits
January 1,
2016 to
March 23,
2016
For the Year
Ended
December 31,
2015
For the Year
Ended
December 31,
2014
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)
$
— $
(14)
—
(14) $
(1) $
(13) $
492
50 $
(65)
(2)
(17) $
(11) $
(6) $
276 $
(45)
(2)
229 $
17 $
212 $
— $
(2)
3
1 $
— $
1 $
(39) $
(8)
13
(34) $
— $
(34) $
62
(3)
13
72
—
72
Table of Contents
Combined Notes to Consolidated Financial Statements—(Continued)
(Dollars in millions, except per share data unless otherwise noted)
(a) 2016 amounts include PHI for the period of March 24, 2016 through December 31, 2016.
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, 2016 and 2015, respectively, for all plans combined:
Prior service cost (credit)
Actuarial loss
Total (a)
Total included in AOCI
Total included in regulatory assets (liabilities)
2016 (a)
$
(31)
8,387
$ 8,356
$ 4,297
$ 4,059
$
Pension Benefits
2015
$
36
7,310
$7,346
$4,246
$3,100
$
$
$
Exelon
PHI
2015
6
910
916
46
870
Predecessor
Exelon
Predecessor
PHI
2015
Other
Postretirement Benefits
2015
$(812)
711
$(101)
$ (63)
$ (38)
2016 (a)
$ (710)
724
14
(42)
56
$
$
$
$
$
$
$
(88)
128
40
—
40
(a) Effective March 23, 2016, Exelon became the sponsor of PHI’s defined benefit pension and other postretirement benefit plans, and assumed PHI’s benefit plan obligations
and related assets.
The following table provides the impact to Exelon’s AOCI and regulatory assets (liabilities) at December 31, 2016 as a result of the
components of periodic benefit costs that are expected to be amortized in 2017. These estimates are subject to the completion of an actuarial
valuation of Exelon’s pension and other postretirement benefit obligations, which will reflect actual census data as of January 1, 2017 and actual
claims activity as of December 31, 2016. The valuation is expected to be completed in the first quarter of 2017 for the majority of the benefit plans.
Prior service cost (credit)
Actuarial loss
Total (a)
Pension Benefits
1
$
605
606
$
Other
Postretirement Benefits
(188)
$
55
(133)
$
(a) Of the $606 million related to pension benefits at December 31, 2016, $297 million and $309 million are expected to be amortized from AOCI and regulatory assets in
2017, respectively. Of the $(133) million related to other postretirement benefits at December 31, 2016, $(70) million and $(63) million are expected to be amortized from
AOCI and regulatory assets (liabilities) in 2017, respectively.
Assumptions
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.
493
Table of Contents
Combined Notes to Consolidated Financial Statements—(Continued)
(Dollars in millions, except per share data unless otherwise noted)
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. For the December 31, 2014 actuarial valuation, Exelon changed its assumption of mortality to reflect more recent expectations of
future improvements in life expectancy. The change was supported through completion of an experience study and supplemental analyses
performed by Exelon’s actuaries. The change in assumption resulted in increases of $361 million and $117 million in the pension and other
postretirement benefits obligations as of December 31, 2014, respectively. There were no changes to the mortality assumption in 2015 or 2016.
The following assumptions were used to determine the benefit obligations for the plans at December 31, 2016, 2015 and 2014. 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
Rate of compensation increase
Mortality table
Health care cost trend on covered
charges
2016
Pension Benefits
2015
2014
2016
Other Postretirement Benefits
2015
2014
4.04% (a)
(d)
4.29% (b)
(d)
3.94% (c)
(d)
4.04% (a)
(d)
4.29% (b)
(d)
3.92% (c)
(d)
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
N/A
494
RP-2000
table
projected to
2012 with
improvement
scale AA, with
Scale BB-2D
improvements
(adjusted)
5.50% with
ultimate
trend of
5.00% in
2017
RP-2000
table
projected to
2012 with
improvement
scale AA, with
Scale BB-2D
improvements
(adjusted)
5.50%
decreasing to
ultimate trend
of 5.00% in
2017
RP-2000
table
projected to
2012 with
improvement
scale AA, with
Scale BB-2D
improvements
(adjusted)
6.00%
decreasing to
ultimate trend
of 5.00% in
2017
Table of Contents
PHI
Discount rate
Rate of compensation
increase
Mortality table
Health care cost trend on covered charges
Combined Notes to Consolidated Financial Statements—(Continued)
(Dollars in millions, except per share data unless otherwise noted)
Predecessor
Pension Benefits
Predecessor
Other
Postretirement Benefits
January 1,
2016 to
March 23,
2016 (e)
2015
2014
January 1,
2016 to
March 23,
2016 (e)
4.65% / 4.55% (f)
4.20%
5.00%
5.00%
RP-2014
table with
improvement
scale
MP-2015
RP-2014
table with
improvement
scale
MP-2014
N/A
N/A
2015
2014
4.55%
5.00%
4.15%
5.00%
RP-2014
table with
improvement
scale
MP-2015
RP-2014
table with
improvement
scale
MP-2014
6.33%
pre-65 and
5.40%
post-65
decreasing
to ultimate
trend of
5.00% in
2020
6.67%
pre-65 and
5.50%
post-65
decreasing
to ultimate
trend of
5.00% in
2020
(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, 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.
(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, 2015. Certain benefit plans used individual rates ranging from 3.68% - 4.14% and 4.32% - 4.43% 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, 2014. Certain benefit plans used individual rates ranging from 3.29% - 3.82% and 3.99% - 4.06% for pension and other postretirement plans, respectively.
(d) 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.
(e) Obligation was not remeasured during this period.
(f)
The discount rate for the qualified and nonqualified pension plans was 4.65% and 4.55%, respectively.
The following assumptions were used to determine the net periodic benefit costs for the plans for the years ended December 31, 2016, 2015
and 2014, as well as for the PHI predecessor period January 1, 2016 to March 23, 2016:
Exelon
Discount rate
Expected return on plan assets
Rate of compensation increase
Mortality table
Health care cost trend on covered
charges
2016
Pension Benefits
2015
2014
2016
Other Postretirement Benefits
2015
2014
4.29% (a)
7.00% (d)
(e)
3.94% (b)
7.00% (d)
(e)
4.80% (c)
7.00% (d)
(f)
4.29% (a)
6.71% (d)
(e)
3.92% (b)
6.50% (d)
(e)
4.90% (c)
6.59% (d)
(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)
RP-2000
table with
Scale AA
improvements
N/A
N/A
N/A
495
RP-2000
table
projected to
2012 with
improvement
scale AA, with
Scale BB-2D
improvements
(adjusted)
5.50%
decreasing to
ultimate trend
of 5.00% in
2017
RP-2000
table
projected to
2012 with
improvement
scale AA, with
Scale BB-2D
improvements
(adjusted)
6.00%
decreasing to
ultimate trend
of 5.00% in
2017
RP-2000
table with
Scale AA
improvements
6.00%
decreasing to
ultimate trend
of 5.00% in
2017
Table of Contents
Combined Notes to Consolidated Financial Statements—(Continued)
(Dollars in millions, except per share data unless otherwise noted)
PHI
Discount rate
Expected return on plan assets (g)
Rate of compensation increase
Mortality table
Health care cost trend on covered charges
Predecessor
Pension Benefits
Predecessor
Other
Postretirement Benefits
January 1,
2016 to
March 23,
2016
4.65% / 4.55% (h)
6.50%
5.00%
2015
2014
4.20%
6.50%
5.00%
5.05%
7.00%
5.00%
January 1,
2016 to
March 23,
2016
4.55%
6.75%
5.00%
2015
2014
4.15%
6.75%
5.00%
5.00%
7.25%
5.00%
RP-2014
table with
improvement
scale
MP-2015
RP-2014
table with
improvement
scale
MP-2014
2014
Mortality
tables
prescribed
by the
Pension
Protection
Act of
2006
N/A
N/A
N/A
RP-2014
table with
improvement
scale
MP-2015
RP-2014
table with
improvement
scale
MP-2014
6.33%
pre-65 and
5.40%
post-65
decreasing
to ultimate
trend of
5.00% in
2020
6.67%
pre-65 and
5.50%
post-65
decreasing
to ultimate
trend of
5.00% in
2020
2014
Mortality
tables
prescribed
by the
Pension
Protection
Act of
2006
7.00%
pre-65
and
5.60%
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, 2016. Certain benefit plans used individual rates ranging from 3.68%-4.14% and 4.32%-4.43% 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, 2015. Certain benefit plans used individual rates ranging from 3.29%-3.82% and 3.99%-4.06% 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, 2014. Certain of the other postretirement benefit plans were remeasured as of April 30, 2014 using an expected long-term rate of return on plan assets of
6.59% and a discount rate of 4.30%. Costs for the year ended December 31, 2014 reflect the impact of this remeasurement. On April 1, 2014, Generation assumed
operational control of CENG’s nuclear fleet. As a result, Exelon became the sponsor of CENG’s legacy pension and OPEB plans effective July 14, 2014; discount rates for
those plans, impacting 2014 costs, ranged from 3.60%-4.30% and 4.09%-4.55%, respectively. See Note 5 - Investment in Constellation Energy Nuclear Group, LLC for
further information.
(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)
3.25% through 2018 and 3.75% thereafter.
(g) Expected return on other postretirement benefit plan assets is pre-tax.
(h) The discount rate for the qualified and nonqualified pension plans was 4.65% and 4.55%, 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)
Assumed health care cost trend rates impact the other postretirement benefit plan costs reported for Exelon’s participant populations with plan
designs that do not have a cap on cost growth. A one percentage point change in assumed health care cost trend rates would have the following
effects:
Effect of a one percentage point increase in assumed health care cost trend:
on 2016 total service and interest cost components
on postretirement benefit obligation at December 31, 2016
Effect of a one percentage point decrease in assumed health care cost trend:
on 2016 total service and interest cost components
on postretirement benefit obligation at December 31, 2016
Contributions
The following tables provide contributions to the pension and other postretirement benefit plans:
$
9
105
(8)
(95)
Exelon
Generation
ComEd
PECO
BGE
BSC (b)
Pepco
DPL
ACE
PHISCO (c)
2016
(a)
$ 347
140
33
30
31
39
24
22
15
17
Pension Benefits
2015
(a)
$ 462
231
143
40
1
47
—
—
—
—
2014
(a)
$ 332
173
122
11
—
26
—
—
—
—
Other Postretirement Benefits
2016
50
$
12
5
—
18
3
8
—
2
2
2015
40
$
14
7
—
16
3
2
—
3
—
2014
$ 291
124
125
5
17
20
1
—
3
—
Successor
March 24,
2016 to
December 31,
2016
Pension Benefits
January 1,
2016 to
March 23,
2016
Predecessor
For the Year
Ended
December 31,
2015
For the Year
Ended
December 31,
2014
Successor
March 24,
2016 to
December 31,
2016
Other Postretirement Benefits
January 1,
2016 to
March 23,
2016
Predecessor
For the Year
Ended
December 31,
2015
For the Year
Ended
December 31,
2014
PHI
$
74
$
4 $
— $
— $
12
$
— $
5 $
4
(a) Exelon’s and Generation’s pension contributions include $25 million, $36 million and $43 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, 2016, 2015 and 2014, respectively.
Includes $6 million, $5 million, and $9 million of pension contributions funded by Exelon Corporate, for the years ended December 31, 2016, 2015, and 2014, respectively.
(b)
(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). Additionally, the projected contribution reflects a funding strategy for the
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Table of Contents
Combined Notes to Consolidated Financial Statements—(Continued)
(Dollars in millions, except per share data unless otherwise noted)
legacy Exelon, CEG and CENG plans of contributing the greater of $250 million until 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. Contributions to the PHI qualified pension plan are $60 million.
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 2017:
Exelon
Generation
ComEd
PECO
BGE
PHI
Pepco
DPL
ACE
Qualified
Pension Plans
(a)
Non-Qualified
Pension Plans
(b)
Other
Postretirement
Benefits (c)
$
310
127
33
23
38
60
60
—
—
$
23
6
1
1
2
8
1
—
—
$
44
12
2
—
16
12
10
—
—
(a) Exelon’s and Generation’s expected qualified pension plan contributions above include $21 million related to the legacy CENG plans that will be funded by CENG as
provided in an EMA between Exelon and CENG.
(b) Unlike the qualified pension plans, Exelon’s non-qualified pension plans are not funded.
(c) Unlike the qualified pension plans, other postretirement plans are not subject to statutory minimum contribution requirements. OPEB funding generally follows 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). These amounts include benefit payments related to unfunded plans.
Estimated Future Benefit Payments
Estimated future benefit payments to participants in all of the pension plans and postretirement benefit plans at December 31, 2016 were:
2017
2018
2019
2020
2021
2022 through 2026
Total estimated future benefit payments through 2026
Allocation to Exelon Subsidiaries
Pension
Benefits
$ 1,360
1,170
1,191
1,223
1,275
6,791
$13,010
Other
Postretirement
Benefits
$
$
244
250
256
263
272
1,456
2,741
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
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Table of Contents
Combined Notes to Consolidated Financial Statements—(Continued)
(Dollars in millions, except per share data unless otherwise noted)
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 CENG, 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 were included in capital expenditures and operating and maintenance expense for the years ended December 31, 2016,
2015 and 2014, respectively, for each of the entities allocated portion of the pension and other postretirement benefit plan costs. These amounts
include the recognized contractual termination benefit charges, curtailment gains, and settlement charges:
For the Year Ended
December 31,
2016 (b)
2015
2014
Exelon Generation ComEd PECO BGE
$ 621 $
637
561
218 $ 166 $ 33 $ 68 $ 48 $ 31 $ 18 $ 15 $
269
250
206
162
39
36
15
13
66
67
57
46
15
7
30
22
47
37
16
BSC
(a) Pepco DPL ACE
PHISCO
(a)
PHI
Pension and Other Postretirement
Benefit Costs
Successor
March 24, 2016 to
December 31,
2016
January 1, 2016 to
March 23,
2016
For the Year Ended
December 31, 2015
For the Year Ended
December 31, 2014
Predecessor
$
88
$
23
$
97
$
58
(a) These amounts primarily represent amounts billed to Exelon’s subsidiaries through intercompany allocations. These amounts are not included in the Generation, ComEd,
PECO, BGE, Pepco, DPL or ACE amounts above.
(b) 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.
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.
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Table of Contents
Combined Notes to Consolidated Financial Statements—(Continued)
(Dollars in millions, except per share data unless otherwise noted)
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.
Exelon used an EROA of 7.00% and 6.60% to estimate its 2017 pension and other postretirement benefit costs, respectively.
Exelon’s pension and other postretirement benefit plan target asset allocations at December 31, 2016 and 2015 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
Target Allocation
33%
39%
28%
Exelon
Predecessor
PHI
Percentage of Plan Assets
at December 31,
2016
33%
39
28
100%
2015
35%
34
31
100%
2015
28%
66
6
100%
Target Allocation
43%
28%
29%
Exelon
Predecessor
PHI
Percentage of Plan Assets
at December 31,
2016
47%
29
24
100%
2015
43%
27
30
100%
2015
63%
34
3
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, 2016. 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, 2016, 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 on the Registrants’
Consolidated Balance Sheets on a recurring basis and their level within the fair value hierarchy at December 31, 2016 and 2015:
Exelon
At December 31, 2016 (a)(d)
Pension plan assets
Cash equivalents
Equities (b)
Fixed income:
U.S. Treasury and agencies
State and municipal debt
Corporate debt
Other (b)
Fixed income subtotal
Private equity
Hedge funds
Real estate
Private credit
Pension plan assets subtotal
At December 31, 2016 (a)(d)
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
Other postretirement benefit plan assets subtotal
Total pension and other postretirement benefit plan assets (c)
501
Level 1
Level 2
Level 3
Not subject to
leveling
Total
$ 325
3,144
$ —
—
$ —
2
$
—
2,535
$
325
5,681
1,008
—
—
—
1,008
—
—
—
—
$4,477
192
64
3,641
340
4,237
—
—
—
—
$4,237
—
—
206
—
206
—
—
—
—
$ 208
$
—
—
—
748
748
991
1,962
828
833
7,897
1,200
64
3,847
1,088
6,199
991
1,962
828
833
$16,819
Level 1
Level 2
Level 3
Not subject to
leveling
Total
$
24
547
$ —
2
$ —
—
$
—
644
$
24
1,193
9
—
—
256
265
—
—
—
$ 836
$5,313
59
134
43
60
296
—
—
—
$ 298
$4,535
—
—
—
—
—
—
—
—
$ —
$ 208
$
$
—
—
—
131
131
445
117
107
1,444
9,341
68
134
43
447
692
445
117
107
$ 2,578
$19,397
Table of Contents
Combined Notes to Consolidated Financial Statements—(Continued)
(Dollars in millions, except per share data unless otherwise noted)
At December 31, 2015 (a)
Pension plan assets
Cash equivalents
Equities (b)
Fixed income:
U.S. Treasury and agencies
State and municipal debt
Corporate debt
Other (b)
Fixed income subtotal
Private equity
Hedge funds
Real estate
Private credit
Pension plan assets subtotal
At December 31, 2015 (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
Other postretirement benefit plan assets subtotal
Total pension and other postretirement benefit plan assets (c)
502
Level 1
Level 2
Level 3
Not subject to
leveling
Total
$ 210
3,571
$ —
—
$ —
2
$
—
1,462
$
210
5,035
1,001
—
—
—
1,001
—
—
—
—
$4,782
79
61
2,901
146
3,187
—
—
—
—
$3,187
—
—
165
—
165
—
—
—
—
$ 167
$
—
—
—
452
452
924
1,924
725
699
6,186
1,080
61
3,066
598
4,805
924
1,924
725
699
$14,322
Level 1
Level 2
Level 3
Not subject to
leveling
Total
$
15
510
$ —
2
$ —
—
$
—
480
$
15
992
11
—
—
155
166
—
—
—
$ 691
$5,473
53
131
44
59
287
—
—
—
$ 289
$3,476
—
—
—
—
—
—
—
—
$ —
$ 167
$
$
—
—
—
146
146
451
131
103
1,311
7,497
64
131
44
360
599
451
131
103
$ 2,291
$16,613
Combined Notes to Consolidated Financial Statements—(Continued)
(Dollars in millions, except per share data unless otherwise noted)
Table of Contents
PHI
Pension plan assets
Cash equivalents
Equities
Fixed income:
U.S. Treasury and agencies
State and municipal debt
Corporate debt securities
Other
Fixed income subtotal
Private equity
Real estate
Pension plan assets subtotal
Predecessor
December 31, 2015 (a)
Level 1
Level 2
Level 3
Not subject to
leveling
50
$
335
$ —
—
$ —
—
$
114
—
—
—
114
—
—
$ 499
15
18
625
40
698
—
—
$ 698
—
—
—
—
—
—
—
$ —
$
—
224
—
—
—
504
504
38
46
812
Predecessor
December 31, 2015 (a)
Level 1
Level 2
Level 3
Not subject to
leveling
$
8
197
121
$ 326
$ 825
$ —
—
—
$ —
$ 698
$ —
—
—
$ —
$ —
$
$
$
—
22
—
22
834
Total
$
50
559
129
18
625
544
1,316
38
46
$2,009
Total
$
8
219
121
$ 348
$2,357
PHI
Other postretirement benefit plan assets
Cash equivalents
Equities
Fixed income—other
Other postretirement benefit plan assets subtotal
Total pension and other postretirement benefit plan assets (e)
(a) See Note 12—Fair Value of Financial Assets and Liabilities for a description of levels within the fair value hierarchy.
(b)
Includes derivative instruments of $1 million and $5 million, which have a total notional amount of $2,918 million and $1,774 million at December 31, 2016 and 2015,
respectively. The notional principal amounts for these instruments provide one measure of the transaction volume outstanding as of the fiscal years ended and do not
represent the amount of the company’s exposure to credit or market loss.
(c) Excludes net liabilities of $28 million and net assets of $27 million at December 31, 2016 and 2015, respectively, which are required to reconcile to the fair value of net
plan assets. These items consist primarily of receivables related to pending securities sales, interest and dividends receivable, and payables related to pending securities
purchases.
(d) Effective March 23, 2016, Exelon became sponsor of PHI’s defined benefit pension and other postretirement benefit plans, and assumed PHI’s benefit plan obligations
and related assets.
(e) Excludes net assets of $9 million at December 31, 2015, which are required to reconcile to the fair value of net plan assets. These items consist primarily of receivables
related to pending securities sales, interest and dividends receivable, and payables related to pending securities purchased.
503
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, 2016 and 2015:
Exelon
Pension Assets
Balance as of January 1, 2016
Actual return on plan assets:
Relating to assets still held at the reporting date
Purchases, sales and settlements:
Purchases
Sales
Settlements (a)
Balance as of December 31, 2016
Pension Assets
Balance as of January 1, 2015
Actual return on plan assets:
Relating to assets still held at the reporting date
Purchases, sales and settlements:
Purchases
Settlements (a)
Balance as of December 31, 2015
(a) Represents cash settlements only.
Fixed
income
Equities
Total
$ 165
$
2
$167
(2)
—
(2)
69
(14)
(12)
$ 206
Fixed
income
—
—
—
2
$
69
(14)
(12)
$208
Equities
Total
$ 120
$
2
$122
(8)
—
(8)
61
(8)
$ 165
—
—
2
$
61
(8)
$167
There were no significant transfers between Level 1 and Level 2 during the year ended December 31, 2016 for the pension and other
postretirement benefit plan assets.
Valuation Techniques Used to Determine Fair Value
Cash equivalents . Investments with 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 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
504
Table of Contents
Combined Notes to Consolidated Financial Statements—(Continued)
(Dollars in millions, except per share data unless otherwise noted)
by these exchanges. Equity securities are valued based on quoted prices in active 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 that hold certain investments 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, 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 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.
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Table of Contents
Combined Notes to Consolidated Financial Statements—(Continued)
(Dollars in millions, except per share data unless otherwise noted)
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 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. The
fair value of private credit investments is 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 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, 2016, 2015 and 2014:
For the Year Ended
December 31,
2016
2015
2014
Exelon (a) Generation (a) ComEd PECO BGE BSC (b) Pepco (c) DPL (c) ACE PHISCO (c)
6
$
6
6
34 $ 10 $ 12 $
32
26
2 $ 2 $
2
2
1
2
164 $
148
103
19 $
11
10
79 $
80
51
3 $
3
3
11
8
14
8
PHI
Saving Plan Matching Contributions
Successor
March 24, 2016 to
December 31, 2016
10
$
506
January 1, 2016 to
March 23, 2016
3
$
Predecessor
For the Year
Ended
December 31,
2015
For the Year
Ended
December 31,
2014
$
14
$
13
Table of Contents
Combined Notes to Consolidated Financial Statements—(Continued)
(Dollars in millions, except per share data unless otherwise noted)
(a)
Includes $13 million, $9 million and $5 million related to CENG for the years ended December 31, 2016, December 31, 2015 and for the period from April 1, 2014 to
December 31, 2014, respectively.
(b) These amounts primarily represent amounts billed to Exelon’s subsidiaries through intercompany allocations. These costs are not included in the Generation, ComEd,
PECO, or BGE 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 at December 31, 2016.
18. 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.
Ongoing Severance Plans
The Registrants provide severance and health and welfare benefits under Exelon’s ongoing severance benefit plans to terminated employees
in the normal course of business. These benefits are accrued for when the benefits are considered probable and can be reasonably estimated.
For the years ended December 31, 2016 and 2015, the Registrants recorded the following severance costs associated with ongoing severance
benefits within Operating and maintenance expense in their Consolidated Statements of Operations and Comprehensive Income:
Year ended December 31,
2016
2015
PHI (a)
Severance Benefits
Exelon
Generation (a)
ComEd (a)
PECO (a)
BGE (a)
$
19
18
$
13
15
$
3
2
$
1
—
$
1
1
Successor
Predecessor
March 24, 2016 to
December 31, 2016
January 1, 2016 to
March 23, 2016
For the Year
Ended
December 31,
2015
$
1
$
—
$
—
(a) The amounts above for Generation, ComEd, PECO, BGE and PHI include immaterial amounts billed by BSC for the years ended December 31, 2016 and 2015.
Early Plant Retirement-Related Severance
On December 7, 2016 the Future Energy Jobs Bill was signed into law by the Governor of Illinois and included a ZES. With the passage of the
IL ZES, Generation reversed its decision to permanently cease generation operations at the Clinton and Quad Cities nuclear generating plants and
expects the
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Combined Notes to Consolidated Financial Statements—(Continued)
(Dollars in millions, except per share data unless otherwise noted)
plants to continue operation for at least another 10 years. As a result, Exelon and Generation reversed the associated severance benefit costs of
$44 million in December 2016 which were previously recorded for expected employee severances.
Cost Management Program-Related Severance
In August 2015, Exelon announced a cost management program focused on cost savings at BSC and Generation, including the elimination of
approximately 500 positions. 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. Exelon expects that approximately 250
corporate support positions in BSC and approximately 250 positions located throughout Generation will be eliminated. The final amount of the
severance charges related to the cost management program will ultimately depend on the specific employees severed.
For the year ended December 31, 2016, the Registrants recorded the following severance costs related to the cost management program
within Operating and maintenance expense in their Consolidated Statements of Operations and Comprehensive Income, pursuant to the
authoritative guidance for ongoing severance plans:
Severance benefits (a)
Exelon
23
$
Generation
18
$
ComEd
3
$
PECO
1
$
BGE
$ 1
(a) The amounts above for Generation, ComEd, PECO and BGE include $7 million, $3 million, $1 million, and $1 million, respectively, for amounts billed by BSC through
intercompany allocations for the year ended December 31, 2016.
Severance Costs Related to the PHI Merger
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 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, pursuant to the
authoritative guidance for ongoing severance plans:
Severance benefits (a)
Exelon Generation
9
$
$
57
ComEd
2
$
PECO
1
$
BGE
$ 1
Successor
PHI
$
44
Pepco (b)
21
$
DPL (c)
13
$
ACE
$ 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 for the year ended December 31, 2016.
(b) Pepco established a regulatory asset of $11 million as of December 31, 2016, primarily for severance benefit costs related to the PHI merger.
(c) DPL established a regulatory asset of $4 million as of December 31, 2016, primarily for severance benefit costs related to the PHI merger.
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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 and exclude amounts
included at Exelon and billed through intercompany allocations:
Severance Liability
Balance at December 31, 2014
Severance charges
Payments
Balance at December 31, 2015
Severance charges (a)
Payments
Balance at December 31, 2016
Severance Liability
Balance at December 31, 2014
Severance charges
Payments
Balance at December 31, 2015
Exelon Generation ComEd PECO BGE
$
50 $
16
(31)
35 $
99
(46)
88 $
$
$
34 $
10
(21)
23 $
22
(9)
36 $
Successor
PHI (b)
2 $ — $
2 $ — $
—
2
(1)
—
3 $ — $
—
2
(2)
—
3 $ — $ — $
Pepco DPL ACE
1 $ — $ —
—
—
(1)
—
1 $ — $ — $ — $ —
—
56
(27)
—
29 $ — $ — $ —
—
(1)
—
(1)
—
—
—
—
1
(1)
1
(1)
Predecessor
PHI (b)
$
$
3
—
(3)
—
(a)
Includes salary continuance and health and welfare severance benefits. Amounts primarily represent benefits provided for the PHI post-merger integration and the cost
management program.
(b) For PHI, the successor period includes activity for the period from March 24, 2016 through December 31, 2016. The PHI predecessor periods include activity for the year
ended December 31, 2015 and the period January 1, 2016 through March 23, 2016. There was no activity in the 2016 PHI predecessor period.
19. Mezzanine Equity (Exelon, Generation and PHI)
Contingently Redeemable Noncontrolling Interests (Exelon and Generation)
In November 2015, 2015 ESA Investco, LLC, a wholly owned subsidiary of Generation, entered into an arrangement to sell a portion of its
equity to a tax equity investor. Pursuant to the operating agreement, in certain circumstances the equity contributed by the noncontrolling interests
holder could be contingently redeemable. These circumstances are outside of the control of Generation and the noncontrolling interests holder
resulting in a portion of the noncontrolling interests being considered contingently redeemable and thus presented in mezzanine equity on the
consolidated balance sheet.
The following table summarizes the changes in the contingently redeemable noncontrolling interests for the years ended December 31, 2016
and 2015:
Balance at December 31, 2014
Cash received from noncontrolling interests
Release of contingency
Balance at December 31, 2015
Cash received from noncontrolling interests
Release of contingency
Balance at December 31, 2016
509
Contingently Redeemable NCI
—
$
32
(4)
28
129
(157)
—
$
$
Table of Contents
Preferred Stock (PHI)
Combined Notes to Consolidated Financial Statements—(Continued)
(Dollars in millions, except per share data unless otherwise noted)
In connection with the PHI Merger Agreement, Exelon purchased 18,000 originally issued shares of PHI preferred stock for a purchase price of
$180 million. PHI excluded the preferred stock from equity at December 31, 2015 since the preferred stock contained conditions for redemption that
were not solely within the control of PHI. Management determined that the preferred stock contained embedded features requiring separate
accounting consideration to reflect the potential value to PHI that any issued and outstanding preferred stock could be called and redeemed at a
nominal par value upon a termination of the merger agreement under certain circumstances due to the failure to obtain required regulatory
approvals. The embedded call and redemption features on the shares of the preferred stock in the event of such a termination were separately
accounted for as derivatives. As of December 31, 2015, the fair value of the derivative related to the preferred stock was estimated to be $18 million
based on PHI’s updated assessment and was included in current assets with a corresponding increase in preferred stock on the Consolidated
Balance Sheet. Immediately prior to the merger date, PHI updated its assessment of the fair value of the derivative and reduced the fair value to
zero, recording the $18 million decrease in fair value as a reduction of Other, within PHI’s predecessor period, January 1, 2016 to March 23, 2016,
Statements of Operations and Comprehensive Income.
On March 23, 2016, the preferred stock was cancelled and the $180 million cash consideration previously received by PHI to issue the
preferred stock was treated as additional merger purchase price consideration.
20. Shareholders’ Equity (Exelon, ComEd, PECO, BGE, PHI, Pepco, DPL and ACE)
The following table presents common stock authorized and outstanding as of December 31, 2016 and 2015:
Common Stock
Exelon
ComEd
PECO
BGE
PHI Predecessor
Pepco
DPL
ACE
Par Value
Shares Authorized
Shares Outstanding
December 31,
2016
2015
no par value
$12.50
no par value
no par value
$ 0.01
$ 0.01
$ 2.25
$ 3.00
2,000,000,000
250,000,000
500,000,000
175,000,000
400,000,000
200,000,000
1,000
25,000,000
924,035,059
127,017,157
170,478,507
1,000
n/a
100
1,000
8,546,017
919,924,742
127,016,973
170,478,507
1,000
254,289,261
100
1,000
8,546,017
ComEd had 72,859 and 73,434 warrants outstanding to purchase ComEd common stock at December 31, 2016 and 2015, 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, 2016 and 2015, 24,286 and 24,478 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
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Table of Contents
Combined Notes to Consolidated Financial Statements—(Continued)
(Dollars in millions, except per share data unless otherwise noted)
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. See Note 14—Debt and Credit Agreements for further 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, 35 million shares of common stock are held as treasury stock with a cost of $2.3 billion at December 31, 2016. During 2016,
2015 and 2014, Exelon had no common stock repurchases.
Preferred and Preference Securities of Subsidiaries
At December 31, 2016 and 2015, Exelon was authorized to issue up to 100,000,000 shares of preferred securities, none of which were
outstanding.
At December 31, 2016 and 2015, 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.
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. At
December 31, 2016 and 2015, BGE cumulative preference stock, $100 par value, consisted of 6,500,000 shares authorized and the outstanding
amounts set forth in the table below. Shares of BGE preference stock have no voting power except for the following:
•
The preference stock has one vote per share on any charter amendment that i) with regards to either dividends or distribution of assets,
would create or authorize any shares of stock ranking prior to or on a parity with the preference stock or ii) substantially adversely affect
the contract rights, as expressly set forth in BGE’s charter, of the preference stock. Each such amendment would require the affirmative
vote of two-thirds of all the shares of preference stock outstanding; and
•
Whenever BGE fails to pay full dividends on the preference stock and such failure continues for one year, the preference stock shall have
one vote per share on all matters, until and
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Table of Contents
Combined Notes to Consolidated Financial Statements—(Continued)
(Dollars in millions, except per share data unless otherwise noted)
unless such dividends shall have been paid in full. Upon liquidation, the holders of the preference stock of each series outstanding are
entitled to receive the par amount of their shares and an amount equal to the unpaid accrued dividends.
Series (without mandatory redemption)
7.125%, 1993 Series
6.97%, 1993 Series
6.70%, 1993 Series
6.99%, 1995 Series
Total preference stock
Redemption
Price (a)
$
100.00
100.00
100.00
100.00
2016
2015
2016
2015
December 31,
Shares Outstanding
Dollar
Amount
—
—
—
—
—
400,000
500,000
400,000
600,000
1,900,000
$ —
—
—
—
$ —
$ 40
50
40
60
$190
(a) Redeemable, at the option of BGE, at the indicated dollar amounts per share, plus accrued and unpaid dividends.
21. 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, 2016, there were approximately 14 million shares authorized for issuance under the LTIP. For the years ended
December 31, 2016, 2015 and 2014, exercised and distributed stock-based awards were primarily issued from authorized but unissued common
stock shares.
Beginning in 2014, ComEd, PECO and BGE 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 accounting 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.
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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 stock-based compensation expense included in Exelon’s and PHI’s Consolidated Statements of Operations
and Comprehensive Income for the years ended December 31, 2016, 2015 and 2014, as well as for the PHI 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,
2016
(a)
$ 93
75
—
7
175
(68)
$107
2015
$ 41
71
1
6
119
(46)
$ 73
2014
$ 59
61
2
5
127
(47)
$ 80
(a) 2016 amounts include expense related to stock-based compensation granted to eligible PHI employees since the merger date of March 23, 2016.
PHI
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
January 1 to
March 23,
2016
$
$
2
1
—
3
(1)
2
Predecessor
Years Ended
December 31,
2015
$ 7
5
1
13
(5)
$ 8
2014
5
$
8
5
18
(7)
$ 11
The following tables present the Registrants’ stock-based compensation expense (pre-tax) for the years ended December 31, 2016, 2015 and
2014, as well as for the PHI predecessor period January 1, 2016 to March 23, 2016:
Subsidiaries
Exelon
Generation
ComEd
PECO
BGE
BSC (a)
PHI (a)(b)
Years Ended
December 31,
2016
$175
78
8
3
1
81
7
2015
$119
64
6
3
3
43
13
2014
$127
52
7
3
5
60
18
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Table of Contents
PHI
Combined Notes to Consolidated Financial Statements—(Continued)
(Dollars in millions, except per share data unless otherwise noted)
Successor
March 24 to
December 31,
2016
$
4
Predecessor
January 1 to
March 23,
2016
$
3
Years Ended
December 31,
2015
$ 13
2014
$ 18
(a) These amounts primarily represent amounts billed to Exelon’s subsidiaries through intercompany allocations. These amounts are not included in the Generation, ComEd,
PECO, BGE or PHI amounts above.
(b) Pepco’s, DPL’s and ACE’s stock-based compensation expense for the year ended December 31, 2016 and for the period January 1, 2016 through March 23, 2016 was
not material. PHI’s stock-based compensation expense for the year ended December 31, 2016 includes $3 million of costs incurred prior to the closing of Exelon’s merger
with PHI on March 23, 2016.
There were no significant stock-based compensation costs capitalized during the years ended December 31, 2016, 2015 and 2014 for Exelon
or PHI, or for PHI during the predecessor period January 1, 2016 to March 23, 2016.
Exelon and PHI receive 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 and PHI recognize the
tax benefit related to compensation costs. The following tables present information regarding Exelon’s and PHI’s tax benefits for the years ended
December 31, 2016, 2015 and 2014 and PHI’s predecessor period January 1, 2016 to March 23, 2016:
Exelon
Realized tax benefit when exercised/distributed:
Restricted stock units
Performance share awards
PHI
Realized tax benefit when exercised/distributed:
Time-based restricted stock units
Performance-based restricted stock units
Time-based restricted stock awards
Stock Options
Years Ended December 31,
2015
2016
2014
$ 27
18
$ 30
18
$ 17
11
Predecessor
January 1 to
March 23,
2016
Years Ended
December 31,
2015
2014
$
—
—
—
$
2
5
—
$ 3
4
1
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 2014, 2015 or 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. As of
December 31, 2016 all stock options are fully vested. All stock options expire 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.
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Table of Contents
Combined Notes to Consolidated Financial Statements—(Continued)
(Dollars in millions, except per share data unless otherwise noted)
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, 2016:
Balance of shares outstanding at December 31, 2015
Options exercised
Options forfeited
Options expired
Balance of shares outstanding at December 31, 2016
Exercisable at December 31, 2016 (a)
(a)
Includes stock options issued to retirement eligible employees.
Weighted
Average
Exercise
Price
(per
share)
$ 46.68
22.12
—
58.60
$ 46.23
$ 46.23
Shares
15,572,757
(840,672)
—
(2,200,494)
12,531,591
12,531,591
Weighted
Average
Remaining
Contractual
Life
(years)
Aggregate
Intrinsic
Value
3.50
3.50
$
$
13
13
The following table summarizes additional information regarding stock options exercised for the years ended December 31, 2016, 2015 and
2014:
Intrinsic value (a)
Cash received for exercise price
Years Ended
December 31,
2016
$ 11
19
2015
$ —
—
2014
$ 3
7
(a) The difference between the market value on the date of exercise and the option exercise price.
The following table summarizes Exelon’s nonvested stock option activity for the year ended December 31, 2016:
Nonvested at December 31, 2015 (a)
Vested
Nonvested at December 31, 2016 (a)
Shares
82,250
(82,250)
—
Weighted Average
Exercise Price
(per share)
$
$
39.81
39.81
—
(a) Excludes 279,000 of stock options issued to retirement-eligible employees as of December 31, 2015 as they are fully vested. As of December 31, 2016, all stock options
are fully vested.
At December 31, 2016, there was no unrecognized compensation costs related to nonvested stock options.
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Restricted Stock Units
Combined Notes to Consolidated Financial Statements—(Continued)
(Dollars in millions, except per share data unless otherwise noted)
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 uses historical data to estimate employee
forfeitures, which are compared to actual forfeitures on a quarterly basis and adjusted as necessary.
The following tables summarize Exelon’s and PHI’s nonvested restricted stock unit activity for the year ended December 31, 2016 and PHI’s
for the predecessor period January 1, 2016 to March 23, 2016:
Exelon
Nonvested at December 31, 2015 (a)
Granted
Vested
Forfeited
Undistributed vested awards (b)
Nonvested at December 31, 2016 (a)(c)
PHI
Nonvested at December 31, 2015
Granted
Vested
Forfeited
Nonvested at March 23, 2016
Shares
3,563,254
3,042,184
(1,797,536)
(85,940)
(897,546)
3,824,416
Weighted Average
Grant Date Fair
Value (per share)
32.92
$
28.14
32.44
30.08
28.35
30.49
$
Time-based
Shares
628,514
152,928
—
—
781,442
Weighted Average
Grant Date Fair
Value (per share)
24.71
$
26.01
—
—
24.96
$
Performance-
based Shares
408,638
$
305,856
(4,950)
(1,238)
708,306
$
Weighted Average
Grant Date Fair
Value (per share)
18.56
$
25.41
26.08
26.08
21.45
$
(a) Excludes 1,319,372 and 975,116 of restricted stock units issued to retirement-eligible employees as of December 31, 2016 and 2015, respectively, as they are fully
vested.
(b) Represents restricted stock units that vested but were not distributed to retirement-eligible employees during 2016.
(c) 2016 amounts include activity related to stock-based compensation granted to eligible PHI employees since the merger date of March 23, 2016.
For Exelon, the weighted average grant date fair value (per share) of restricted stock units granted for the years ended December 31, 2016,
2015 and 2014 was $28.14, $36.55 and $28.71, 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)
At December 31, 2016 and 2015, Exelon had obligations related to outstanding restricted stock units not yet settled of $101 million and $97 million,
respectively, which are included in common stock in Exelon’s Consolidated Balance Sheets. For the years ended December 31, 2016, 2015 and
2014, Exelon settled restricted stock units with fair value totaling $68 million, $75 million and $43 million, respectively. At December 31, 2016,
$58 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 years.
For PHI, the weighted average grant date fair value (per share) of time-based restricted stock units granted for the years ended December 31,
2015 and 2014 was $27.40 and $19.77, respectively, and for performance-based restricted stock units was $26.08 and $18.53 for the same periods,
respectively. At December 31, 2015 PHI had obligations related to outstanding time-based and performance-based restricted stock units not yet
settled of $1 million each, which are included in common stock in PHI’s Consolidated Balance Sheet. For the years ended December 31, 2015 and
2014, PHI settled time-based restricted stock units with fair value totaling $6 million and $8 million, respectively, and settled performance-based
restricted stock units with fair value totaling $15 million and $9 million, for the same periods, respectively. There were no settled restricted stock units
for the predecessor period January 1, 2016 to March 23, 2016.
Performance Share Awards
Performance share awards are granted under the LTIP. The performance share awards are being 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 may be settled 100% in
common stock, 100% in cash or 50%in common stock and 50% in cash if certain ownership requirements are satisfied.
The common stock portion of the performance share is considered an equity award and is valued based on Exelon’s stock price on the grant
date. The cash portion of the awards is considered a liability award which is remeasured each reporting period based on Exelon’s current stock
price. As the value of the common stock and cash portions of the awards are based on Exelon’s stock price during the performance period, coupled
with changes in the total shareholder return modifier and expected payout of the award, the compensation costs are subject to volatility until payout
is established.
For nonretirement-eligible employees, stock-based compensation costs are recognized over the vesting period of three years using the
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.
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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 summarize Exelon’s and PHI’s nonvested performance share awards activity for the year ended December 31, 2016 and
PHI’s for the predecessor period January 1, 2016 to March 23, 2016:
Exelon
Nonvested at December 31, 2015 (a)
Granted
Change in performance
Vested
Forfeited
Undistributed vested awards (b)
Nonvested at December 31, 2016 (a)
PHI
Nonvested at December 31, 2015
Vested
Nonvested at March 23, 2016
Shares (c)
2,557,159
2,319,407
627,303
(949,315)
(70,876)
(1,367,417)
3,116,261
Weighted Average
Grant Date Fair
Value (per share)
31.88
$
28.85
30.04
31.31
30.90
28.33
30.77
$
Time-based
Shares
54,165
—
54,165
Weighted Average
Grant Date Fair
Value (per share)
26.80
$
—
26.80
$
Performance-
based Shares
24,717
(24,717)
—
Weighted Average
Grant Date Fair
Value (per share)
26.10
$
26.10
—
$
(a) Excludes 2,443,409 and 1,817,883 of performance share awards issued to retirement-eligible employees as of December 31, 2016 and 2015, respectively, as they are
fully vested.
(b) Represents performance share awards that vested but were not distributed to retirement-eligible employees during 2016.
(c) 2016 amounts include PHI for the period of March 24, 2016 through December 31, 2016.
For Exelon, the weighted average grant date fair value (per share) of performance share awards granted during the years ended
December 31, 2016, 2015 and 2014 was $28.85, $35.88, and $28.75, respectively. During the years ended December 31, 2016, 2015 and 2014,
Exelon settled performance shares with a fair value totaling $45 million, $46 million and $27 million, respectively, of which $28 million, $29 million
and $13 million was paid in cash, respectively. As of December 31, 2016, $51 million of total unrecognized compensation costs related to nonvested
performance shares are expected to be recognized over the remaining weighted-average period of 2 years.
For PHI, the weighted average grant date fair value (per share) of time-based restricted stock awards granted for the year ended
December 31, 2014 was $26.80 and for performance-based restricted stock awards was $26.10 and $27.01 for the years ended December 31, 2015
and 2014, respectively. There were no time-based restricted stock awards granted for the year ended December 31, 2015. At December 31, 2015
PHI had no obligations related to vested time-based and performance-based restricted stock awards not yet settled. For the year ended
December 31, 2014 PHI settled time-based shares with a fair value totaling $3 million. There were no time-based share settlements for the year-
ended December 31, 2015 or the predecessor period January 1, 2016 to March 23, 2016 or performance-based share settlements for the
predecessor period January 1, 2016 to March 23, 2016 and the years ended December 31, 2015 and 2014.
518
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 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.
(c) Excludes $8 million of common stock for PHI at December 31, 2015.
December 31,
2016
$ 49
52
40
$141
2015 (c)
28
$
32
35
95
$
22. Earnings Per Share (Exelon)
Diluted earnings per share is calculated by dividing Net income attributable to common shareholders by the weighted average number of
shares of common stock outstanding, including shares to be issued upon exercise of stock options, performance share awards and restricted stock
outstanding under Exelon’s LTIPs considered to be common stock equivalents. The following table sets forth the components of basic and diluted
earnings per share and shows the effect of the stock options, performance share awards and restricted stock 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
Years Ended December 31,
2016
$1,134
924
3
927
2015
$2,269
890
3
893
2014
$1,623
860
4
864
The number of stock options not included in the calculation of diluted common shares outstanding due to their antidilutive effect was
approximately 12 million in 2016, 16 million in 2015, and 17 million in 2014. 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 year ended December 31, 2016. The number of equity units
related to the PHI merger not included in the calculation of diluted common shares outstanding due to their antidilutive effect were 3 million and less
than 1 million for the years ended December 31, 2015 and 2014. Refer to Note 20—Shareholders’ Equity for further information regarding the equity
units and equity forward units.
Under share repurchase programs, 35 million shares of common stock are held as treasury stock with a cost of $2.3 billion as of December 31,
2016. In 2008, Exelon management decided to defer indefinitely any share repurchases.
519
Table of Contents
Combined Notes to Consolidated Financial Statements—(Continued)
(Dollars in millions, except per share data unless otherwise noted)
23. Changes in Accumulated Other Comprehensive Income (Exelon, Generation, PECO and PHI)
The following tables present changes in accumulated other comprehensive income (loss) (AOCI) by component for the years ended
December 31, 2016 and 2015:
For the Year Ended December 31, 2016
Exelon (a)
Beginning balance
OCI before reclassifications
Amounts reclassified from AOCI (b)
Net current-period OCI
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
PHI Predecessor (a)
Beginning balance January 1, 2016
OCI before reclassifications
Amounts reclassified from AOCI (b)
Net current-period OCI
Ending balance March 23, 2016 (c)
Gains and
(Losses) on
Cash Flow
Hedges
Unrealized
Gains on
Marketable
Securities
Pension and
Non-Pension
Postretirement
Benefit Plan
Items
Gains and
(Losses) on
Foreign
Currency
Items
AOCI of
Equity
Investments
Total
$
$
$
$
$
$
$
$
(19)
(6)
8
2
(17)
(21)
(6)
8
2
(19)
—
—
—
—
—
(8)
—
—
—
(8)
$
$
$
$
$
$
$
$
3
1
—
1
4
1
1
—
1
2
1
—
—
—
1
—
—
—
—
—
$
$
$
$
$
$
$
$
520
(2,565)
(182)
137
(45)
(2,610)
—
—
—
—
—
—
—
—
—
—
(28)
—
1
1
(27)
$
$
$
$
$
$
$
$
(40)
5
5
10
(30)
(40)
5
5
10
(30)
—
—
—
—
—
—
—
—
—
—
$
$
$
$
$
$
$
$
(3)
(4)
—
(4)
(7)
(3)
(4)
—
(4)
(7)
—
—
—
—
—
—
—
—
—
—
$(2,624)
(186)
150
(36)
$(2,660)
$
$
(63)
(4)
13
9
(54)
$
1
—
—
—
1
$
$
(36)
—
1
1
(35)
$
Table of Contents
For the Year Ended December 31, 2015
Exelon (a)
Beginning balance
OCI before reclassifications
Amounts reclassified from AOCI (b)
Net current-period OCI
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
PHI Predecessor (a)
Beginning balance
OCI before reclassifications
Amounts reclassified from AOCI (b)
Net current-period OCI
Ending balance
Combined Notes to Consolidated Financial Statements—(Continued)
(Dollars in millions, except per share data unless otherwise noted)
Gains and
(Losses) on
Cash Flow
Hedges
Unrealized
Gains on
Marketable
Securities
Pension and
Non-Pension
Postretirement
Benefit Plan
items
Gains and
(Losses) on
Foreign
Currency
Items
AOCI of
Equity
Investments
Total
$
$
$
$
$
$
$
$
(28)
(12)
21
9
(19)
(18)
(8)
5
(3)
(21)
—
—
—
—
—
(9)
—
1
1
(8)
$
$
$
$
$
$
$
$
3
—
—
—
3
1
—
—
—
1
1
—
—
—
1
—
—
—
—
—
$
$
$
$
$
$
$
$
(2,640)
(100)
175
75
(2,565)
—
—
—
—
—
—
—
—
—
—
(37)
5
4
9
(28)
$
$
$
$
$
$
$
$
(19)
(21)
—
(21)
(40)
(19)
(21)
—
(21)
(40)
—
—
—
—
—
—
—
—
—
—
$
$
$
$
$
$
$
$
—
(3)
—
(3)
(3)
—
(3)
—
(3)
(3)
—
—
—
—
—
—
—
—
—
—
$(2,684)
(136)
196
60
$(2,624)
(36)
(32)
5
(27)
(63)
$
$
1
—
—
—
1
$
$
$
(46)
5
5
10
(36)
(a) All amounts are net of tax and noncontrolling interests. Amounts in parenthesis represent a decrease in accumulated other comprehensive income.
(b) See next tables for details about these reclassifications.
(c) As a result of the PHI Merger, the PHI predecessor balances at March 23, 2016 were reduced to zero on March 24, 2016 due to purchase accounting adjustments applied
to PHI.
521
Table of Contents
Combined Notes to Consolidated Financial Statements—(Continued)
(Dollars in millions, except per share data unless otherwise noted)
ComEd, PECO, BGE, Pepco, DPL and ACE did not have any reclassifications out of AOCI to Net income during the years ended
December 31, 2016 and 2015. The following tables present amounts reclassified out of AOCI to Net income for Exelon, Generation and PHI during
the years ended December 31, 2016 and 2015:
For the Year Ended December 31, 2016
Details about AOCI components
Items reclassified out of AOCI (a)
Affected line item in the Statements of
Operations and Comprehensive Income
Gains and (losses) on cash flow hedges
Other cash flow hedges
Total before tax
Tax benefit
Net of tax
Amortization of pension and other
postretirement benefit plan items
Prior service costs (b)
Actuarial losses (b)
Total before tax
Tax benefit
Net of tax
Gains and (losses) of FX
Gains
Other
Total before tax
Tax benefit
Net of tax
Total Reclassifications
Exelon
Generation
$
$
$
$
$
$
$
(13)
(13)
5
(8)
78
(302)
(224)
87
(137)
(5)
—
(5)
—
(5)
(150)
(13)
(13)
5
(8)
—
—
—
—
—
(5)
—
(5)
—
(5)
(13)
$
$
$
$
$
$
$
522
Predecessor
January 1,
2016 to
March 23,
2016
PHI
$
$
$
$
$
$
$
—
—
—
—
—
(1)
(1)
—
(1)
—
—
—
—
—
(1)
Interest expense
Comprehensive income
Comprehensive income
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, 2015
Details about AOCI components
Items reclassified out of AOCI (a)
Affected line item in the Statements of
Operations and Comprehensive Income
Gains and (losses) on cash flow hedges
Terminated interest rate swaps
Energy related hedges
Other cash flow hedges
Total before tax
Tax benefit
Net of tax
Amortization of pension and other
postretirement benefit plan items
Prior service costs (b)
Actuarial losses (b)
Total before tax
Tax benefit
Net of tax
Total Reclassifications
Exelon
Generation
PHI
Predecessor
$
$
$
$
$
(26)
2
(11)
(35)
14
(21)
74
(361)
(287)
112
(175)
(196)
$
$
$
$
$
—
2
(11)
(9)
4
(5)
—
—
—
—
—
(5)
$
$
$
$
$
—
—
(1)
(1)
—
(1)
—
(6)
(6)
2
(4)
(5)
Other, net
Operating revenues
Interest expense
Comprehensive income
Comprehensive income
(a) Amounts in parenthesis represent a decrease in net income.
(b) This accumulated other comprehensive income component is included in the computation of net periodic pension and OPEB cost (see Note 17—Retirement Benefits for
additional details).
(c) Amortization of the deferred compensation unit plan is allocated to capital and operating and maintenance expense.
The following table presents income tax expense (benefit) allocated to each component of other comprehensive income (loss) during the years
ended December 31, 2016 and 2015:
Exelon
Pension and non-pension postretirement benefit plans:
Prior service benefit reclassified to periodic benefit cost
Actuarial loss reclassified to periodic cost
Pension and non-pension postretirement benefit plan valuation adjustment
Change in unrealized (gain) loss on cash flow hedges
Change in unrealized (gain) loss on equity investments
Total
Generation
Change in unrealized loss on cash flow hedges
Change in unrealized (gain) loss on equity investments
Total
523
For the Years Ended
December 31,
2016
2015
2014
$ 30
(118)
115
—
3
$ 30
$
$
(2)
3
1
$ 30
(140)
62
(6)
1
$ (53)
$
$
2
1
3
$ 19
(93)
317
96
73
$412
$ 84
73
$157
Table of Contents
Combined Notes to Consolidated Financial Statements—(Continued)
(Dollars in millions, except per share data unless otherwise noted)
PHI
Pension and non-pension postretirement benefit plans:
Actuarial loss reclassified to periodic cost
24. Commitments and Contingencies (All Registrants)
Commitments
Constellation Merger Commitments
January 1 to
March 23,
2016
Predecessor
For the Years Ended
December 31,
2015
2014
$
—
$
6
$
5
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 estimate includes $95 million to $120 million relating to the construction of a
headquarters building in Baltimore for Generation’s competitive energy businesses.
The direct investment commitment also includes $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. The MDPSC
order contemplates 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 $454 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. During the third quarter of 2014, the conditions associated with one of the generation development commitments changed such that the most
likely outcome would involve Exelon and Generation making subsidy payments and/or liquidated damages payments rather than constructing the
specified generating plant. As a result, Exelon and Generation recorded a pre-tax $44 million loss contingency in Operating and maintenance
expense related to this specific commitment that is included in Exelon’s and Generation’s Consolidated Statements of Operations and
Comprehensive Income for the year ended December 31, 2014. On December 19, 2016, Generation paid $44 million to the Maryland Energy
Administration in full satisfaction of this commitment. 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 will now most likely 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 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.
Equity Investment Commitments
As part of Generation’s recent investments in technology development, Generation enters into equity purchase agreements that include
commitments to invest additional equity through incremental payments to fund the anticipated needs of the planned operations of the associated
companies. The commitment includes approximately $20 million of in-kind services and 100% of 2015 ESA Investco,
524
Table of Contents
Combined Notes to Consolidated Financial Statements—(Continued)
(Dollars in millions, except per share data unless otherwise noted)
LLC’s equity commitment since 2015 ESA Investco, LLC is consolidated by Generation (see Note 2—Variable Interest Entities for additional details).
As of December 31, 2016, Generation’s estimated commitment relating to its equity purchase agreements, including in-kind services contributions, is
anticipated to be as follows:
2017
2018
Total
Commercial Commitments
Exelon’s commercial commitments as of December 31, 2016, representing commitments potentially triggered by future events, were as
follows:
Total
$ 34
5
$ 39
Letters of credit (non-debt) (a)
Surety bonds (b)
Financing trust guarantees (c)
Guaranteed lease residual values (d)
Total commercial commitments
Total
2017
2018 2019 2020 2021
Expiration within
$1,614 $1,355 $246 $ — $ 13 $ — $
1,035
628
20
978
—
—
$3,297 $2,333 $279 $
33
—
—
2
—
—
16
—
—
6
—
—
2 $ 29 $
6 $
2022
and beyond
—
—
628
20
648
(a) Letters of credit (non-debt)—Exelon and certain of its subsidiaries maintain non-debt letters of credit to provide credit support for certain transactions as requested by third
parties.
(b) Surety bonds—Guarantees issued related to contract and commercial agreements, excluding bid bonds.
(c)
Includes $200 million of Trust Preferred Securities of ComEd Financing III, $178 million of Trust Preferred Securities of PECO Trust III and IV and $250 million of Trust
Preferred Securities of BGE Capital Trust II.
(d) 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
$50 million, $14 million of which is a guarantee by Pepco, $17 million by DPL and $13 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, 2016, representing commitments potentially triggered by future events, were as
follows:
Letters of credit (non-debt) (a)
Surety bonds
Total commercial commitments
Total
2017
2018 2019 2020 2021
Expiration within
$1,546 $1,287 $246 $ — $ 13 $ — $
945
918
27
—
—
—
$2,491 $2,205 $273 $ — $ 13 $ — $
2022
and beyond
—
—
—
(a) Letters of credit (non-debt)—Non-debt letters of credit maintained to provide credit support for certain transactions as requested by third parties.
525
Table of Contents
Combined Notes to Consolidated Financial Statements—(Continued)
(Dollars in millions, except per share data unless otherwise noted)
ComEd’s commercial commitments as of December 31, 2016, representing commitments potentially triggered by future events, were as
follows:
Letters of credit (non-debt) (a)
Surety bonds (b)
Financing trust guarantees
Total commercial commitments
Expiration within
Total 2017 2018 2019 2020 2021
$ 14 $ 14 $ — $ — $ — $ — $
11
200
9
—
2
—
—
—
—
—
—
$225 $ 23 $
2 $ — $ — $ — $
2022
and beyond
—
—
200
200
(a) Letters of credit (non-debt)—ComEd maintains non-debt letters of credit to provide credit support for certain transactions as requested by third parties.
(b) Surety bonds—Guarantees issued related to contract and commercial agreements, excluding bid bonds.
PECO’s commercial commitments as of December 31, 2016, representing commitments potentially triggered by future events, were as follows:
Expiration within
Letters of credit (non-debt) (a)
Surety bonds (b)
Financing trust guarantees
Total commercial commitments
Total 2017 2018 2019 2020 2021
$ 23 $ 23 $ — $ — $ — $ — $
9
178
9
—
—
—
—
—
—
—
—
—
$210 $ 32 $ — $ — $ — $ — $
2022
and beyond
—
—
178
178
(a) Letters of credit (non-debt)—PECO maintains non-debt letters of credit to provide credit support for certain transactions as requested by third parties.
(b) Surety bonds—Guarantees issued related to contract and commercial agreements, excluding bid bonds.
BGE’s commercial commitments as of December 31, 2016, representing commitments potentially triggered by future events, were as follows:
Expiration within
Letters of credit (non-debt) (a)
Surety bonds (b)
Financing trust guarantees
Total commercial commitments
Total 2017 2018 2019 2020 2021
$
2 $ — $ — $ — $ — $
2 $
11
250
10
—
1
—
—
—
—
—
—
—
$263 $ 12 $
1 $ — $ — $ — $
2022
and beyond
—
—
250
250
(a) Letters of credit (non-debt)—BGE maintains non-debt letters of credit to provide credit support for certain transactions as requested by third parties.
(b) Surety bonds—Guarantees issued related to contract and commercial agreements, excluding bid bonds.
526
Table of Contents
Combined Notes to Consolidated Financial Statements—(Continued)
(Dollars in millions, except per share data unless otherwise noted)
PHI commercial commitments (Successor) as of December 31, 2016, representing commitments potentially triggered by future events, were
as follows:
Expiration within
Letters of credit (non-debt) (a)
Surety bonds (b)
Guaranteed lease residual values (c)
Total commercial commitments
Total 2017 2018 2019 2020 2021
$ 1 $
16
20
1 $ — $ — $ — $ — $
—
—
14
—
2
—
—
—
—
—
$ 37 $ 15 $
2 $ — $ — $ — $
2022
and beyond
—
—
20
20
(a) Letters of credit (non-debt)—PHI and certain of its subsidiaries maintain non-debt letters of credit to provide credit support for certain transactions as requested by third
parties.
(b) Surety bonds—Guarantees issued related to contract and commercial agreements, excluding bid bonds.
(c) 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
$50 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.
Pepco commercial commitments as of December 31, 2016, representing commitments potentially triggered by future events, were as follows:
Expiration within
Surety bonds (a)
Guaranteed lease residual values (b)
Total commercial commitments
Total 2017 2018 2019 2020 2021
$ 9 $
9 $ — $ — $ — $ — $
6
—
—
—
—
—
$ 15 $
9 $ — $ — $ — $ — $
2022
and beyond
—
6
6
(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
$14 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.
DPL commercial commitments as of December 31, 2016, representing commitments potentially triggered by future events, were as follows:
Surety bonds (a)
Guaranteed lease residual values (b)
Total commercial commitments
Expiration within
Total
$ 4
7
$ 11
2017
$
3
—
3
$
2018
$
1
—
1
$
2019
$ —
—
$ —
2020
$ —
—
$ —
2021
$ —
—
$ —
2022
and beyond
—
$
7
7
$
(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
$17 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.
527
Table of Contents
Combined Notes to Consolidated Financial Statements—(Continued)
(Dollars in millions, except per share data unless otherwise noted)
ACE commercial commitments as of December 31, 2016, representing commitments potentially triggered by future events, were as follows:
Letters of credit (non-debt) (a)
Surety bonds (b)
Guaranteed lease residual values (c)
Total commercial commitments
Expiration within
Total
$ 1
3
5
$ 9
2017
1
$
2
—
3
$
2018
$ —
1
—
1
$
2019
$ —
—
—
$ —
2020
$ —
—
—
$ —
2021
$ —
—
—
$ —
2022
and beyond
—
$
—
5
5
$
(a) Letters of credit (non-debt)—ACE maintains non-debt letters of credit to provide credit support for certain transactions as requested by third parties.
(b) Surety bonds—Guarantees issued related to contract and commercial agreements, excluding bid bonds.
(c) 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
$13 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.
Leases
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, 2016 were:
2017
2018
2019
2020
2021
Remaining years
Total minimum future lease payments
Exelon
(a)
$ 183
179
123
140
133
968
$1,726
Generation
(a)
$
$
70
75
30
48
47
644
914
ComEd
(b)
$
11
6
6
3
3
—
29
$
PECO
(b)
$
3
3
4
4
4
—
$ 18
BGE
(b)(c)
(d)
$ 32
34
34
34
32
33
$199
PHI
$ 50
49
36
38
34
211
$418
Pepco
7
$
6
5
4
3
7
$ 32
DPL
(b)
$ 13
17
7
10
9
54
$110
ACE
$ 8
8
7
6
5
20
$ 54
(a) Excludes Generation’s contingent operating lease payments associated with contracted generation agreements.
(b) 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 2017—2021, was $2 million, $4 million, $2 million and $2 million, respectively.
Includes all future lease payments on a 99 year real estate lease that expires in 2106.
(c)
(d) 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 $21 million $25 million, $26 million , $27 million, $28 million, and $14 million related to
years 2017, 2018, 2019, 2020, 2021 and thereafter, respectively.
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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 Registrants’ rental expense under operating leases for the years ended December 31, 2016, 2015 and 2014:
For the Year Ended December 31,
2016
2015
2014
PHI
Rental expense under operating leases
Generation
(a)
Exelon
$ 777 $
922
865
ComEd PECO BGE Pepco DPL ACE
8 $ 15 $ 13
13
14
7
12
14
8
7 $ 22 $
9
14
15 $
12
15
667 $
851
806
32
12
Successor
March 24, 2016
to December 31,
2016
January 1,
2016
to March 23,
2016
Predecessor
For the Year
Ended
December 31,
2015
For the Year
Ended
December 31,
2014
$
49
12
60
59
(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 $604 million, $798 million and $755 million during 2016, 2015 and 2014,
respectively. Excludes contract amortization associated with purchase accounting and contract acquisitions.
For information regarding capital lease obligations, see Note 14—Debt and Credit Agreements.
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 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 also to limit the liability of nuclear reactor owners for such claims from any single incident. As of December 31, 2016,
the current liability limit per incident is $13.4 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 September 10, 2013. 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 $13.0 billion per incident
in funds available for public liability claims. Participation in this secondary financial protection pool requires the operator of each reactor to fund its
proportionate share of costs for any single incident that exceeds the primary layer of financial protection. Exelon’s share of this secondary layer
would be approximately $2.7 billion, including CENG’s related liability, however any amounts payable under this secondary layer would be capped at
$400 million per year.
In addition, the U.S. Congress could impose revenue-raising measures on the nuclear industry to pay public liability claims exceeding the
$13.4 billion limit for a single incident.
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Combined Notes to Consolidated Financial Statements—(Continued)
(Dollars in millions, except per share data unless otherwise noted)
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 5—
Investment in Constellation Energy Nuclear Group, LLC 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 distribution declared
by NEIL is estimated to be $21 million for 2016, and was $21 million for 2015 and $18 million for 2014. 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 $353 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 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 condition, results of operations and
liquidity.
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Spent Nuclear Fuel Obligation
Combined Notes to Consolidated Financial Statements—(Continued)
(Dollars in millions, except per share data unless otherwise noted)
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 year ended December 31, 2016, and December 31, 2015, Generation did not incur any expense in SNF disposal fees. For the year ended
December 31, 2014, Generation incurred expense of $49 million in SNF disposal fees recorded in Purchased power and fuel expense within
Exelon’s and Generation’s Consolidated Statements of Operations and Comprehensive Income, including Exelon’s share of Salem and net of
co-owner reimbursements (not including such fees incurred by CENG). 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. This fee may be adjusted prospectively in order 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. A 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. 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.
Generation uses the 2030 date as the assumed date for when the DOE will begin accepting SNF for purposes of determining nuclear
decommissioning asset retirement obligations.
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. A settlement agreement for Calvert Cliffs and Nine Mile Point
was executed during 2011, pursuant to which the government agreed to reimburse the costs associated with SNF storage expended or to be
expended during a term set by the agreement. The term was subsequently extended during 2014 to include SNF storage costs incurred at Calvert
Cliffs and Nine Mile Point through December 31, 2016. A DOE settlement agreement for Ginna was also executed during 2011. During 2015, Ginna
executed another DOE
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Combined Notes to Consolidated Financial Statements—(Continued)
(Dollars in millions, except per share data unless otherwise noted)
settlement agreement providing for the reimbursement of SNF storage costs incurred through December 31, 2016. Generation expects the terms for
each of the settlement agreements to be extended during 2017 for another three years to cover SNF storage costs through December 31, 2019.
Generation, including CENG, 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 agreement, Generation has received cumulative cash reimbursements for costs incurred as follows:
Cumulative cash reimbursements (b)
Total
$1,038
Net
(a)
$887
(a) Total after considering amounts due to co-owners of certain nuclear stations and to the former owner of Oyster Creek.
(b)
Includes $53 million and $49 million, respectively, for amounts received since April 1, 2014, for costs incurred under the CENG DOE Settlement Agreements prior to the
consolidation of CENG.
As of December 31, 2016, and 2015, 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)
Amounts owed to co-owners (a)(c)
December 31, 2016
109
$
15
(13)
December 31, 2015
76
$
14
(5)
(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
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. As of December 31, 2016, the unfunded SNF liability for the one-time fee with interest was $1,024 million. Interest accrues at the
13-week Treasury Rate. The 13-week Treasury Rate in effect, for calculation of the interest accrual at December 31, 2016, was 0.355%. The
liabilities for SNF disposal costs, including the one-time fee, were transferred to Generation as part of Exelon’s 2001 corporate restructuring. 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 12—Fair Value of Financial Assets and Liabilities for additional information.
Environmental Remediation Matters
General. 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,
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Combined Notes to Consolidated Financial Statements—(Continued)
(Dollars in millions, except per share data unless otherwise noted)
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.
ComEd, PECO, BGE, and DPL have identified sites where former MGP 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, 18 of which have been remediated and approved by the Illinois EPA or the U.S. EPA and 24 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 2021.
•
PECO has identified 26 sites, 17 of which have been remediated in accordance with applicable PA DEP regulatory requirements. The
remaining 9 sites 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 former gas manufacturing or purification sites that it currently owns or owned at one time through a predecessor’s
acquisition. Two gas manufacturing sites require some level of remediation and ongoing monitoring under the direction of the MDE. The
required costs at these 2 sites are not considered material. An investigation of an additional gas purification site was completed during the
first quarter of 2015 at the direction of the MDE. For more information, see the discussion of the Riverside site below.
•
DPL has identified 2 sites, all of which the remediation has been completed and approved by the MDE or the Delaware Department of
Natural Resources and Environmental Control.
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 3—Regulatory Matters for additional
information regarding the associated regulatory assets. BGE is authorized to recover, and is currently recovering, environmental costs for the
remediation of the former MGP facility sites from customers; however, while BGE does not have a rider for MGP clean-up costs, BGE has historically
received recovery of actual clean-up costs in distribution rates. DPL has historically received recovery of actual clean-up costs in distribution rates.
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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, 2016 and 2015, the Registrants had accrued the following undiscounted amounts for environmental liabilities in Other
current liabilities and Other deferred credits and other liabilities within their respective Consolidated Balance Sheets:
December 31, 2016
Exelon
Generation
ComEd
PECO
BGE (a)
PHI
Pepco
DPL
ACE
December 31, 2015
Exelon
Generation
ComEd
PECO
BGE
PHI (Predecessor)
Pepco
DPL
ACE
Total environmental
investigation
and remediation reserve
429
$
72
292
33
2
30
27
2
1
Total environmental
investigation
and remediation reserve
369
$
63
266
37
3
33
24
3
1
Portion of total related to MGP
investigation and remediation
(a)
$
325
—
291
31
2
1
—
1
—
Portion of total related to MGP
investigation and remediation
301
$
—
264
35
2
1
—
1
—
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.
During the third quarter of 2016, ComEd and PECO completed an annual study of their future estimated MGP remediation requirements. The
results of the study resulted in a $7 million and $2 million increase to environmental liabilities and related regulatory assets for ComEd and PECO,
respectively.
The Registrants cannot reasonably estimate whether they will incur other 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.
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Water Quality
Combined Notes to Consolidated Financial Statements—(Continued)
(Dollars in millions, except per share data unless otherwise noted)
Benning Road Site NPDES Permit Limit Exceedances . Pepco holds an NPDES permit issued by EPA with a July 19, 2009 effective date,
which authorizes discharges from the Benning Road service facility. The 2009 permit for the first time imposed numerical limits on the allowable
concentration of certain metals in storm water discharged from the site into the Anacostia River. The permit contemplated that Pepco would meet
these limits over time through the use of best management practices (BMPs). The BMPs were effective in reducing metal concentrations in storm
water discharges, but were not sufficient to meet all of the numerical limits for all metals.
The 2009 permit remains in effect pending EPA’s action on the Pepco renewal application, including resolution of the stormwater compliance
issues. On October 30, 2015, EPA filed a Clean Water Act civil enforcement action against Pepco in federal district court, and in March 2016 the
court granted a motion by the Anacostia Riverkeeper to intervene in this case as a plaintiff along with EPA. Since 2009 Pepco has installed runoff
mitigation measures and implemented new operating procedures to comply with regulations. In January 2017, the parties agreed to a settlement in
the form of a Consent Decree whereby Pepco will pay a civil penalty in the amount of $1.6 million, continue the BMPs to manage stormwater,
construct a new stormwater treatment system, and make certain other capital improvements to the stormwater management system. The Consent
Decree has been lodged with the Court and will be subject to a 30-day public comment period. It is expected that the Court will approve the Consent
Decree in the first quarter of 2017. Pepco has established appropriate reserves for the liabilities under the Consent Agreement, which is included in
the table above.
Solid and Hazardous Waste
Cotter Corporation. 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 approving the remediation option submitted by Cotter and the two other PRPs that required additional landfill cover. The current estimated
cost of the landfill cover remediation for the site is approximately $90 million including escalation, which will be allocated among all PRPs.
Generation has accrued what it believes to be an adequate amount to cover its anticipated share of such liability, which is included in the table
above. 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. The final supplemental feasibility study was completed in December of 2016 and will enable
the EPA to propose a remedy for public comment. While the EPA has not yet formally announced a change in the schedule, the PRPs believe that
the EPA announcement of the proposed remedy will take place in the third quarter of 2017 at the earliest. Thereafter, the EPA will select a final
remedy and enter into a Consent Decree with the PRPs to effectuate the remedy. Recent investigation has identified a number of other parties who
may be PRPs and could be liable to contribute to the final remedy. Further investigation is underway. Generation believes that a partial excavation
remedy is reasonably possible, and the partial excavation costs, inclusive of a landfill cover, could range from approximately $225 million
to$650 million; such costs would likely be shared by the final group of identified PRPs.
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Combined Notes to Consolidated Financial Statements—(Continued)
(Dollars in millions, except per share data unless otherwise noted)
Generation believes the likelihood that the EPA would require a complete excavation remedy is remote. The cost of a partial or complete excavation
could have a material, unfavorable impact on Generation’s and Exelon’s future results of operations and cash flows.
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. Generation has accrued what it believes to be an adequate amount to cover
its anticipated liability for this interim action. 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, EPA has not provided sufficient details related to the basis for and the requirements and design of a
barrier wall to enable Generation to determine the likelihood such a remedy will ultimately be implemented, assess the degree to which Generation
may have liability as a potentially responsible party, or develop a reasonable estimate of the potential incremental costs. It is reasonably possible,
however, that resolution of this matter could have a material, unfavorable impact on Generation’s and Exelon’s future results of operations and cash
flows. Finally, one of the other PRP’s, 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, Generation and Exelon do not possess sufficient information to assess this claim and are
therefore unable to determine the impact on their future results of operations and cash flows.
On February 2, 2016, the U.S. Senate passed a bill to transfer remediation authority over the West Lake Landfill from the EPA to the U.S.
Army Corps of Engineers, under the Formerly Utilized Sites Remedial Action Program (FUSRAP). Such legislation would become final upon
passage in the U.S. House of Representatives and the signature of the President, and be subject to annual funding appropriations in the U.S.
Budget. The legislation has not passed in the House. Remediation under FUSRAP would not alter the liability of the PRPs, but could delay the
determination of a final remedy and its implementation.
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 the 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. The DOJ and the PRPs agreed to toll the statute of
limitations until August 2017 so that settlement discussions could proceed. Based on Generation’s preliminary review, it appears probable that
Generation has liability to Cotter under the indemnification agreement and has established an appropriate accrual for this 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
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Combined Notes to Consolidated Financial Statements—(Continued)
(Dollars in millions, except per share data unless otherwise noted)
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. The complaints do not contain specific
damage claims. In the event of a finding of liability against Cotter, it is reasonably possible that Exelon would be financially responsible due to its
indemnification responsibilities of Cotter described above. The court has dismissed a number of lawsuits, and is expected to dismiss additional
lawsuits based on a recent ruling. Pre-trial motions and discovery are proceeding in the remaining cases and a pre-trial scheduling order has been
filed with the court. At this stage of the litigation, Generation and ComEd cannot estimate a range of loss, if any.
68th Street Dump. In 1999, the U.S. EPA proposed to add the 68th Street Dump in Baltimore, Maryland to the Superfund National Priorities
List, and notified BGE and 19 others that they are PRPs at the site. In connection with BGE’s 2000 corporate restructuring the responsibility for this
liability was transferred to Constellation and as a result of the 2012 Exelon and CEG merger is now Generation’s responsibility. In March 2004, the
PRPs formed the 68th Street Coalition and entered into consent order negotiations with the U.S. EPA to investigate clean-up options for the site
under the Superfund Alternative Sites Program. In May 2006, a settlement among the U.S. EPA and the PRPs with respect to investigation of the
site became effective. The settlement requires the PRPs, over the course of several years, to identify contamination at the site and recommend
clean-up options. The PRPs submitted their investigation of the range of clean-up options in the first quarter of 2011. Although the investigation and
options provided to the U.S. EPA are still subject to U.S. EPA review and selection of a remedy, the range of estimated clean-up costs to be
allocated among all of the PRPs is in the range of $50 million to $64 million. On September 30, 2013, U.S. EPA issued the Record of Decision
identifying its preferred remedial alternative for the site. The estimated cost for the alternative chosen by U.S. EPA is consistent with the PRPs’
estimated range of costs noted above. Based on Generation’s preliminary review, it appears probable that Generation has liability and has
established an appropriate accrual for its share of the estimated clean-up costs.
Rossville Ash Site. The Rossville Ash Site is a 32-acre property located in Rosedale, Baltimore County, Maryland, which was used for the
placement of fly ash from 1983-2007. The property is owned by Constellation Power Source Generation, LLC (CPSG), a wholly-owned subsidiary of
Generation. In 2008, CPSG investigated and remediated the property by entering it into the Maryland Voluntary Cleanup Program (VCP) to address
any historic environmental concerns and ready the site for appropriate future redevelopment. The site was accepted into the program in 2010 and is
currently going through the process to remediate the site and receive closure from MDE. Exelon currently estimates the cost to close the site to be
approximately $4 million, which has been fully reserved as of December 31, 2016 and is included in the table above.
Sauer Dump. On May 30, 2012, BGE was notified by the U.S. EPA that it is considered a PRP at the Sauer Dump Superfund site in Dundalk,
Maryland. The U.S. EPA offered BGE and three other PRPs the opportunity to conduct an environmental investigation and present cleanup
recommendations at the site. In addition, the U.S. EPA is seeking recovery from the PRPs of $1.7 million for past cleanup and investigation costs at
the site. On March 11, 2013, BGE and three other PRPs signed an Administrative Settlement Agreement and Order on Consent with the U.S. EPA
which requires the PRPs to conduct a remedial investigation and feasibility study at the site to determine what, if any, are the appropriate and
recommended cleanup activities for the site. The ultimate outcome of this proceeding is uncertain. Since the U.S. EPA has not selected a cleanup
537
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Combined Notes to Consolidated Financial Statements—(Continued)
(Dollars in millions, except per share data unless otherwise noted)
remedy and the allocation of the cleanup costs among the PRPs has not been determined, an estimate of the range of BGE’s reasonably possible
loss, if any, cannot be determined. It is possible, however, that resolution of this matter could have a material, unfavorable impact on Exelon’s and
BGE’s future results of operations and cash flows.
Riverside . In 2013, the MDE, at the request of EPA, conducted a site inspection and limited environmental sampling of certain portions of the
170 acre Riverside property owned by BGE. The site consists of several different parcels with different current and historical uses. The sampling
included soil and groundwater samples for a number of potential environmental contaminants. The sampling confirmed the existence of
contaminants consistent with the known historical uses of the various portions of the site. In March 2014, the MDE requested that BGE conduct an
investigation which included a site-wide investigation of soils, sediment, groundwater, and surface water to complement the MDE sampling. The field
investigation was completed in January 2015, and a final report was provided to MDE on June 2, 2015. On November 3, 2015, MDE provided BGE
with its comments and recommendations on the report which require BGE to conduct further investigation and sampling at the site to better delineate
the nature and extent of historic contamination, including off-site sediment and soil sampling. MDE did not request any interim remediation at this
time and BGE anticipates completing the additional work requested by the end of the first quarter of 2017. BGE has established what it believes is
an appropriate reserve based upon the investigation to date. The established reserve is included in the table above. As the investigation and
potential remediation proceed, it is possible that resolution of this matter could have a material, unfavorable impact on Exelon’s and BGE’s future
results of operations and cash flows.
Benning Road Site. 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 RI/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 that are determined to be
attributable to past activities at the Benning Road site.
The initial RI field work began in January 2013 and was completed in December 2014. In April 2015, Pepco and Pepco Energy Services
submitted a draft RI Report to DOEE. After review, DOEE determined that additional field investigation and data analysis was required to complete
the RI process (much of which was beyond the scope of the original DOEE-approved RI work plan). In the meantime, Pepco and Pepco Energy
Services revised the draft RI Report to address DOEE’s comments and DOEE released the draft RI Report for public review in February 2016. Once
the additional RI work has been completed, Pepco and Pepco Energy Services will issue a draft “final” RI report for review and comment by DOEE
and the public. Pepco and Pepco Energy Services will then proceed to develop an FS to evaluate possible remedial alternatives for submission to
DOEE.
Upon DOEE’s approval of the final remedial investigation and feasibility study Reports, Pepco and Pepco Energy Services will have satisfied
their obligations under the consent decree. At that point,
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Combined Notes to Consolidated Financial Statements—(Continued)
(Dollars in millions, except per share data unless otherwise noted)
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 Pepco Energy Services have determined that a loss associated with this matter for PHI, Pepco and Pepco Energy Services is
probable and an estimated liability for this issue has been accrued, which is included in the table above. As the remedial investigation proceeds and
potential remedies are identified, it is possible that additional reserves could be established in amounts that could be material to PHI, Pepco and
Pepco Energy Services. Pursuant to Exelon’s March 2016 acquisition of PHI, Pepco Energy Services was transferred to Generation. The ultimate
resolution of this matter is currently not expected to have any significant financial impact on Generation.
Anacostia River Tidal Reach . Contemporaneous with the Benning RI/FS being performed by Pepco and Pepco Energy Services, 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 Road 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.
DOEE has advised the Consultative Working Group that the federal and DOEE authorities are conducting phase 2 of a remedial investigation. DOEE
has targeted June 2018 as the date for remedy selection for clean-up of sediments in this section of the river. The Consultative Working Group and
the other possible PRPs have provided input into the proposed clean-up process and schedule. At this time, it is not possible to predict the extent of
Pepco’s participation in the river-wide RI/FS process, and Pepco cannot estimate the reasonably possible range of loss for response costs beyond
those associated with the Benning RI/FS component of the river-wide initiative. It is possible, however, that resolution of this matter could have a
material, unfavorable impact on Exelon’s and Pepco’s future results of operations and cash flows.
Conectiv Energy Wholesale Power Generation Sites. In July 2010, PHI sold the wholesale power generation business of Conectiv Energy
Holdings, Inc. and substantially all of its subsidiaries (Conectiv Energy) to Calpine Corporation (Calpine). Under New Jersey’s Industrial Site
Recovery Act (ISRA), the transfer of ownership triggered an obligation on the part of Conectiv Energy to remediate any environmental contamination
at each of the nine Conectiv Energy generating facility sites located in New Jersey. Under the terms of the sale, Calpine has assumed responsibility
for performing the ISRA-required remediation and for the payment of all related ISRA compliance costs up to $10 million. PHI is obligated to
indemnify Calpine for any ISRA compliance remediation costs in excess of $10 million. According to PHI’s estimates, the costs of ISRA-required
remediation activities at the nine generating facility sites located in New Jersey are in the range of approximately $7 million to $18 million, and PHI
has established an appropriate accrual for its share of the estimated clean-up costs, which is included in the table above. Pursuant to Exelon’s
March 2016 acquisition of PHI, Conectiv Energy was transferred to Generation, however, the responsibility to indemnify Calpine remained at PHI.
The ultimate resolution of this matter is currently not expected to have any significant financial impact on PHI.
539
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Combined Notes to Consolidated Financial Statements—(Continued)
(Dollars in millions, except per share data unless otherwise noted)
Rock Creek Mineral Oil Release. In late August 2015, a Pepco underground transmission line in the District of Columbia suffered a breach,
resulting in the release of non-toxic mineral oil surrounding the transmission line into the surrounding soil, and a small amount reached Rock Creek
through a storm drain. Pepco notified regulatory authorities, and Pepco and its spill response contractors placed booms in Rock Creek, blocked the
storm drain to prevent the release of mineral oil into the creek and commenced remediation of soil around the transmission line and the Rock Creek
shoreline. Pepco estimates that approximately 6,100 gallons of mineral oil were released and that its remediation efforts recovered approximately
80% of the amount released. Pepco’s remediation efforts are ongoing under the direction of the DOEE, including the requirements of a February 29,
2016 compliance order which requires Pepco to prepare a full incident investigation report and prepare a removal action work plan to remove all
impacted soils in the vicinity of the storm drain outfall, and in collaboration with the National Park Service, the Smithsonian Institution/National Zoo
and EPA. Pepco’s investigation presently indicates that the damage to Pepco’s facilities occurred prior to the release of mineral oil when third-party
excavators struck the Pepco underground transmission line while installing cable for another utility.
To the extent recovery is available against any party who contributed to this loss, PHI and Pepco will pursue such action. Exelon, PHI and
Pepco continue to investigate the cause of the incident, the parties involved, and legal responsibility under District of Columbia law, but do not
believe that the remediation costs to resolve this matter will have a material adverse effect on their respective financial condition, results of
operations or cash flows.
Brandywine Fly Ash Disposal Site. In February 2013, Pepco received a letter from the MDE requesting that Pepco investigate the extent of
waste on a Pepco right-of-way that traverses the Brandywine fly ash disposal site in Brandywine, Prince George’s County, Maryland, owned by NRG
Energy, Inc. (as successor to GenOn MD Ash Management, LLC) (NRG). In July 2013, while reserving its rights and related defenses under a 2000
agreement covering the sale of this site, Pepco indicated its willingness to investigate the extent of, and propose an appropriate closure plan to
address, ash on the right-of-way. Pepco submitted a schedule for development of a closure plan to MDE on September 30, 2013 and, by letter dated
October 18, 2013, MDE approved the schedule.
Exelon, PHI and Pepco have determined that a loss associated with this matter is probable and have estimated that the costs for
implementation of a closure plan and cap on the site are in the range of approximately $3 million to $6 million, for which an appropriate reserve has
been established and is included in the table above. Exelon, PHI and Pepco believe that the costs incurred in this matter will be recoverable from
NRG under the 2000 sale agreement.
Litigation and Regulatory Matters
Asbestos Personal Injury Claims (Exelon, Generation, ComEd, PECO and BGE).
Exelon and Generation. Generation maintains a reserve for claims associated with asbestos-related personal injury actions in certain facilities
that are currently owned by Generation or were previously owned by ComEd and PECO. The reserve is recorded on an undiscounted basis and
excludes the estimated legal costs associated with handling these matters, which could be material.
At December 31, 2016 and 2015, Generation had reserved approximately $83 million and $95 million, respectively, in total for asbestos-related
bodily injury claims. As of December 31, 2016, approximately $22 million of this amount related to 230 open claims presented to Generation, while
the
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Combined Notes to Consolidated Financial Statements—(Continued)
(Dollars in millions, except per share data unless otherwise noted)
remaining $61 million of the reserve 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 an adjustment to the reserve is necessary.
On November 22, 2013, the Supreme Court of Pennsylvania held that the Pennsylvania Workers Compensation Act does not apply to an
employee’s disability or death resulting from occupational disease, such as diseases related to asbestos exposure, which manifests more than 300
weeks after the employee’s last employment-based exposure, and that therefore the exclusivity provision of the Act does not preclude such
employee from suing his or her employer in court. The Supreme Court’s ruling reverses previous rulings by the Pennsylvania Superior Court
precluding current and former employees from suing their employers in court, despite the fact that the same employee was not eligible for workers
compensation benefits for diseases that manifest more than 300 weeks after the employee’s last employment-based exposure to asbestos. Since
the Pennsylvania Supreme Court’s ruling in November 2013, Exelon, Generation, and PECO have experienced an increase in asbestos-related
personal injury claims brought by former PECO employees, all of which have been reserved against on a claim by claim basis. Those additional
claims are taken into account in projecting estimated future asbestos-related bodily injury claims.
On November 4, 2015, the Illinois Supreme Court found that the provisions of the Illinois’ Workers’ Compensation Act and the Workers’
Occupational Diseases Act barred an employee from bringing a direct civil action against an employer for latent diseases, including asbestos-related
diseases that fall outside the 25-year limit of the statute of repose. The Illinois Supreme Court’s ruling reversed previous rulings by the Illinois Court
of Appeals, which initially ruled that the Illinois Worker’s Compensation law should not apply in cases where the diagnosis of an asbestos related
disease occurred after the 25-year maximum time period for filing a Worker’s Compensation claim. As a result of this ruling, Exelon, Generation, and
ComEd have not recorded an increase to the asbestos-related bodily injury liability as of December 31, 2016.
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 adverse effect on Exelon’s, Generation’s and PECO’s future results of operations
and cash flows.
BGE. Since 1993, BGE and certain Constellation (now Generation) subsidiaries have been involved in several actions concerning asbestos.
The actions are based upon the theory of “premises liability,” alleging that BGE and Generation knew of and exposed individuals to an asbestos
hazard. In addition to BGE and Generation, numerous other parties are defendants in these cases.
To date, most asbestos claims which have been resolved relating to BGE and certain Constellation subsidiaries have been dismissed or
resolved without any payment and a small minority of these cases has been resolved for amounts that were not material to BGE or Generation’s
financial results. Presently, there are an immaterial number of asbestos cases pending against BGE and certain Constellation subsidiaries.
Continuous Power Interruption (Exelon and ComEd)
Section 16-125 of the Illinois Public Utilities Act provides that in the event an electric utility, such as ComEd, experiences a continuous power
interruption of four hours or more that affects (in ComEd’s
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Combined Notes to Consolidated Financial Statements—(Continued)
(Dollars in millions, except per share data unless otherwise noted)
case) more than 30,000 customers, the utility may be liable for actual damages suffered by customers as a result of the interruption and may be
responsible for reimbursement of local governmental emergency and contingency expenses incurred in connection with the interruption. Recovery of
consequential damages is barred. The affected utility may seek from the ICC a waiver of these liabilities when the utility can show that the cause of
the interruption was unpreventable damage due to weather events or conditions, customer tampering, or certain other causes enumerated in the
law. As of December 31, 2016 and 2015, ComEd did not have any material liabilities recorded for these storm events.
Fund Transfer Restrictions (Exelon, Generation, ComEd, PECO, BGE, PEPCO, DPL and ACE)
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.
The Federal Power Act declares it to be unlawful for any officer or director of any public utility “to participate in the making or paying of any
dividends of such public utility from any funds properly included in capital account.” What constitutes “funds properly included in capital account” is
undefined in the Federal Power Act or the related regulations; however, FERC has consistently interpreted the provision to allow dividends to be
paid as long as: (1) the source of the dividends is clearly disclosed; (2) the dividend is not excessive; and (3) there is no self-dealing on the part of
corporate officials. While these restrictions may limit the absolute amount of dividends that a particular subsidiary may pay, Exelon does not believe
these limitations are materially limiting because, under these limitations, the subsidiaries are allowed to pay dividends sufficient to meet Exelon’s
actual cash needs.
Under Illinois law, ComEd may not pay any dividend on its stock unless, among other things, “[its] earnings and earned surplus are sufficient to
declare and pay same after provision is made for reasonable and proper reserves,” or unless it has specific authorization from the ICC. ComEd has
also 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.
PECO’s Articles of Incorporation prohibit payment of any dividend on, or other distribution to the holders of, common stock if, after giving effect
thereto, the capital of PECO represented by its common stock together with its retained earnings is, in the aggregate, less than the involuntary
liquidating value of its then outstanding preferred securities. On May 1, 2013, PECO redeemed all outstanding preferred securities. As a result, the
above ratio calculation is no longer applicable. Additionally, PECO may 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.
BGE is subject to certain dividend restrictions established by the MDPSC. First, BGE was prohibited from paying a dividend on its common
shares through the end of 2014. Second, BGE is prohibited from paying a dividend on its common shares if (a) after the dividend payment, BGE’s
equity
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Combined Notes to Consolidated Financial Statements—(Continued)
(Dollars in millions, except per share data unless otherwise noted)
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. Finally, BGE must notify the MDPSC that it intends to declare a dividend on its
common shares at least 30 days before such a dividend is paid. There are no other limitations on BGE paying common stock dividends unless BGE
elects to defer interest payments on the 6.20% Deferrable Interest Subordinated Debentures due 2043, and any deferred interest remains unpaid.
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 commissions and the Board or (b) Pepco’s senior unsecured credit rating is rated by one of the
three major credit rating agencies below investment grade.
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 commissions and the Board or (b) DPL’s senior unsecured credit rating is rated by one of the three major credit rating
agencies below investment grade.
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 commissions and the Board or (b) ACE’s senior unsecured credit rating is rated by one of the three major credit rating agencies
below investment grade.
Baltimore City Franchise Taxes (BGE)
The City of Baltimore claims that BGE has maintained electric facilities in the City’s public right-of-ways for over one hundred years without the
proper franchise rights from the City. BGE has reviewed the City’s claim and believes that it lacks merit. BGE has not recorded an accrual for
payment of franchise fees for past periods as a range of loss, if any, cannot be reasonably estimated at this time. Franchise fees assessed in future
periods may be material to BGE’s results of operations and cash flows.
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 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
have 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 credit to Operating and maintenance expense in the fourth quarter of approximately
$28 million for the reversal of the previously higher fees accrued in the current year as well as the settlement of prior year disputed fee true-up
amounts.
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Combined Notes to Consolidated Financial Statements—(Continued)
(Dollars in millions, except per share data unless otherwise noted)
Deere Wind Energy Assets (Exelon and Generation)
In 2013, Deere & Company (“Deere”) filed a lawsuit against Generation in the Delaware Superior Court relating to Generation’s acquisition of
the Deere wind energy assets. Under the purchase agreement, Deere was entitled to receive earn-out payments if certain specific wind projects
already under development in Michigan met certain development and construction milestones following the sale. In the complaint, Deere seeks to
recover a $14 million earn-out payment associated with one such project, which was never completed. Generation has filed counterclaims against
Deere for breach of contract, with a right of recoupment and set off. On June 2, 2016, the Delaware Superior Court entered summary judgment in
favor of Deere. On January 17, 2017, Generation filed an appeal with the Supreme Court of Delaware. Generation has accrued an amount to cover
its potential liability.
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.
Income Taxes (Exelon, Generation, ComEd, PECO and BGE)
See Note 15—Income Taxes for information regarding the Registrants’ income tax refund claims and certain tax positions, including the 1999
sale of fossil generating assets.
25. 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, 2016, 2015 and 2014.
For the year ended
December 31, 2016
Taxes other than income
Utility (a)
Property
Payroll
Other
Total taxes other than income
Exelon Generation ComEd PECO BGE Pepco DPL ACE
PHI
PHI
Successor
March 24,
2016 to
December 31,
2016
Predecessor
January 1,
2016 to
March 23,
2016
$ 753 $
483
226
114
122 $ 242 $ 136 $ 85 $ 312 $ 18 $ — $
123
246
17
117
4
21
13
15
—
31
5
1
27
28
(4)
53
8
4
$1,576 $
506 $ 293 $ 164 $229 $ 377 $ 55 $
544
3
3
1
7 $
253
73
23
5
354
$
$
78
18
8
1
105
Table of Contents
For the year ended December 31, 2015
Taxes other than income
Utility (a)
Property
Payroll
Other
Total taxes other than income
For the year ended December 31, 2014
Taxes other than income
Utility (a)
Property
Payroll
Other
Total taxes other than income
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
Predecessor
PHI
$ 474 $
407
201
118
105 $ 236 $ 133 $ 85 $
250
118
16
11
14
2
119
16
4
27
28
5
$1,200 $
489 $ 296 $ 160 $224 $
326 $ 308 $ 18 $ —
3
2
2
7
57
6
5
455 $ 376 $ 51 $
28
4
1
94
27
8
Exelon Generation ComEd PECO BGE
Pepco DPL ACE
Predecessor
PHI
$ 456 $
89 $ 238 $ 128 $ 86 $
396
200
102
240
118
18
25
28
2
15
14
2
114
18
3
$1,154 $
465 $ 293 $ 159 $221 $
324 $ 307 $ 17 $ —
3
2
(1)
4
51
6
5
437 $ 369 $ 46 $
24
4
1
85
23
5
(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 on the Registrants’ Consolidated Statements of Operations and Comprehensive Income.
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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 the year ended
December 31, 2016
Other, Net
Decommissioning-related activities:
Net realized income on decommissioning
trust funds (a)
Regulatory agreement units
Non-regulatory agreement units
Net unrealized gains on decommissioning
trust funds
Regulatory agreement units
Non-regulatory agreement units
Net unrealized losses on pledged assets
Zion Station decommissioning
Regulatory offset to decommissioning trust
fund-related activities (b)
Total decommissioning-related activities
Investment income (loss)
Long-term lease income
Interest income related to uncertain income tax
positions
Penalty related to uncertain income tax positions
(c)
AFUDC—Equity
Loss on debt extinguishment
Other
Other, net
Exelon Generation ComEd PECO BGE
Pepco DPL ACE
PHI
PHI
Successor
March 24,
2016 to
December 31,
2016
Predecessor
January 1,
2016 to
March 23,
2016
$
237 $
126
216
194
(1)
(372)
400
17
4
13
(106)
64
(3)
24
413 $
$
237 $ — $ — $ —
—
126
—
—
$ — $ — $ — $
—
—
—
216
194
—
—
—
—
—
—
—
—
—
—
—
—
(1)
—
—
—
—
—
—
(372)
400
8
—
—
—
—
—
—
—
(1)
—
—
—
2(f)
—
—
—
1
—
—
—
—
—
—
—
1
—
—
—
—
—
1
—
—
—
—
(2)
(5)
401 $
(86)
14
—
7
(65) $
—
—
8
19
—
—
—
1
8 $ 21
546
—
19
—
15
36 $ 13 $
—
5
—
8
—
6
—
2
9 $
$
—
—
$
—
—
—
—
—
1
—
(1)
—
23
—
21
44
$
—
—
—
—
—
—
—
—
—
—
—
7
—
(11)
(4)
Table of Contents
For the year ended December 31, 2015
Other, Net
Decommissioning-related activities:
Combined Notes to Consolidated Financial Statements—(Continued)
(Dollars in millions, except per share data unless otherwise noted)
Exelon Generation ComEd PECO BGE
Predecessor
PHI
Pepco DPL ACE
Net realized income on decommissioning trust
funds (a)
Regulatory agreement units
Non-regulatory agreement units
$ 232 $
156
232 $ — $ — $ —
—
156
—
—
$
— $ — $ — $ —
—
—
—
—
Net unrealized losses on decommissioning trust
funds—
Regulatory agreement units
Non-regulatory agreement units
Net unrealized gains on pledged assets
Zion Station decommissioning
Regulatory offset to decommissioning trust fund-
related activities (b)
Total decommissioning-related activities
Investment income (loss)
Long-term lease income
Interest income related to uncertain income tax
positions
AFUDC—Equity
Terminated interest rate swaps (d)
PHI merger related debt exchange (e)
Other
Other, net
(282)
(197)
(282)
(197)
—
—
—
—
—
—
—
—
—
—
—
—
—
—
7
21
(63)
8
15
1
24
(26)
(22)
17
$ (46) $
7
—
—
—
—
—
—
—
21
(63)
3
—
—
—
—
—
—
—
(2)
—
—
—
4(f)
—
—
—
—
—
—
—
—
—
—
—
—
—
—
—
—
—
1
—
—
—
(1)
(60) $
—
5
—
—
16
21 $
—
—
14
5
—
—
—
—
—
2
5 $ 18
5
34
12
14
—
—
—
—
11
40
88 $ 28 $ 10 $
—
1
—
—
9
—
1
—
—
2
3
$
547
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, 2014
Other, Net
Decommissioning-related activities:
Net realized income on decommissioning trust funds (a)
Regulatory agreement units
Non-regulatory agreement units
Net unrealized gains on decommissioning trust funds
Regulatory agreement units
Non-regulatory agreement units
Net unrealized gains on pledged assets
Zion Station decommissioning
Regulatory offset to decommissioning trust fund-related activities
(b)
Total decommissioning-related activities
Investment income (loss)
Long-term lease income
Interest income related to uncertain income tax positions
AFUDC—Equity
Other
Other, net
Exelon Generation ComEd PECO BGE
Predecessor
PHI
Pepco DPL ACE
$
216 $
159
216 $ — $ — $ —
— —
159
—
$
— $ — $ — $ —
—
—
—
—
180
134
29
(358)
360
1
24
40
21
9
455 $
$
180
134
—
—
— —
— —
—
—
—
—
29
—
— —
—
(358)
360
1
—
54
—
(9)
406 $
—
—
—
—
—
3
14
17 $
—
— —
(1)
— —
— —
6 12
2
(1)
7 $ 18
7(f)
$
—
—
1
—
—
13
30
44 $
—
—
—
—
1
10
19
30 $ 10 $
—
—
—
—
—
2
8
—
—
—
—
1
1
1
3
(a)
(b)
Includes investment income and realized gains and losses on sales of investments within the nuclear decommissioning trust funds.
Includes the elimination of NDT fund activity for the Regulatory Agreement Units, including the elimination of net income taxes related to all NDT fund activity for those
units. See Note 16—Asset Retirement Obligations for additional information regarding the accounting for nuclear decommissioning.
(c) See Note 15—Income Taxes for discussion of the penalty related to the Tax Court’s decision on Exelon’s like-kind exchange tax position.
(d)
In January 2015, in connection with Generation’s $750 million issuance of five-year Senior Unsecured Notes, Exelon terminated certain floating-to-fixed interest rate
swaps. As the original forecasted transactions were a series of future interest payments over a ten year period, a portion of the anticipated interest payments are probable
not to occur. As a result, $26 million of anticipated payments were reclassified from AOCI to Other, net in Exelon’s Consolidated Statements of Operations and
Comprehensive Income.
(e) See Note 14—Debt and Credit Agreements and Note 4—Mergers, Acquisitions, and Dispositions for additional information on the PHI merger related debt exchange.
(f) Relates to the cash return on BGE’s rate stabilization deferral. See Note 3—Regulatory Matters for additional information regarding the rate stabilization deferral.
548
Table of Contents
Combined Notes to Consolidated Financial Statements—(Continued)
(Dollars in millions, except per share data unless otherwise noted)
Supplemental Cash Flow Information
The following tables provide additional information regarding the Registrants’ Consolidated Statements of Cash Flows for the years ended
December 31, 2016, 2015 and 2014.
For the year ended December 31,
2016
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
For the year ended December 31, 2015
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
For the year ended December 31, 2014
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
Exelon Generation ComEd PECO BGE Pepco DPL ACE
PHI
PHI
Successor
March 24,
2016 to
December 31,
2016
Predecessor
January 1,
2016 to
March 23,
2016
$ 3,477 $
407
52
35
1,159
446
$ 5,576 $
1,835 $
—
44
67
—
35
1,159
446
3,519 $
—
—
—
708 $ 244 $ 299 $ 175 $ 110 $ 82 $
26
—
124
—
120
—
47
—
83
—
—
—
—
—
—
—
—
—
—
—
—
—
—
—
—
775 $ 270 $ 423 $ 295 $ 157 $ 165 $
325
190
—
—
—
—
515
$
$
94
58
—
—
—
—
152
Predecessor
Exelon Generation ComEd PECO BGE Pepco DPL ACE
PHI
$ 2,227 $
170
54
22
1,116
398
1,007 $
—
47
635 $ 240 $ 289 $ 164 $ 103 $ 76 $
72
—
20
—
77
—
92
—
45
—
99
—
22
1,116
397
—
—
—
—
—
—
—
—
—
—
—
—
—
—
—
—
—
—
$ 3,987 $
2,589 $
707 $ 260 $ 366 $ 256 $ 148 $ 175 $
392
232
—
—
—
—
624
Exelon Generation ComEd PECO BGE Pepco DPL ACE
PHI
Predecessor
$ 2,080 $
191
44
135
1,073
345
$ 3,868 $
922 $
—
44
99
—
135
1,073
345
2,519 $
—
—
—
588 $ 227 $ 288 $ 155 $ 94 $ 72 $
9
—
83
—
57
—
28
—
83
—
—
—
—
—
—
—
—
—
—
—
—
—
—
—
—
687 $ 236 $ 371 $ 212 $ 122 $ 155 $
363
163
—
—
—
—
526
(a)
(b)
(c)
Included in Operating revenues or Purchased power and fuel on the Registrants’ Consolidated Statements of Operations and Comprehensive Income.
Included in Purchased power and fuel expense on the Registrants’ Consolidated Statements of Operations and Comprehensive Income.
Included in Operating and maintenance expense on the Registrants’ Consolidated Statements of Operations and Comprehensive Income.
549
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 Pepco DPL ACE
PHI
PHI
Successor
March 24,
2016 to
December 31,
2016
Predecessor
January 1,
2016 to
March 23,
2016
$ 1,340 $
(441)
339 $
435
298 $ 104 $ 92 $ 118 $ 47 $ 62 $
(444)
216 115 200
64 31
For the year ended December 31,
2016
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
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)(d)
Severance costs
Asset retirement costs
Amortization of debt costs
Discrete impacts from EIMA (e)
Lower of cost or market inventory adjustment
Baltimore City Conduit Lease Settlement
Cash Working Capital Order
Other
Total other non-cash operating activities
Non-cash investing and financing activities:
Change in capital expenditures not paid
Fair value of net assets contributed to Generation in
$
619 $
24
155
12
111
(384)
(11)
9
76
(11)
558
99
2
35
8
37
(28)
(13)
35
$ 1,333 $
218 $
166 $
33 $ 67 $
31 $ 18 $ 15 $
4
1
3
41
30
1
4 — —
25 — — — — — —
29 23 32
19
1
6
— — — — — — —
(384) — — — — — —
(11) — — — — — —
1
—
1
1 —
— — — 81
2 —
(11) — — — — — —
53 — — —
125 82 110
22 — — — — — —
— — — — —
2
4
17
1 — — —
8 — — — — —
—
36 —
1 — — — —
— — — (28) — — —
— — — (13) — — —
(6)
25
15 $
(3) (21)
65 $ 88 $ 183 $ 114 $ 155 $
(12)
215 $
2
(12)
5 (14)
1
3
$ (128) $
50 $
(91) $ (11) $ (86) $
27 $ (12) $ 11 $
21
$
connection with the PHI Merger, net of cash
Fair value of net assets distributed to Exelon in
—
119 — — — — — —
connection with the PHI Merger, net of cash (c)(f)
—
— — — — — — —
Fair value of pension obligation transferred in
connection with the PHI Merger (c)(f)
Assumption of member purchase liability
Assumption of merger commitment liability
Change in PPE related to ARO update
Non-cash financing of capital projects
Indemnification of like-kind exchange position (h)
Sale of Upstream assets (c)
Pending FitzPatrick Acquisition (i)
—
—
—
191
95
—
37
(54)
— — — — — — —
— — — — — — —
33 — —
— — — —
191 — — — — — —
95 — — — — — —
—
158 — — — — —
37 — — — — — —
(54) — — — — — —
—
127
53
29
33
—
—
—
—
—
550
209
258
$
86
—
65
1
—
—
—
3
(5)
—
317
56
2
1
—
—
—
—
(12)
514
$
$
43
11
23
—
16
1
3
—
—
1
5
—
—
—
—
—
—
—
—
—
(3)
46
11
—
—
—
—
—
—
—
—
—
—
Table of Contents
Combined Notes to Consolidated Financial Statements—(Continued)
(Dollars in millions, except per share data unless otherwise noted)
(a)
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 16—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 4—Mergers, Acquisitions, and Dispositions for more 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.
(f)
See Note 3—Regulatory Matters for more information.
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) Relates to the nuclear fuel procurement contract for the purchase of fixed quantities of converted uranium, which was delivered to Generation in 2015. Generation is
required to make payments starting September 28, 2018, with the final payment being due no later than September 30, 2020.
(h) See Note 15—Income Taxes for discussion of the like-kind exchange tax position.
(i) Reflects the transfer of nuclear fuel to Entergy under the cost reimbursement provisions of the FitzPatrick acquisition agreements. See Note 4—Mergers, Acquisitions, and
Dispositions for more information.
For the year ended December 31, 2015
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
Discrete impacts from EIMA (c)
Amortization of debt costs
Provision for excess and obsolete inventory
Lower of cost or market inventory adjustment
Other
Total other non-cash operating activities
Non-cash investing and financing activities:
Change in capital expenditures not paid
Nuclear fuel procurement (d)
Change in PPE related to ARO update
Indemnification of like-kind exchange position (e)
Non-cash financing of capital projects
Long-term software licensing agreement (f)
Exelon Generation ComEd PECO BGE Pepco DPL ACE
PHI
Predecessor
$ 930 $
342
348 $ 308 $ 94 $ 120 $ 116 $ 47 $ 63 $
73
476
—
(265)
64
(5)
(6)
$ 637 $
269 $ 206 $ 39 $ 65 $
30 $ 15 $ 15 $
7
120
97
(82)
21
7
73
(17)
144
58
10
23
11
$ 1,109 $
$
96 $
57
885
—
77
95
551
—
53
—
—
—
5
—
—
144
4
1
—
3
8
22
—
(82)
21
—
—
(17)
—
15
9
23
—
268 $ 416 $ 70 $ 137 $
—
30
—
—
—
2
—
—
—
2
—
—
(3)
—
15
—
—
—
—
73
—
—
2
—
—
(18)
—
21
—
—
—
2
1
—
—
—
—
—
—
—
20
—
—
—
1
(3)
—
—
—
—
—
—
—
20
—
—
—
1
—
—
—
—
—
—
1
54 $ 33 $ 37 $
82 $
57
885
—
77
—
—
—
7
—
—
34 $ (13) $ (9) $
(1) $ 3 $ 3 $
—
—
—
—
—
—
—
—
—
—
—
—
—
—
—
—
—
—
—
—
—
—
—
—
—
268
(13)
97
—
61
13
—
—
5
(2)
—
—
2
1
—
(10)
167
6
—
—
—
—
—
Table of Contents
Combined Notes to Consolidated Financial Statements—(Continued)
(Dollars in millions, except per share data unless otherwise noted)
(a)
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 16—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) 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 3—Regulatory Matters for more information.
(d) Relates to the nuclear fuel procurement contract for the purchase of fixed quantities of converted uranium, which was delivered to Generation in 2015. Generation is
required to make payments starting September 28, 2018, with the final payment being due no later than September 30, 2020.
(e) See Note 15—Income Taxes for discussion of the like-kind exchange tax position.
(f) Relates to a long-term software license agreement entered into on May 30, 2015. Exelon is required to make payments starting August of 2015 through May of 2024. See
Note 14—Debt and Credit Agreements for additional information.
For the year ended December 31, 2014
Cash paid (refunded) during the year:
Interest (net of amount capitalized)
Income taxes (net of refunds)
Exelon Generation
ComEd PECO BGE Pepco DPL ACE
PHI
Predecessor
$
940 $
314
322
227
$
292 $
(6)
94 $ 111 $ 111 $ 45 $ 61 $
(58)
85
(21)
(43)
(3)
Other non-cash operating activities:
Pension and non-pension postretirement benefit costs
Loss 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
Discrete impacts from EIMA (c)
Amortization of debt costs
Lower of cost or market inventory adjustment
Other
Total other non-cash operating activities
Non-cash investing and financing activities:
Change in PPE related to ARO update
Change in capital expenditures not paid
Fair value of net assets recorded upon CENG consolidation (e)
Issuance of equity units (f)
Nuclear fuel procurement (g)
Indemnification of like-kind exchange position (h)
$
560 $
22
156
5
91
(132)
122
11
65
(23)
44
53
53
29
(2)
$ 1,054 $
$
72 $
220
3,400
131
70
—
249
20
14
5
—
(132)
122
—
—
(23)
44
—
12
29
6
346
$
162 $
36 $ 64 $
22 $
—
26
—
—
—
—
8
—
—
—
53
4
—
2
255 $
—
52
—
—
—
—
3
—
—
—
—
2
—
(1)
92 $ 180 $
—
64
—
—
—
—
—
65
—
—
—
2
—
(15)
7 $ 13 $
—
13
—
—
—
—
—
—
—
—
—
—
—
—
—
17
—
—
—
—
3
3
—
—
—
—
—
(8)
37 $ 22 $ 26 $
—
14
—
—
—
—
2
(1)
—
—
—
—
—
—
$
72
(61) (d)
3,400
—
70
—
$ — $ — $ — $ — $ — $ — $
78
—
—
—
5
—
—
—
—
—
25
—
—
—
—
10
—
—
—
—
8
—
—
—
—
9
—
—
—
—
257
(2)
58
—
49
—
18
—
—
5
2
—
—
—
1
—
(6)
127
—
28
—
—
—
—
(a)
(b)
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 16—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.
552
Table of Contents
Combined Notes to Consolidated Financial Statements—(Continued)
(Dollars in millions, except per share data unless otherwise noted)
(c) 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 3—Regulatory Matters for more information.
Includes $170 million of changes in capital expenditures not paid between December 31, 2014 and 2013 related to Antelope Valley.
(d)
(e) See Note 5—Investment in Constellation Energy Nuclear Group, LLC for additional information.
(f) Relates to the present value of the contract payments for the equity units issued by Exelon. See Note 21—Stock-Based Compensation Plans for additional information.
(g) Relates to the nuclear fuel procurement contracts for the purchase of fixed quantities of uranium, which was delivered to Generation in 2014. Generation is required to
make payments starting June 30, 2016, with the final payment being due no later than June 30, 2018.
(h) See Note 15—Income Taxes for discussion of the like-kind exchange tax position.
DOE Smart Grid Investment Grant (Exelon, PECO and BGE). For the year ended December 31, 2014, PECO has included in the capital
expenditures line item under investing activities of the cash flow statement capital expenditures of $2 million and reimbursements of $5 million
related to PECO’s DOE SGIG programs. For the years ended December 31, 2016 and 2015, PECO had no capital expenditures or reimbursements,
as the DOE SGIG program was completed during 2014. See Note 3—Regulatory Matters for additional information regarding the DOE SGIG.
Supplemental Balance Sheet Information
The following tables provide additional information about assets and liabilities of the Registrants at December 31, 2016 and 2015.
Exelon Generation ComEd PECO
BGE
PHI
Pepco
DPL
ACE
Successor
December 31, 2016
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
(c)
Other cost method investments
Other available for sale investments
$
22 $
216
57
16
311
232
52
34
6 $
8 $
— $
216
57
15
288
—
—
—
6
—
—
—
8
8 $ — $ — $ — $ —
—
—
—
—
—
—
—
—
—
—
—
—
—
—
—
—
—
—
—
8
—
—
—
44
52
34
418 $
17
—
—
4
—
—
102
—
—
—
133
—
—
—
—
133 $ 102 $ — $ —
—
—
—
553
Total investments
$ 629 $
6 $ 25 $ 12 $
Table of Contents
Combined Notes to Consolidated Financial Statements—(Continued)
(Dollars in millions, except per share data unless otherwise noted)
December 31, 2015
Investments
Equity method investments:
Financing trusts (a)
Bloom
Net Power
Other equity method investments
Total equity method investments
Other investments:
Net investment in leases (b)
Employee benefit trusts and investments (c)
Other cost method investments
Other available for sale investments
Total investments
Exelon Generation ComEd PECO BGE
Pepco DPL ACE
Predecessor
PHI
$
22 $
63
23
4
112
358
85
55
29
$ 639 $
6 $
8 $
8 $
— $
63
23
3
89
—
—
—
6
—
—
—
—
6
31
55
29
210 $
—
—
—
8
—
—
—
8
—
20
—
—
—
4
—
—
6 $ 28 $ 12 $
— $ — $ — $ —
—
—
—
—
—
—
—
—
—
—
—
—
—
—
—
—
—
68
—
—
—
—
—
80
—
—
—
—
80 $ 68 $ — $ —
—
—
—
—
(a)
Includes investments in affiliated financing trusts, which were not consolidated within the financial statements of Exelon and are shown as investments on the
Consolidated Balance Sheets. See Note 1—Significant Accounting Policies for additional information.
(b) Represents direct financing lease investments. See Note 8—Impairment of Long-Lived Assets for additional information.
(c) The Registrants’ investments in these marketable securities are recorded at fair market value.
The following tables provide additional information about liabilities of the Registrants at December 31, 2016 and 2015.
December 31, 2016
Accrued expenses
Compensation-related accruals (a)
Taxes accrued
Interest accrued
Severance accrued
Other accrued expenses
Total accrued expenses
December 31, 2015
Accrued expenses
Compensation-related accruals (a)
Taxes accrued
Interest accrued
Severance accrued
Other accrued expenses
Total accrued expenses
Exelon Generation ComEd PECO BGE
PHI
Pepco DPL ACE
Successor
$1,199 $
723
1,234
44
260
557 $ 199 $ 67 $ 64 $
239
82
15
96
4
30
—
3
78
31
—
2
330
609
2
110
$3,460 $
989 $1,250 $ 104 $175 $
112 $ 30 $ 17 $ 11
9
12
—
6
272 $ 113 $ 36 $ 38
48
21
—
14
4
8
—
7
65
49
19
27
Exelon Generation ComEd PECO BGE
Pepco DPL ACE
Predecessor
PHI
$1,014 $
293
915
21
133
$2,376 $
547 $ 183 $ 66 $ 57 $
186
77
11
114
935 $ 706 $ 109 $110 $
4
35
—
4
23
27
1
2
63
443
3
14
88 $ 26 $ 14 $
56
77
54
23
—
—
14
47
8
23
13
—
26
266 $ 119 $ 31 $ 70
3
8
—
6
(a) Primarily includes accrued payroll, bonuses and other incentives, vacation and benefits.
554
Table of Contents
Combined Notes to Consolidated Financial Statements—(Continued)
(Dollars in millions, except per share data unless otherwise noted)
26. 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.
In the first quarter of 2016, following the consummation of the PHI Merger, three new reportable segments were added: Pepco, DPL and ACE.
As a result, Exelon has twelve reportable segments, which include ComEd, PECO, BGE, PHI’s three reportable segments consisting of Pepco, DPL,
and ACE, and 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”, which includes activities in the South, West and Canada. 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 and return on equity.
Effective with the consummation of the PHI Merger, PHI’s reportable segments have changed based on the information used by the CODM to
evaluate performance and allocate resources. PHI’s reportable segments consist of Pepco, DPL and ACE. PHI’s Predecessor periods’ segment
information has been recast to conform to the current presentation. The reclassification of the segment information did not impact PHI’s reported
consolidated revenues or net income. PHI’s CODM evaluates the performance of and allocates resources to Pepco, DPL and ACE based on net
income and return on equity.
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, which includes portions of Illinois, Pennsylvania, Indiana, Ohio, Michigan,
Kentucky and Tennessee, and the United States footprint of MISO, excluding MISO’s Southern Region, which covers all or most of North
Dakota, South Dakota, Nebraska, Minnesota, Iowa, Wisconsin, the remaining parts of Illinois, Indiana, Michigan and Ohio not covered by
PJM, and parts of Montana, Missouri and Kentucky.
New England represents the operations within ISO-NE covering the states of Connecticut, Maine, Massachusetts, New Hampshire, Rhode
Island and Vermont.
New York represents operations within ISO-NY, which covers the state of New York in its entirety.
ERCOT represents operations within Electric Reliability Council of Texas, covering most of the state of Texas.
555
Table of Contents
•
Other Power Regions :
Combined Notes to Consolidated Financial Statements—(Continued)
(Dollars in millions, except per share data unless otherwise noted)
•
•
•
South represents operations in the FRCC, MISO’s Southern Region, and the remaining portions of the SERC not included within
MISO or PJM, which includes all or most of Florida, Arkansas, Louisiana, Mississippi, Alabama, Georgia, Tennessee, North
Carolina, South Carolina and parts of Missouri, Kentucky and Texas. Generation’s South region also includes operations in the SPP,
covering Kansas, Oklahoma, most of Nebraska and parts of New Mexico, Texas, Louisiana, Missouri, Mississippi and Arkansas.
West represents operations in the WECC, which includes California ISO, and covers the states of California, Oregon, Washington,
Arizona, Nevada, Utah, Idaho, Colorado and parts of New Mexico, Wyoming and South Dakota.
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
revenues net of purchased power and fuel expense (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.
556
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, 2016, 2015, and 2014 is as follows:
Operating revenues (c) :
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
2015
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
2014
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
Intersegment revenues (d) :
2016
2015
2014
Depreciation and amortization:
2016
2015
2014
Operating expenses (c) :
2016
2015
2014
Equity in earnings (losses) of unconsolidated affiliates:
2016
2015
2014
Interest expense, net:
2016
2015
2014
Generation
(a)
ComEd PECO BGE
PHI (e)
Other
(b)
Intersegment
Eliminations Exelon
Successor
$
15,390 $ — $ — $ — $
2,146
215
—
—
—
—
—
5,254
—
—
—
—
2,531
463
—
—
—
2,609
624
—
$
15,944 $ — $ — $ — $
2,433
758
—
—
—
—
—
4,905
—
—
—
—
2,486
546
—
—
—
2,490
645
—
$
14,533 $ — $ — $ — $
2,705
155
—
—
—
—
—
4,564
—
—
—
—
2,448
646
—
—
—
2,460
705
—
— $ — $
—
—
3,506
92
45
—
—
—
—
1,648
— $ — $
—
—
—
—
—
—
—
—
—
1,372
— $ — $
—
—
—
—
—
—
—
—
—
1,285
(1,430) $ 13,960
2,146
211
13,869
1,166
7
—
(4)
(31)
(13)
(1,686)
(744) $ 15,200
2,433
—
757
(1)
9,876
(5)
1,176
(15)
5
(1,367)
(760) $ 13,773
2,704
154
9,467
1,325
6
(1)
(1)
(5)
(26)
(1,279)
1,428 $
745
762
15 $
4
4
8 $
2
2
21 $
14
25
45 $ 1,647 $
—
—
1,367
1,280
(3,159) $
(2,127)
(2,067)
5
5
6
1,879 $
1,054
967
775 $ 270 $ 423 $
707
687
366
371
260
236
16,856 $ 4,056 $ 2,292 $ 2,683 $
16,872
16,923
3,889
3,586
2,404
2,522
2,578
2,726
$
(25) $ — $ — $ — $
(8)
(20)
—
—
—
—
—
—
$
364 $
365
356
461 $ 123 $ 103 $
332
321
114
113
99
106
557
515 $
—
—
74 $
63
53
— $ 3,936
2,450
—
2,314
—
3,549 $ 1,928 $
—
—
1,444
1,353
(3,164) $ 28,200
25,056
(2,131)
25,039
(2,071)
— $
—
—
1 $
1
—
195 $ 290 $
—
—
123
169
— $
—
—
(24)
(7)
(20)
— $ 1,536
1,033
—
1,065
—
$
$
$
Table of Contents
Income (loss) before income taxes:
2016
2015
2014
Income taxes:
2016
2015
2014
Net income (loss):
2016
2015
2014
Capital expenditures:
2016
2015
2014
Total assets:
2016
2015
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
$
$
$
$
$
$
$
$
873
1,850
1,226
290
502
207
558
1,340
1,019
679
706
676
301
280
268
378
426
408
3,078
3,841
3,012
$ 2,734
2,398
1,689
$
$
$
$
587 $ 468 $
521
466
477
351
149 $ 174 $
143
114
189
140
438 $ 294 $
378
352
288
211
(58)
—
—
3
—
—
(61)
—
—
686 $ 934 $
601
661
719
620
1,008
—
—
$
$
$
$
(555)
(219)
(227)
(156)
(41)
(63)
(398)
(177)
(164)
113
65
95
46,974
46,529
$ 28,335
26,532
$ 10,831 $ 8,704 $ 21,025
—
8,295
10,367
$ 10,369
15,389
$
$
$
$
$
$
$
$
$
(5)
(5)
(6)
—
—
—
(5)
(5)
(6)
—
—
—
1,989
3,330
2,486
761
1,073
666
1,204
2,250
1,820
8,553
7,624
6,077
(11,334)
(11,728)
$114,904
95,384
(a) Generation includes the six reportable segments shown below: Mid-Atlantic, Midwest, New England, New York, ERCOT and Other Power Regions. For the year ended
December 31, 2016, intersegment revenues for Generation include revenue from sales to PECO of $290 million, sales to BGE of $608 million, sales to Pepco of
$295 million, sales to DPL of $154 million and sales to ACE of $37 million in the Mid-Atlantic region, and sales to ComEd of $47 million in the Midwest region, which
eliminate upon consolidation. For the year ended December 31, 2015, intersegment revenues for Generation include revenue from sales to PECO of $224 million and
sales to BGE of $502 million in the Mid-Atlantic region, and sales to ComEd of $18 million in the Midwest region, which eliminate upon consolidation. For the year ended
December 31, 2014, intersegment revenues for Generation include revenue from sales to PECO of $198 million and sales to BGE of $387 million in the Mid-Atlantic
region, and sales to ComEd of $176 million in the Midwest region, net of $7 million related to the unrealized mark-to-market losses related to the ComEd swap, which
eliminate upon consolidation.
(b) Other primarily includes Exelon’s corporate operations, shared service entities and other financing and investment activities.
(c) For the years ended December 31, 2016, 2015 and 2014, utility taxes of $122 million, $105 million and $89 million, respectively, are included in revenues and expenses
for Generation. For the years ended December 31, 2016, 2015 and 2014, utility taxes of $242 million, $236 million and $238 million, respectively, are included in revenues
and expenses for ComEd. For the years ended December 31, 2016, 2015 and 2014, utility taxes of $136 million, $133 million and $128 million, respectively, are included
in revenues and expenses for PECO. For the years ended December 31, 2016, 2015 and 2014, utility taxes of $85 million, $85 million and $86 million are included in
revenues and expenses for BGE, respectively.
Intersegment revenues exclude sales to unconsolidated affiliates. The intersegment profit associated with Generation’s sale of certain products and services by and
between Exelon’s segments is not eliminated in consolidation due to the recognition of intersegment profit in accordance with regulatory accounting guidance. For Exelon,
these amounts are included in operating revenues in the Consolidated Statements of Operations and Comprehensive Income.
(d)
(e) Amounts included represent activity for PHI’s successor period, March 24, 2016 through December 31, 2016. PHI includes the three reportable segments: Pepco, DPL
and ACE. See tables below for PHI’s predecessor periods, including Pepco, DPL and ACE, for January 1, 2016 to March 23, 2016 and for the years ended December 31,
2015 and December 31, 2014.
558
Table of Contents
Combined Notes to Consolidated Financial Statements—(Continued)
(Dollars in millions, except per share data unless otherwise noted)
Successor and Predecessor PHI:
Operating revenues (a) :
March 24, 2016 to December 31, 2016—Successor
Rate-regulated electric revenues
Rate-regulated natural gas revenues
Shared service and other revenues
January 1, 2016 to March 23, 2016—Predecessor
Rate-regulated electric revenues
Rate-regulated natural gas revenues
Shared service and other revenues
December 31, 2015—Predecessor
Rate-regulated electric revenues
Rate-regulated natural gas revenues
Shared service and other revenues
December 31, 2014—Predecessor
Rate-regulated electric revenues
Rate-regulated natural gas revenues
Shared service and other revenues
Intersegment revenues:
March 24, 2016 to December 31, 2016—Successor
January 1, 2016 to March 23, 2016—Predecessor
December 31, 2015—Predecessor
December 31, 2014—Predecessor
Depreciation and amortization:
March 24, 2016 to December 31, 2016—Successor
January 1, 2016 to March 23, 2016—Predecessor
December 31, 2015—Predecessor
December 31, 2014—Predecessor
Operating expenses:
March 24, 2016 to December 31, 2016—Successor
January 1, 2016 to March 23, 2016—Predecessor
December 31, 2015—Predecessor
December 31, 2014—Predecessor
Interest expense, net:
March 24, 2016 to December 31, 2016—Successor
January 1, 2016 to March 23, 2016—Predecessor
December 31, 2015—Predecessor
December 31, 2014—Predecessor
Income (loss) before income taxes:
March 24, 2016 to December 31, 2016—Successor
January 1, 2016 to March 23, 2016—Predecessor
December 31, 2015—Predecessor
December 31, 2014—Predecessor
Income taxes:
March 24, 2016 to December 31, 2016—Successor
January 1, 2016 to March 23, 2016—Predecessor
December 31, 2015—Predecessor
December 31, 2014—Predecessor
Net income (loss):
March 24, 2016 to December 31, 2016—Successor
January 1, 2016 to March 23, 2016—Predecessor
December 31, 2015—Predecessor
December 31, 2014—Predecessor
Capital Expenditures:
March 24, 2016 to December 31, 2016—Successor
January 1, 2016 to March 23, 2016—Predecessor
December 31, 2015—Predecessor
December 31, 2014—Predecessor
Total assets:
December 31, 2016—Successor
December 31, 2015—Predecessor
Pepco DPL ACE
Other
(b)
Intersegment
Eliminations
PHI
$ 1,675 $ 850 $ 989 $
—
— — —
5 $
92 — —
45
42 $
$ 511 $ 279 $ 268 $
1
56 —
—
— — — —
210 $
$ 2,129 $ 1,138 $ 1,295 $
—
1
164 —
— — — —
264 $
$ 2,055 $ 1,088 $ 1,210 $
—
194 — —
— — — —
$
4 $
1
5
5
5 $
2
6
7
2 $
47 $
1 —
4 —
4 —
$ 224 $ 120 $ 128 $
37
175
155
71
256
212
37
148
122
443
$ 1,577 $ 952 $ 1,000 $
251
1,790 1,137 1,161
1,706 1,075 1,073
284
98 $
29
124
115
38 $
12
50
48
47 $
15
64
64
43 $
11
45
38
33 $
73
220
350
12 $
11
43
42
36 $
47
289
264
(30) $
43
125
169
(51) $
5
73
76
(84) $
59
23
306
26 $
15
102
93
5 $
17
49
65
(5) $
1
33
30
(23) $
(16)
(48)
(228)
10 $
32
187
171
(35) $
26
76
104
(47) $
5
40
46
$ 489 $ 277 $ 218 $
93
300
225
97
544
567
72
352
352
(34) $
(44)
25
(78)
24 $
11
34
79
$
$
$
$
(13) $ 3,506
92
—
45
—
(4) $ 1,096
57
—
— —
(2) $ 4,770
—
165
— —
(3) $ 4,614
—
194
— —
(13) $
45
(4) —
(15) —
(16) —
— $
(4)
—
(1)
515
152
624
526
(13) $ 3,549
(3) 1,048
— 4,308
(1) 4,203
— $
(2)
(1)
—
71 $
(118)
(29)
(435)
— $
—
27
178
45 $
—
(1)
(1)
195
65
280
269
(58)
36
481
380
3
17
163
138
(61)
19
327
242
— $ 1,008
—
273
— 1,230
— 1,223
$ 7,335 $ 4,153 $ 3,457 $ 10,804 $
6,908 3,969 3,387 7,162
(4,724) $ 21,025
(5,238) 16,188
559
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 on the Registrants’
Consolidated Statements of Operations and Comprehensive Income. See Note 25—Supplemental Financial Information for total utility taxes for the year ended
December 31, 2016 and 2015
(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.
Generation total revenues:
2016
2015
2014
Mid-Atlantic (a)
Midwest
New England
New York (a)
ERCOT
Other Power Regions
Total Revenues for Reportable
Segments
Other (c)
Total Generation Consolidated
$ 6,212 $
4,402
1,778
1,198
831
969
$15,390 $
2,361
Revenues
from
external
customers
(b)
Intersegment
revenues
Total
revenues
Revenues
from
external
customers
(b)
Intersegment
revenues
Total
revenues
Revenues
from
external
customers
(b)(d)
(33) $ 6,179 $ 5,974 $
10
(9)
(42)
6
(62)
4,712
2,217
996
863
1,182
4,412
1,769
1,156
837
907
(74) $ 5,900 $ 5,414 $
(2)
(5)
(11)
(6)
(80)
4,710
2,212
985
857
1,102
4,488
1,468
846
938
1,379
Intersegment
revenues (d)
Total
revenues
(155) $ 5,259
4,475
1,422
843
935
1,309
(13)
(46)
(3)
(3)
(70)
(130) $15,260 $15,944 $
130
2,491
3,191
(178) $15,766 $14,533 $
178
2,860
3,369
(290) $14,243
3,150
290
Operating Revenues
$17,751 $
— $17,751 $19,135 $
— $19,135 $17,393 $
— $17,393
(a) On April 1, 2014, Generation assumed operational control of CENG’s nuclear fleet. As a result, beginning on April 1, 2014, CENG’s revenues are included on a fully
consolidated basis.
Includes all wholesale and retail electric sales to third parties and affiliated sales to the Utility Registrants.
(b)
(c) Other represents activities not allocated to a region. See text above for a description of included activities. Also includes a $52 million decrease to revenues, a $7 million
increase to revenues, and a $289 million decrease to revenues for the amortization of intangible assets related to commodity contracts recorded at fair value for the years
ended December 31, 2016, 2015, and 2014, respectively, unrealized mark-to-market losses of $500 million, gains of $203 million, and losses of $174 million for the years
ended December 31, 2016, 2015, and 2014, respectively, and elimination of intersegment revenues.
(d) Exelon corrected an error in the December 31, 2014 balances within Intersegment revenues and Revenues from external customers for an overstatement of Intersegment
revenues for Reportable Segments of $284 million for the year ended December 31, 2014, an understatement of Revenues from external customers for Reportable
Segments of $284 million for the year ended December 31, 2014, an understatement of Intersegment revenues for Other of $284 million for the year ended December 31,
2014, and an overstatement of Revenues from external customers for Other of $284 million for the year ended December 31, 2014. The error is not considered material to
any prior period, and there is no net impact to Total Revenues.
560
Table of Contents
Combined Notes to Consolidated Financial Statements—(Continued)
(Dollars in millions, except per share data unless otherwise noted)
Generation total revenues net of purchased power and fuel expense:
2016
2015
2014
RNF from
external
customers (b)
Intersegment
RNF
Total
RNF
RNF from
external
customers (b)
Intersegment
RNF
Total
RNF
RNF from
external
customers (b)(d)
Intersegment
RNF (d)
Mid-Atlantic (a)
Midwest
New England
New York (a)
ERCOT
Other Power Regions
Total Revenues net of
$
3,282 $
2,969
467
761
412
483
35 $3,317 $
2 2,971
438
742
281
336
(29)
(19)
(131)
(147)
3,556 $
2,912
519
584
425
440
15 $3,571 $
(20) 2,892
461
(58)
634
50
293
(132)
250
(190)
3,544 $
2,607
450
439
573
517
Total
RNF
(113) $3,431
(8) 2,599
351
483
317
327
(99)
44
(256)
(190)
8,374 $
547
(289) $8,085 $
836
289
8,436 $
678
(335) $8,101 $
335 1,013
8,130 $
(662)
(622) $7,508
(40)
622
purchased power and fuel
expense for Reportable
Segments
$
Other (c)
Total Generation Revenues
net of purchased power
and fuel expense
$
8,921 $
— $8,921 $
9,114 $
— $9,114 $
7,468 $
— $7,468
(a) On April 1, 2014, Generation assumed operational control of CENG’s nuclear fleet. As a result, beginning on April 1, 2014, CENG’s revenues net of purchased power and
fuel expense are included on a fully consolidated basis.
Includes purchases and sales from third parties and affiliated sales to the Utility Registrants.
(b)
(c) Other represents activities not allocated to a region. See text above for a description of included activities. Also includes a $57 million decrease in RNF, a $8 million
increase in RNF, and a $124 million decrease in RNF for the amortization of intangible assets related to commodity contracts recorded at fair value for the years ended
December 31, 2016, 2015, and 2014, respectively, unrealized mark-to-market losses of $41 million, gains of $257 million, and losses of $591 million for the years ended
December 31, 2016, 2015, and 2014, respectively, accelerated nuclear fuel amortization associated with the initial early retirement decision for Clinton and Quad Cities as
discussed in Note 9—Early Nuclear Plant Retirements of $60 million for the year ended December 31, 2016, and the elimination of intersegment revenues net of
purchased power and fuel expense.
(d) Exelon corrected an error in the December 31, 2014 balances within Intersegment RNF and RNF from external customers for an understatement of $8 million of
Intersegment RNF for Reportable Segments for the year ended December 31, 2014, an understatement of RNF from external customers for Reportable Segments of
$11 million for the year ended December 31, 2014, an overstatement of $8 million of Intersegment RNF for Other for the year ended December 31, 2014, and an
overstatement of RNF from external customers for Other of $11 million for the year ended December 31, 2014. This also included an understatement of total RNF for
Reportable Segments and an overstatement of total RNF for Other of $19 million for the year ended December 31, 2014. The error is not considered material to any prior
period, and there is no net impact to Generation Total RNF for 2014.
561
Table of Contents
Combined Notes to Consolidated Financial Statements—(Continued)
(Dollars in millions, except per share data unless otherwise noted)
27. 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:
PECO (a)
CENG (b)
BGE (a)
Other
Total operating revenues from affiliates
Purchase power and fuel from affiliates:
CENG (c)
Keystone Fuels, LLC (d)
Conemaugh Fuels, LLC (d)
Safe Harbor Water Power Corp (d)
Total purchase power and fuel 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:
CENG (e)
Qualifying facilities and domestic power projects
Other
Total losses in equity method investments
Payables to affiliates (current):
ComEd Financing III
PECO Trust III
BGE Capital Trust II
Total payables to affiliates (current)
Long-term debt due to financing trusts:
ComEd Financing III
PECO Trust III
PECO Trust IV
BGE Capital Trust II
Total long-term debt due to financing trusts
562
For the Years Ended
December 31,
2016
2015
2014
1
$
—
4
5
$ 10
$ —
—
—
—
$ —
$ 13
6
6
16
$ 41
$ —
(25)
1
$ (24)
1
$
—
4
4
9
$
$ —
—
—
—
$ —
$ 13
6
6
16
$ 41
$ —
(8)
1
$ (7)
1
$
17
5
—
$ 23
$282
138
99
12
$531
$ 13
6
6
16
$ 41
$ (19)
(1)
—
$ (20)
December 31,
2016
2015
$
$
4
1
3
8
$205
81
103
252
$641
$
$
4
1
3
8
$205
81
103
252
$641
Table of Contents
Combined Notes to Consolidated Financial Statements—(Continued)
(Dollars in millions, except per share data unless otherwise noted)
(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 accounting guidance. For Exelon, these amounts are included in operating revenues in the Consolidated
Statements of Operations. See Note 3—Regulatory Matters for additional information.
(b) Beginning in 2012, Generation entered into a power services agency agreement (PSAA) with the CENG plants, which as of April 1, 2014, was amended and extended
until the permanent cessation of power generation by the CENG generation plants. The PSAA is an agreement under which Generation provides scheduling, asset
management and billing services to the CENG plants for a specified monthly fee. The charges for services reflect the cost of the services. On April 1, 2014, Generation
and CENG entered into a Nuclear Operating Services Agreement (NOSA) pursuant to which Generation will operate the CENG nuclear generation fleet owned by CENG
subsidiaries and provide corporate and administrative services for the remaining life of the CENG nuclear plants as if they were part of the Generation nuclear fleet. For
further information regarding the Investment in CENG, see Note 5—Investment in Constellation Energy Nuclear Group, LLC.
(c) CENG owns 100% of four nuclear units in Maryland and New York and 82% of Nine Mile Point Unit 2 in New York. Beginning in 2012, Generation had a PPA under which
it purchased 85% of the nuclear plant output owned by CENG that was not sold to third parties under pre-existing unit-contingent PPAs through 2014. Beginning on
January 1, 2015 and continuing to the end of the life of the respective plants, Generation will purchase on a unit-contingent basis 50.01% of the nuclear plant output
owned by CENG and a subsidiary of EDF will purchase on a unit-contingent basis 49.99% of the nuclear plant output owned by CENG (EDF PPA) not sold to third parties.
Beginning April 1, 2014, sales to Generation are eliminated in consolidation. For further information regarding the Investment in CENG, see Note 5—Investment in
Constellation Energy Nuclear Group, LLC.
(d) During 2014, Generation closed the sale of Safe Harbor Water Power Corporation, Keystone Fuels, LLC, and Conemaugh Fuels LLC. Generation recorded purchase
power and fuel costs from affiliates related to these generating assets during the time these assets were still partially owned by Generation. See Note 4—Mergers,
Acquisitions, and Dispositions for more information.
(e) Prior to April 1, 2014, Generation’s total gain (loss) in equity method investments includes equity investment income (loss) and amortization of the basis difference
established as a result of purchase accounting applied upon Constellation merger in 2012. CENG was fully consolidated on April 1, 2014. For further information regarding
the Investment in CENG, see Note 5—Investment in Constellation Energy Nuclear Group, LLC.
563
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)
CENG (g)
BSC
Other
Total operating revenues from affiliates
Purchase power and fuel from affiliates:
ComEd
BGE
CENG (h)
Keystone Fuels, LLC (l)
Conemaugh Fuels, LLC (l)
Safe Harbor Water Power Corporation (l)
Total purchase power and fuel from affiliates
Operating and maintenance from affiliates:
ComEd (i)
PECO (i)
BGE (i)
PHI
Pepco
BSC (j)
Total operating and maintenance from affiliates
Interest expense to affiliates, net:
Exelon Corporate (m)
Earnings (losses) in equity method investments
CENG (k)
Qualifying facilities and domestic power projects
Total losses in equity method investments
Capitalized costs
BSC (j)
Cash distribution paid to member
Contribution from member
564
For the Years Ended
December 31,
2015
2016
$
47
290
608
295
154
37
—
2
6
$1,439
$ —
12
—
—
—
—
12
$
$
7
3
1
1
1
650
$ 663
$
18
224
502
—
—
—
—
1
4
$ 749
$ —
14
—
—
—
—
14
$
$
4
2
—
—
—
614
$ 620
2014
$176
198
387
—
—
—
17
1
—
$779
$
1
25
282
138
99
12
$557
$
3
2
—
—
—
618
$623
$
39
$
43
$ 53
$ —
(25)
(25)
$
$ —
(8)
(8)
$
$
98
$ 922
$ 142
$
76
$2,474
47
$
$ (19)
(1)
$ (20)
$ 91
$645
$ 53
Table of Contents
Combined Notes to Consolidated Financial Statements—(Continued)
(Dollars in millions, except per share data unless otherwise noted)
December 31,
2016
2015
Receivables from affiliates (current):
ComEd (a)
PECO (b)
BGE (c)
Pepco (d)
DPL (e)
ACE (f)
PHISCO (j)
PCI
Other
Total receivables from affiliates (current)
Intercompany money pool (current):
Exelon Corporate
PCI
Total intercompany money pool (current)
Payables to affiliates (current):
Exelon Corporate (m)
BSC (j)
ComEd
Other
Total payables to affiliates (current)
Long-term debt due to affiliates (noncurrent):
Exelon Corporate (o)
Payables to affiliates (noncurrent):
BSC (g)
ComEd (n)
PECO (n)
Total payables to affiliates (noncurrent)
$
14
33
26
44
16
9
5
8
1
$ 156
$
15
36
31
—
—
—
—
—
1
83
$
$ —
55
55
$
$1,252
—
$1,252
$
22
99
9
7
$ 137
$
16
78
9
1
$ 104
$ 922
$ 933
$
1
2,169
438
$2,608
$ —
2,172
405
$2,577
(a) Generation has an ICC-approved RFP contract with ComEd to provide a portion of ComEd’s electricity supply requirements. Generation also sells RECs to ComEd. In
addition, Generation had revenue from ComEd associated with the settled portion of the financial swap contract established as part of the Illinois Settlement. See Note 3—
Regulatory Matters for additional information.
(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. See Note 3—Regulatory Matters for additional information.
(c) Generation provides a portion of BGE’s energy requirements under its MDPSC-approved market-based SOS and gas commodity programs. See Note 3—Regulatory
Matters for additional information.
(d) Generation provides electric supply to Pepco under contracts executed through Pepco’s competitive procurement process approved by the MDPSC and DCPSC. See
Note 3—Regulatory Matters for additional information.
(e) Generation provides a portion of DPL’s energy requirements under its MDPSC and DPSC approved market based SOS and gas commodity programs. See Note 3—
Regulatory Matters for additional information.
(f) Generation provides electric supply to ACE under contracts executed through ACE’s competitive procurement process. See Note 3—Regulatory Matters for additional
information.
(g) Beginning in 2012, Generation entered into a power services agency agreement (PSAA) with the CENG plants, which as of April 1, 2014, was amended and extended
until the permanent cessation of power generation by the CENG generation plants. The PSAA is an agreement under which Generation provides scheduling, asset
management and billing services to
565
Table of Contents
Combined Notes to Consolidated Financial Statements—(Continued)
(Dollars in millions, except per share data unless otherwise noted)
the CENG plants for a specified monthly fee. The charges for services reflect the cost of the services. On April 1, 2014, Generation and CENG entered into a Nuclear
Operating Services Agreement (NOSA) pursuant to which Generation will operate the CENG nuclear generation fleet owned by CENG subsidiaries and provide corporate
and administrative services for the remaining life of the CENG nuclear plants as if they were part of the Generation nuclear fleet. For further information regarding the
Investment in CENG, see Note 5—Investment in Constellation Energy Nuclear Group, LLC.
(h) CENG owns 100% of four nuclear units in Maryland and New York and 82% of Nine Mile Point Unit 2 in New York. Beginning in 2012, Generation had a PPA under which
it purchased 85% of the nuclear plant output owned by CENG that was not sold to third parties under pre-existing unit-contingent PPAs through 2014. Beginning on
January 1, 2015 and continuing to the end of the life of the respective plants, Generation will purchase on a unit-contingent basis 50.01% of the nuclear plant output
owned by CENG and a subsidiary of EDF will purchase on a unit-contingent basis 49.99% of the nuclear plant output owned by CENG (EDF PPA) not sold to third parties.
Beginning April 1, 2014, sales to Generation are eliminated in consolidation. For further information regarding the Investment in CENG, see Note 5—Investment in
Constellation Energy Nuclear Group, LLC.
(i) 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.
(j) Generation 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.
(k) Prior to April 1, 2014, Generation’s total gain (loss) in equity method investments includes equity income (loss) and amortization of the basis difference established as a
result of purchase accounting applied upon Constellation merger in 2012. CENG was fully consolidated on April 1, 2014. For further information regarding the Investment
in CENG, see Note 5—Investment in Constellation Energy Nuclear Group, LLC.
(l) During 2014, Generation closed the sale of Safe Harbor Water Power Corporation, Keystone Fuels, LLC, and Conemaugh Fuels LLC. Generation recorded purchase
power and fuel costs from affiliates related to these generating assets during the time these assets were still partially owned by Generation. See Note 4—Mergers,
Acquisitions, and Dispositions for more information.
(m) 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.
(n) 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
(o)
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 16—Asset Retirement Obligations.
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 affiliate on Generation’s Consolidated Balance Sheets and intercompany notes receivable at Exelon Corporate, which are eliminated in consolidation
on Exelon’s Consolidated Balance Sheets.
566
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 affiliate
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
Contribution from parent
Prepaid voluntary employee beneficiary association trust (c)
Receivable from affiliates (current):
Voluntary employee beneficiary association trust
Generation
Exelon Corporate (e)
Total receivable from affiliates (current)
Receivable from affiliates (noncurrent):
Generation (d)
Other
Total receivable from affiliates (noncurrent)
Payables to affiliates (current):
Generation (a)
BSC (b)
ComEd Financing III
PECO
Exelon Corporate
Total payables to affiliates (current)
Long-term debt to ComEd financing trust
ComEd Financing III
567
For the Years Ended
December 31,
2016
2015
2014
$
7
6
1
1
$ 15
$
4
—
—
—
4
$
$
4
—
—
—
4
$
$ 47
$ 18
$176
$225
1
1
227
$195
—
—
195
$166
—
—
166
$ 13
$ 13
$ 13
$112
$369
$315
$103
$299
$202
$ 77
$307
$273
December 31,
2016
5
$
2015
11
$
$
2
9
345
$ 356
$
2
9
188
$ 199
$2,169
1
$2,170
$2,172
—
$2,172
$
$
14
42
4
2
3
65
$
$
15
39
4
2
2
62
$ 205
$ 205
Table of Contents
Combined Notes to Consolidated Financial Statements—(Continued)
(Dollars in millions, except per share data unless otherwise noted)
(a) ComEd procures a portion of its electricity supply requirements from Generation under an ICC-approved RFP contract. ComEd also purchases RECs from Generation. In
addition, purchased power expense includes the settled portion of the financial swap contract with Generation, which expired in 2013. See Note 3—Regulatory Matters
and Note 13—Derivative Financial Instruments for additional information.
(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.
(e) Represents indemnification from Exelon Corporate related to the like-kind exchange.
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
Total operating revenues from affiliates
Purchased power from affiliate
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
Total interest expense to affiliates, net
Capitalized costs
BSC (c)
Cash dividends paid to parent
Contribution from parent
568
For the Years Ended
December 31,
2016
2015
2014
$
$
3
3
1
1
8
2
$
—
—
—
2
$
2
$
—
—
—
2
$
$287
$220
$194
$142
2
1
1
$146
$107
3
—
—
$110
$
6
6
$ 12
$
6
6
$ 12
$ 96
3
—
—
$ 99
$
6
6
$ 12
$ 57
$277
$ 18
$ 40
$279
$ 16
$ 39
$320
$ 24
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)
Receivable from affiliate (current):
ComEd
BGE
Total receivable from affiliates (current)
Receivable from affiliate (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,
2016
1
$
2015
2
$
$
$
2
2
4
$
2
—
2
$
$438
$405
$ 33
28
1
1
$ 63
$ 81
103
$184
$ 36
17
1
1
$ 55
$ 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. See Note 3—Regulatory Matters for additional information on AECs.
(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.
569
Table of Contents
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 affiliate
Generation (b)
Operating and maintenance from affiliates:
BSC (c)
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
Contribution from parent
Payables to affiliates (current):
Generation (b)
BSC (c)
Exelon Corporate
PECO
BGE Capital Trust II
Other
Total payables to affiliates (current)
Long-term debt to BGE financing trust
BGE Capital Trust II
For the Years Ended
December 31,
2016
2015
2014
$ 13
6
1
1
$ 21
$ 14
—
—
—
$ 14
$ 25
—
—
—
$ 25
$604
$498
$382
$130
1
1
$132
$118
—
—
$118
$103
—
—
$103
$ 16
$ 16
$ 16
$ 36
$179
$ 61
$ 28
$158
7
$
$ 19
$ —
$ —
December 31,
2016
2015
$ 26
22
1
2
3
1
$ 55
$ 31
17
1
—
3
—
$ 52
$252
$252
(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. See
Note 3—Regulatory Matters for additional information.
(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.
570
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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
Generation
Total operating revenues from affiliates
Purchased power from affiliate
Generation
Operating and maintenance from affiliates:
BSC
PCI
Total operating and maintenance from affiliates
Cash dividends paid to parent
Contribution from member
Payables to affiliates (current):
Generation
BSC
Exelon Corporate
PHI Corporate
Total payables to affiliates (current)
571
Successor
March 24, 2016 to
December 31, 2016
$
$
$
$
$
$
$
44
1
45
486
86
3
89
273
1,251
December 31,
2016
Successor
$
$
74
10
6
4
94
Table of Contents
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)
PHISCO
Total operating revenues from affiliates
Purchased power from affiliate
Generation (b)
Operating and maintenance:
PHISCO (c)
PES (d)
Total operating and maintenance
Operating and maintenance from affiliates:
BSC (c)
PHISCO (c)
Total operating and maintenance from affiliates
Cash dividends paid to parent
Contribution from parent
Payables to affiliates (current):
Generation (b)
BSC (c)
DPL
PHISCO (c)
PES (e)
Other
Total payables to affiliates (current)
For the Years Ended
December 31,
2016
2015
2014
$
$
1
4
5
$ —
5
5
$
$ —
5
5
$
$295
$ —
$ —
$263
39
$302
$240
26
$266
$ 31
4
$ 35
$136
$187
$ —
4
$
4
$146
$112
$220
30
$250
$ —
4
$
4
$ 86
$ 80
December 31,
2016
2015
$ 44
4
1
25
—
—
$ 74
$ —
—
—
25
4
1
$ 30
(a) Pepco provides energy to Generation for Generation’s own use.
(b) Pepco 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. See Note 3—Regulatory Matters for additional information.
(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 performs underground transmission, distribution construction and maintenance services, including services that are treated as capital costs, for Pepco.
(e) Pepco bills customers on behalf of PES where PES has performed work for certain government agencies under a General Services Administration area-wide agreement
on behalf of Pepco.
572
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DPL
Combined Notes to Consolidated Financial Statements—(Continued)
(Dollars in millions, except per share data unless otherwise noted)
The financial statements of DPL include related party transactions as presented in the tables below:
Operating revenues from affiliates:
PHISCO
Other
Total operating revenues from affiliates
Purchased power from affiliate
Generation (a)
Operating and maintenance:
PHISCO (b)
PES (c)
Total operating and maintenance
Operating and maintenance from affiliates:
BSC (b)
Other
Total operating and maintenance from affiliates
Cash dividends paid to parent
Contribution from parent
Receivables from affiliates (current):
Pepco
ACE
Total receivable from affiliates (current)
Payables to affiliates (current):
Generation (a)
BSC (b)
PHISCO (b)
Other
Total payables to affiliates (current)
For the Years Ended
December 31,
2016
2015
2014
$
$
5
2
7
$
$
5
1
6
$
$
6
1
7
$154
$ —
$ —
$194
8
$202
$179
3
$182
$ 18
1
$ 19
$ 54
$152
$ —
1
$
1
$ 92
$ 75
$163
—
$163
$ —
1
$
1
$100
$130
December 31,
2016
2015
$
$
1
2
3
$ 16
3
19
—
$ 38
$ —
—
$ —
$ —
—
19
1
$ 20
(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. See Note 3—Regulatory Matters for additional information.
(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 performs underground transmission construction services, including services that are treated as capital costs, for DPL.
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ACE
Combined Notes to Consolidated Financial Statements—(Continued)
(Dollars in millions, except per share data unless otherwise noted)
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 affiliate
Generation (a)
Operating and maintenance:
PHISCO (b)
Operating and maintenance from affiliates:
BSC (b)
Other
Total operating and maintenance from affiliates
Cash dividends paid to parent
Contribution from parent
Payables to affiliates (current):
Generation (a)
BSC (b)
DPL
PHISCO (b)
Other
Total payables to affiliates (current)
For the Years Ended
December 31,
2016
2015
2014
$
$
2
1
3
$
$
2
2
4
$
$
1
3
4
$ 37
$ —
$ —
$155
$143
$124
$ 15
3
$ 18
$ 63
$139
$ —
3
$
3
$ 12
$ 95
$ —
3
$
3
$ 26
$ —
December 31,
2016
2015
$
9
2
2
16
—
$ 29
$ —
—
—
15
1
$ 16
(a) ACE purchases electric supply from Generation under contracts executed through its competitive procurement process. See Note 3—Regulatory Matters for additional
information.
(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.
574
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Combined Notes to Consolidated Financial Statements—(Continued)
(Dollars in millions, except per share data unless otherwise noted)
28. Quarterly Data (Unaudited) (All Registrants)
Exelon
The data shown below, which may not equal the total for the year due to the effects of rounding and dilution, includes all adjustments that
Exelon considers necessary for a fair presentation of such amounts:
Quarter ended:
March 31
June 30
September 30
December 31
Quarter ended:
March 31
June 30
September 30
December 31
Quarter ended:
March 31
June 30
September 30
December 31
Net Income
Attributable to
Operating Revenues
2015
2016
Operating Income
2015
2016
Common Shareholders
2015
2016
$ 7,573
6,910
9,002
7,875
$ 8,830
6,514
7,401
6,702
$ 483
647
1,267
714
$1,366
1,134
1,200
707
$
$
173
267
490
204
693
638
629
309
Average Basic Shares
Outstanding
(in millions)
Net Income
per Basic Share
2016
2015
2016
2015
923
924
925
925
862
863
913
921
$ 0.19
0.29
0.53
0.22
$ 0.80
0.74
0.69
0.34
Average Diluted Shares
Outstanding
(in millions)
Net Income
per Diluted Share
2016
2015
2016
2015
925
926
927
928
867
866
915
924
$
0.19
0.29
0.53
0.22
$
0.80
0.74
0.69
0.33
The following table presents the New York Stock Exchange—Composite Common Stock Prices and dividends by quarter on a per share basis:
2016
2015
High price
Low price
Close
Dividends
Third
Quarter
Fourth
Quarter
Second
Quarter
First
Quarter
$ 36.36 $ 37.70 $ 36.37 $ 35.95 $ 31.37 $ 34.44 $ 34.98 $ 38.25
31.71
33.61
0.310
31.28
31.42
0.310
33.18
36.36
0.318
28.41
29.70
0.310
25.09
27.77
0.310
29.82
35.49
0.318
32.86
33.29
0.318
26.26
35.86
0.310
Second
Quarter
Fourth
Quarter
Third
Quarter
Quarter
First
575
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Generation
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 Generation considers necessary for a fair presentation of such amounts:
Quarter ended:
March 31
June 30
September 30
December 31
ComEd
Operating Revenues
2016
2015
Operating (Loss) Income
2015
2016
Net (Loss) Income
Attributable to
Membership Interest
2016
2015
$ 4,739
3,589
5,035
4,388
$ 5,840
4,232
4,768
4,294
$
415
(13)
342
94
$
719
703
622
230
$
310
(8)
236
(41)
$
443
398
377
154
The data shown below includes all adjustments that ComEd considers necessary for a fair presentation of such amounts:
Quarter ended:
March 31
June 30
September 30
December 31
PECO
Operating Revenues
Operating Income
Net Income
2016
2015
2016
2015
2016
2015
$ 1,249
1,286
1,497
1,223
$ 1,185
1,148
1,376
1,196
$
274
324
389
217
$
230
243
327
217
$
115
145
37
80
$
90
99
149
87
The data shown below includes all adjustments that PECO 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
Attributable to
Common Shareholders
2016
2015
2016
2015
2016
2015
$
841
664
788
701
$
576
985
661
740
645
$
196
152
204
150
$
223
124
154
128
$
124
100
122
92
$
139
70
90
79
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BGE
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 BGE considers necessary for a fair presentation of such amounts:
Quarter ended:
March 31
June 30
September 30
December 31
PHI
Net Income
Attributable to
Operating Revenues
Operating Income
2016
2015
2016
2015
Common Shareholders
2015
2016
$
929
680
812
812
$ 1,036
628
725
746
$
$
187
59
115
190
$
204
99
110
144
98
31
54
103
$
106
44
51
74
The data shown below includes all adjustments that PHI considers necessary for a fair presentation of such amounts:
Successor
Predecessor Successor
Predecessor Successor
Predecessor
Operating Revenues
Operating (Loss) Income
Net (Loss) Income
Attributable to
Membership Interest
Quarter ended:
March 31
June 30
September 30
December 31
2016
2015
2016
2015
2016
2015
$
105 (a)
$
1,066
1,394
1,078
1,354 $
1,119
1,336
1,126
(411) (a)
136
279
90
$
142 $
139
184
208
(309) (a)
$
52
166
30
53
53
91
130
Predecessor
January 1, 2016—March 23, 2016
Operating Revenues
1,153
Operating Income
105
(a) Amounts for March 31, 2016 reflect the PHI Successor activity for the period March 24, 2016 to March 31, 2016.
Pepco
The data shown below includes all adjustments that Pepco considers necessary for a fair presentation of such amounts:
Net Income
Attributable to
Membership Interest
19
Quarter ended:
March 31
June 30
September 30
December 31
Operating Revenues
Operating
(Loss) Income
Net (Loss) Income
Attributable to
Common Shareholders
2016
2015
2016
2015
2016
2015
$
551
509
635
491
577
$
545
504
592
488
$(105)
97
132
51
$ 63
83
115
123
$
(108)
49
79
23
$
26
42
60
59
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DPL
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 DPL considers necessary for a fair presentation of such amounts:
Quarter ended:
March 31
June 30
September 30
December 31
ACE
Operating Revenues
2016
2015
(Loss) Income
2015
2016
Common Shareholders
2015
2016
Operating
Net (Loss) Income
Attributable to
$
362
281
331
303
$
421
271
314
296
$ (72)
30
72
20
$ 63
24
32
46
$
(72)
12
44
7
$
32
8
15
21
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
2016
2015
Operating
(Loss) Income
2015
2016
Net (Loss) Income
Attributable to
Common Shareholders
2016
2015
$
291
270
421
275
578
$
334
285
386
291
$ (121)
19
83
26
$ 29
25
51
29
$
(100)
3
47
8
$
9
6
22
3
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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 2016, 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, 2016, 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 2016 that have materially affected, or are reasonably likely to materially affect, any of the registrant’s internal
control over financial reporting.
Consistent with guidance issued by the SEC that an assessment of internal control over financial reporting of a recently acquired business may
be omitted from management’s evaluation of disclosure controls and procedures, management is excluding an assessment of such internal controls
of ConEdison Solutions, which was acquired on September 1, 2016, from its evaluation of the effectiveness of Exelon’s and Generation’s disclosure
controls and procedures. The total assets related to ConEdison Solutions are approximately less than 1% and total operating revenues related to
ConEdison Solutions are 1% and 2%, respectively, of Exelon’s and Generation’s related consolidated financial statement amounts as of and for the
year ended December 31, 2016.
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, 2016. As a
result of that assessment, management determined that there were no material weaknesses as of December 31, 2016 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.
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ITEM 9B.
OTHER INFORMATION
All Registrants
None.
580
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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 13, 2017.
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 2017 proxy statement
(2017 Exelon Proxy Statement) and the ComEd information statement (2017 ComEd Information Statement) to be filed with the SEC before April 29,
2017 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 Bruce G. Wilson, Senior Vice President, Deputy General Counsel, and Corporate Secretary, Exelon Corporation, P.O.
Box 805398, Chicago, Illinois 60680-5398.
If any substantive amendments to the Code of Business Conduct are made or any waivers are granted, including any implicit waiver, from a
provision of the Code of Business Conduct, to its Chief Executive Officer, Chief Financial Officer or Corporate Controller, Exelon will disclose the
nature of such amendment or waiver on Exelon’s website, www.exeloncorp.com , or in a report on Form 8-K.
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ITEM 11.
EXECUTIVE COMPENSATION
The information required by this item will be set forth under Executive Compensation Data and Report of the Compensation Committee in the
Exelon Proxy Statement for the 2017 Annual Meeting of Shareholders or the ComEd 2017 Information Statement, which are incorporated herein by
reference.
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ITEM 12.
SECURITY OWNERSHIP OF CERTAIN BENEFICIAL OWNERS AND MANAGEMENT AND RELATED STOCKHOLDER MATTERS
The additional information required by this item will be set forth under Ownership of Exelon Stock in the Exelon Proxy Statement for the 2017
Annual Meeting of Shareholders or the ComEd 2017 Information Statement, which are incorporated herein by reference.
Securities Authorized for Issuance under Exelon Equity Compensation Plans
[A]
[B]
[C]
[D]
Number of securities
remaining available
for future issuance
under equity
compensation plans
(excluding securities
reflected in
column [B]) (Note 3)
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)
Plan Category
Equity compensation plans approved by security
holders
28,108,200
$
32.47
26,042,500
(1) Balance includes stock options, unvested performance shares, and unvested restricted shares that were granted under the Exelon LTIP or predecessor company plans
and shares awarded under those plans and deferred into the stock deferral plan, as well as deferred stock units granted to directors as part of their compensation. For
performance shares granted in 2014, 2015 and 2016, the total includes the maximum number of shares that could be granted, if performance, total shareholder return
modifier, and individual performance multipliers were all at maximum, a total of 9,800,400 shares. At target, the number of securities to be issued for such awards is
4,900,200. The deferred stock units granted to directors includes 357,700 shares to be issued upon the conversion of deferred stock units awarded to members of the
Exelon board of directors, and 105,500 shares to be issued upon the conversion of stock units held by members of the Exelon board of directors that were earned under a
legacy Constellation Energy Group plan. Conversion of stock units to shares will occur after the director terminates service to the Exelon board or the board of any of its
subsidiary companies. See Note 21—Common Stock of the Combined Notes to Consolidated Financial Statements for additional information about the material features
of the plans.
Includes outstanding restricted stock units and performance shares that can be exercised for no consideration. Without such instruments, the weighted-average price of
outstanding options, warrants and rights shown in column [C] would be $46.23.
Includes 21,055,700 shares available for issuance from the company’s employee stock purchase plan.
(2)
(3)
No ComEd securities are authorized for issuance under equity compensation plans.
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ITEM 13.
CERTAIN RELATIONSHIPS AND RELATED TRANSACTIONS AND DIRECTOR INDEPENDENCE
The additional information required by this item will be set forth under Related Persons Transactions and Director Independence in the Exelon
Proxy Statement for the 2017 Annual Meeting of Shareholders or the ComEd 2017 Information Statement, which are incorporated herein by
reference.
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ITEM 14.
PRINCIPAL ACCOUNTING FEES AND SERVICES
The information required by this item will be set forth under The Ratification of PricewaterhouseCoopers LLP as Exelon’s Independent
Accountant for 2017 in the Exelon Proxy Statement for the 2017 Annual Meeting of Shareholders and the ComEd 2017 Information Statement,
which are incorporated herein by reference.
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PART IV
ITEM 15.
EXHIBITS, FINANCIAL STATEMENT SCHEDULES
(a)
The following documents are filed as a part of this report:
Exelon
1.
Financial Statements:
Report of Independent Registered Public Accounting Firm dated February 13, 2017 of PricewaterhouseCoopers LLP
Consolidated Statements of Operations and Comprehensive Income for the Years Ended December 31, 2016, 2015 and 2014
Consolidated Statements of Cash Flows for the Years Ended December 31, 2016, 2015 and 2014
Consolidated Balance Sheets at December 31, 2016 and 2015
Consolidated Statements of Changes in Shareholders’ Equity for the Years Ended December 31, 2016, 2015 and 2014
Notes to Consolidated Financial Statements
2.
Financial Statement Schedules:
Schedule I—Condensed Financial Information of Parent (Exelon Corporate) at December 31, 2016 and 2015 and for the Years Ended
December 31, 2016, 2015 and 2014
Schedule II—Valuation and Qualifying Accounts
Schedules not included are omitted because of the absence of conditions under which they are required or because the required information is
provided in the consolidated financial statements, including the notes thereto.
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Table of Contents
Exelon Corporation and Subsidiary Companies
Schedule I – Condensed Financial Information of Parent (Exelon Corporate)
Condensed Statements of Operations and Other Comprehensive Income
(In millions)
Operating expenses
Operating and maintenance
Operating and maintenance from affiliates
Other
Total operating expenses
Operating loss
Other income and (deductions)
Interest expense, net
Equity in earnings of investments
Interest income from affiliates, net
Other, net
Total other income
Income before income taxes
Income taxes
Net income
Other comprehensive income (loss)
Pension and non-pension postretirement benefit plans:
Prior service benefit reclassified to periodic costs
Actuarial loss reclassified to periodic cost
Pension and non-pension postretirement benefit plan valuation adjustment
Unrealized gain (loss) on cash flow hedges
Unrealized gain on marketable securities
Unrealized (loss) gain on equity investments
Unrealized gain (loss) on foreign currency translation
Reversal of CENG equity method AOCI
Other comprehensive (loss) income
Comprehensive income
For the Years Ended
December 31,
2015
2016
2014
$ 221
51
4
276
(276)
(312)
1,521
39
7
1,255
979
(155)
$1,134
$
(48)
184
(181)
2
1
(4)
10
—
(36)
$1,098
$ —
43
4
47
(47)
(168)
2,461
43
(43)
2,293
2,246
(23)
$2,269
$
(46)
220
(99)
9
—
(3)
(21)
—
60
$2,329
$
9
38
3
50
(50)
(237)
1,779
53
(2)
1,593
1,543
(80)
$1,623
$
(30)
147
(497)
(148)
1
8
(9)
(116)
(644)
$ 979
See Notes to Financial Statements
587
Table of Contents
Exelon Corporation and Subsidiary Companies
Schedule I – Condensed Financial Information of Parent (Exelon Corporate)
Condensed Statements of Cash Flows
(In millions)
Net cash flows provided by operating activities
Cash flows from investing activities
Return on investment of direct financing lease termination
Changes in Exelon intercompany money pool
Note receivable from affiliates
Capital expenditures
Investment in affiliates
Acquisition of business
Other investing activities
Net cash flows (used in) provided by investing activities
Cash flows from financing activities
Issuance of long-term debt
Retirement of long-term debt
Issuance of common stock
Dividends paid on common stock
Proceeds from employee stock plans
Other financing activities
Net cash flows provided by financing activities
(Decrease) Increase in cash and cash equivalents
Cash and cash equivalents at beginning of period
Cash and cash equivalents at end of period
For the Years Ended
December 31,
2015
$ 3,071
2016
$ 1,029
—
1,390
—
—
(1,757)
(6,962)
5
(7,324)
1,800
(46)
—
(1,166)
55
(20)
623
(5,672)
5,690
18
$
—
(1,217)
550
—
(212)
—
(55)
(934)
4,200
(2,263)
1,868
(1,105)
32
(58)
2,674
4,811
879
$ 5,690
2014
806
$
335
(83)
—
1
(70)
—
(126)
57
1,150
(23)
—
(1,065)
35
(84)
13
876
3
879
$
See Notes to Financial Statements
588
Table of Contents
Exelon Corporation and Subsidiary Companies
Schedule I – Condensed Financial Information of Parent (Exelon Corporate)
Condensed Balance Sheets
ASSETS
(In millions)
Current assets
Cash and cash equivalents
Deposit with IRS
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
Non-pension postretirement benefit asset
Notes receivable from affiliates
Other
Total deferred debits and other assets
Total assets
December 31,
2016
2015
$
18
1,250
$ 5,690
—
73
48
88
263
—
1,740
51
4,033
34,869
2,107
—
922
256
42,187
$43,978
272
20
1,478
241
5
7,706
53
3,072
26,119
2,036
108
933
404
32,672
$40,431
See Notes to Financial Statements
589
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
Long-term debt due within one year
Accounts payable
Accrued expenses
Payables to affiliates
Regulatory liabilities
Pension obligations
Other
Total current liabilities
Long-term debt
Deferred credits and other liabilities
Regulatory liabilities
Pension obligations
Non-pension postretirement benefit obligations
Deferred income taxes
Other
Total deferred credits and other liabilities
Total liabilities
Commitments and contingencies
Shareholders’ equity
Common stock (No par value, 2000 shares authorized, 924 shares and 920 shares outstanding at December 31,
2016 and 2015, respectively)
Treasury stock, at cost (35 shares at December 31, 2016 and 2015, respectively)
Retained earnings
Accumulated other comprehensive loss, net
Total shareholders’ equity
BGE preference stock not subject to mandatory redemption
Total liabilities and shareholders’ equity
See Notes to Financial Statements
590
December 31,
2016
2015
$ —
570
2
489
706
16
58
50
1,891
7,193
31
8,608
7
226
182
9,054
18,138
$
188
60
5
440
—
63
52
1
809
6,017
31
7,520
—
134
122
7,807
14,633
18,797
(2,327)
12,030
(2,660)
25,840
—
$43,978
18,678
(2,327)
12,068
(2,624)
25,795
3
$40,431
Table of Contents
1. Basis of Presentation
Exelon Corporation and Subsidiary Companies
Schedule I – Condensed Financial Information of Parent (Exelon Corporate)
Notes to Financial Statements
Exelon Corporate is a holding company that conducts substantially all of its business operations through its subsidiaries. These condensed
financial statements and related footnotes have been prepared in accordance with Rule 12-04, Schedule I of Regulation S-X. These statements
should be read in conjunction with the consolidated financial statements and notes thereto of Exelon Corporation.
Exelon Corporate owns 100% of all of its significant subsidiaries, either directly or indirectly, except for Commonwealth Edison Company
(ComEd), of which Exelon Corporate owns more than 99%, and 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 4—
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, 2016 and December 31, 2015.
Credit Agreements
On May 30, 2014, Exelon Corporate amended and extended its unsecured syndicated revolving credit facility with aggregate bank
commitments of $600 million through May 2019. As of December 31, 2016, Exelon Corporation had available capacity under those commitments of
$571 million. See Note 14—Debt and Credit Agreements of the Combined Notes to Consolidated Financial Statements for further information
regarding Exelon Corporation’s credit agreement.
591
Table of Contents
Long-Term Debt
Exelon Corporation and Subsidiary Companies
Schedule I – Condensed Financial Information of Parent (Exelon Corporate)
Notes to Financial Statements
The following tables present the outstanding long-term debt for Exelon Corporate as of December 31, 2016 and December 31, 2015:
Rates
Maturity
Date
December 31,
2016
2015
Long-term debt
Junior subordinated notes
Contract payment—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 due within one year
Long-term debt
6.5%
2.5%
7.6%
2024
2017
2017-2046
1.6%
(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 2017, 2018, 2019, 2020, 2021 and thereafter are as follows:
2017
2018
2019
2020
2021
Remaining years
Total long-term debt
$1,150
19
6,439
7,608
(8)
(57)
220
(570)
$7,193
$1,150
64
4,639
5,853
(4)
(47)
275
(60)
$6,017
$ 570
—
—
1,450
300
5,288
$7,608
4. Commitments and Contingencies
See Note 24—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.
592
Table of Contents
Exelon Corporation and Subsidiary Companies
Schedule I – Condensed Financial Information of Parent (Exelon Corporate)
Notes to Financial Statements
5. Related Party Transactions
The financial statements of Exelon Corporate include related party transactions as presented in the tables below:
(In millions)
Operating and maintenance from affiliates:
BSC (a)
Interest income from affiliates, net:
Generation
Equity in earnings (losses) of investments:
Exelon Energy Delivery Company, LLC (b)
PCI
BSC
Exelon Ventures Company, LLC (c)
UII, LLC
Exelon Transmission Company, LLC
Exelon Enterprise
Generation
Total equity in earnings of investments
Cash contributions received from affiliates
593
For the Years Ended
December 31,
2015
2016
2014
$
$
51
39
$1,041
6
1
—
(9)
(13)
(1)
496
$1,521
$1,912
$
$
43
43
$1,079
—
—
—
20
(8)
(1)
1,371
$2,461
$3,209
$
$
38
53
$ 958
—
—
926
(6)
(7)
(1)
(91)
$1,779
$1,370
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 (d)
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 (d)
Notes payable to affiliates (current):
ComEd
Accounts payable to affiliates (current):
ComEd
UII, LLC
Total accounts payable to affiliates (current)
December 31,
2016
2015
$
$
15
22
3
1
1
6
48
$ —
16
2
1
1
—
20
$
$
88
—
88
$
$
226
1,252
$ 1,478
$
194
23,003
77
92
5
(5)
21
11,488
(6)
$34,869
$
922
$ —
$
$
345
361
706
$
191
14,163
—
102
3
7
22
11,637
(6)
$26,119
$
$
933
188
$ —
—
$ —
(a) Exelon Corporate receives a variety of corporate support services from BSC, including legal, human resources, financial, information technology and supply management
services. All services are provided at cost, including applicable overhead.
(b) Exelon Energy Delivery Company, LLC consists of ComEd, PECO, BGE, PHI, Pepco, DPL and ACE.
(c) Exelon Ventures Company, LLC primarily consisted of Generation and was fully dissolved as of December 31, 2014. Exelon Enterprises, Exelon Generation Company,
(d)
LLC, and Exelon Consolidations are now directly owned Exelon Corporate investments as of December 31, 2014.
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 affiliate on Generation’s Consolidated Balance Sheets and intercompany notes receivable at Exelon Corporate, which are eliminated in
consolidation on Exelon’s Consolidated Balance Sheets.
594
Table of Contents
Column A
Description
For the year ended December 31, 2016
Allowance for uncollectible accounts (a)
Deferred tax valuation allowance
Reserve for obsolete materials
For the year ended December 31, 2015
Allowance for uncollectible accounts (a)
Deferred tax valuation allowance
Reserve for obsolete materials
For the year ended December 31, 2014
Allowance for uncollectible accounts (a)
Deferred tax valuation allowance
Reserve for obsolete materials
Exelon Corporation and Subsidiary Companies
Schedule II – Valuation and Qualifying Accounts
Column B
Column C
Column D
Column E
Additions and adjustments
Balance at
Beginning
of Period
Charged to
Costs and
Expenses
Charged
to Other
Accounts
(in millions)
Deductions
Balance at
End
of Period
$
$
$
284 $
13
105
311 $
50
95
272 $
13
58
162 $
—
12
113 $
—
10
175 $
—
5
99(b) (c) $
10(b)
1(b)
211(d) $
3
5
27(c)
(27)
2
69(c)
37
34
$
167(d) $
10
2
$
205(d) $
—
2
334
20
113
284
13
105
311
50
95
(a) Excludes the non-current allowance for uncollectible accounts related to PECO’s installment plan receivables of $23 million, $8 million, and $8 million for the years ended
December 31, 2016, 2015, and 2014, respectively.
(b) Primarily represents the addition of PHI’s results as of March 23, 2016, the date of the merger
(c)
(d) Write-off of individual accounts receivable.
Includes charges for late payments and non-service receivables.
595
Table of Contents
Generation
1.
Financial Statements:
Exelon Generation Company, LLC and Subsidiary Companies
Report of Independent Registered Public Accounting Firm dated February 13, 2017 of PricewaterhouseCoopers LLP
Consolidated Statements of Operations and Comprehensive Income for the Years Ended December 31, 2016, 2015 and 2014
Consolidated Statements of Cash Flows for the Years Ended December 31, 2016, 2015 and 2014
Consolidated Balance Sheets at December 31, 2016 and 2015
Consolidated Statements of Changes in Equity for the Years Ended December 31, 2016, 2015 and 2014
Notes to Consolidated Financial Statements
2.
Financial Statement Schedules:
Schedule II—Valuation and Qualifying Accounts
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
596
Table of Contents
Exelon Generation Company, LLC and Subsidiary Companies
Schedule II – Valuation and Qualifying Accounts
Column A
Description
Column B
Balance at
Beginning
of Period
Column C
Additions and adjustments
Charged to
Costs and
Expenses
Charged
to Other
Accounts
(in millions)
Column D
Column E
Deductions
Balance at
End
of Period
For the year ended December 31, 2016
Allowance for uncollectible accounts
Deferred tax valuation allowance
Reserve for obsolete materials
For the year ended December 31, 2015
Allowance for uncollectible accounts
Deferred tax valuation allowance
Reserve for obsolete materials
For the year ended December 31, 2014
Allowance for uncollectible accounts
Deferred tax valuation allowance
Reserve for obsolete materials
$
$
$
77
11
102
60
48
93
57
11
55
$
$
$
597
19
—
6
22
—
9
14
—
5
$
$
$
3
—
—
—
(27)
—
8
37
32
$
$
$
8
2
2
5
10
—
19
—
(1)
$
$
$
91
9
106
77
11
102
60
48
93
Table of Contents
ComEd
1.
Financial Statements:
Commonwealth Edison Company and Subsidiary Companies
Report of Independent Registered Public Accounting Firm dated February 13, 2017 of PricewaterhouseCoopers LLP
Consolidated Statements of Operations and Comprehensive Income for the Years Ended December 31, 2016, 2015 and 2014
Consolidated Statements of Cash Flows for the Years Ended December 31, 2016, 2015 and 2014
Consolidated Balance Sheets at December 31, 2016 and 2015
Consolidated Statements of Changes in Shareholders’ Equity for the Years Ended December 31, 2016, 2015 and 2014
Notes to Consolidated Financial Statements
2.
Financial Statement Schedules:
Schedule II – Valuation and Qualifying Accounts
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
598
Table of Contents
Commonwealth Edison Company and Subsidiary Companies
Schedule II – Valuation and Qualifying Accounts
Column A
Description
For the year ended December 31, 2016
Allowance for uncollectible accounts
Reserve for obsolete materials
For the year ended December 31, 2015
Allowance for uncollectible accounts
Reserve for obsolete materials
For the year ended December 31, 2014
Allowance for uncollectible accounts
Reserve for obsolete materials
Column B
Column C
Column D
Column E
Additions and adjustments
Balance at
Beginning
of Period
Charged to
Costs and
Expenses
Charged
to Other
Accounts
(in millions)
Deductions
Balance at
End
of Period
$
$
$
75 $
3
84 $
2
62 $
2
45 $
4
39 $
1
23(a) $
73(b) $
1
4
18(a) $
66(b) $
2
2
45 $
—
33(a) $
56(b) $
2
2
70
4
75
3
84
2
(a) Primarily charges for late payments and non-service receivables.
(b) Write-off of individual accounts receivable.
599
Table of Contents
PECO
1.
Financial Statements:
PECO Energy Company and Subsidiary Companies
Report of Independent Registered Public Accounting Firm dated February 13, 2017 of PricewaterhouseCoopers LLP
Consolidated Statements of Operations and Comprehensive Income for the Years Ended December 31, 2016, 2015 and 2014
Consolidated Statements of Cash Flows for the Years Ended December 31, 2016, 2015 and 2014
Consolidated Balance Sheets at December 31, 2016 and 2015
Consolidated Statements of Changes in Shareholder’s Equity for the Years Ended December 31, 2016, 2015 and 2014
Notes to Consolidated Financial Statements
2.
Financial Statement Schedules:
Schedule II – Valuation and Qualifying Accounts
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
600
Table of Contents
Column A
Description
For the year ended December 31, 2016
Allowance for uncollectible accounts (a)
Reserve for obsolete materials
For the year ended December 31, 2015
Allowance for uncollectible accounts (a)
Reserve for obsolete materials
For the year ended December 31, 2014
Allowance for uncollectible accounts (a)
Reserve for obsolete materials
PECO Energy Company and Subsidiary Companies
Schedule II – Valuation and Qualifying Accounts
Column B
Column C
Column D
Column E
Additions and adjustments
Balance at
Beginning
of Period
Charged to
Costs and
Expenses
Charged
to Other
Accounts
(in millions)
Deductions
Balance at
End
of Period
$
83 $
1
$
100 $
1
$
107 $
1
32 $
1
37 $
—
52 $
—
7(b) $
61(c) $
—
—
9(b) $
63(c) $
—
—
61
2
83
1
11(b) $
70(c) $
100
—
—
1
(a) Excludes the non-current allowance for uncollectible accounts related to PECO’s installment plan receivables of $23 million, $8 million, and $8 million for the years ended
December 31, 2016, 2015, and 2014, respectively.
(b) Primarily charges for late payments.
(c) Write-off of individual accounts receivable.
601
Table of Contents
BGE
1.
Financial Statements:
Baltimore Gas and Electric Company and Subsidiary Companies
Report of Independent Registered Public Accounting Firm dated February 13, 2017 of PricewaterhouseCoopers LLP
Consolidated Statements of Operations and Comprehensive Income for the Years Ended December 31, 2016, 2015 and 2014
Consolidated Statements of Cash Flows for the Years Ended December 31, 2016, 2015 and 2014
Consolidated Balance Sheets at December 31, 2016 and 2015
Consolidated Statements of Changes in Shareholders’ Equity for the Years Ended December 31, 2016, 2015 and 2014
Notes to Consolidated Financial Statements
2.
Financial Statement Schedules:
Schedule II – Valuation and Qualifying Accounts
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
602
Table of Contents
Baltimore Gas and Electric Company and Subsidiary Companies
Schedule II – Valuation and Qualifying Accounts
Column A
Description
Column B
Balance at
Beginning
of Period
Column C
Additions and adjustments
Charged to
Costs and
Expenses
Charged
to Other
Accounts
(in millions)
Column D
Column E
Deductions
Balance at
End
of Period
For the year ended December 31, 2016
Allowance for uncollectible accounts
Deferred tax valuation allowance
Reserve for obsolete materials
For the year ended December 31, 2015
Allowance for uncollectible accounts
Deferred tax valuation allowance
Reserve for obsolete materials
For the year ended December 31, 2014
Allowance for uncollectible accounts
Deferred tax valuation allowance
Reserve for obsolete materials
(a) Write-off of individual accounts receivable.
(b) Primarily charges for late payments.
$
$
$
49
1
—
67
1
—
46
1
1
$
$
$
603
1
—
—
15
—
—
64
—
—
$
9(b)
—
—
$
— (b)
—
—
$
17(b)
—
—
$
$
$
27(a)
—
—
33(a)
—
—
60(a)
—
1
$
$
$
32
1
—
49
1
—
67
1
—
Table of Contents
PHI
Pepco Holdings LLC and Subsidiary Companies
1.
Successor Company Financial Statements:
Report of Independent Registered Public Accounting Firm dated February 13, 2017 of PricewaterhouseCoopers LLP
Consolidated Statement of Operations and Comprehensive Income for the Periods March 24, 2016 to December 31, 2016
Consolidated Statement of Cash Flows for the Periods March 24, 2016 to December 31, 2016
Consolidated Balance Sheet at December 31, 2016
Consolidated Statement of Changes in Equity for the Periods March 24, 2016 to December 31, 2016
Notes to Consolidated Financial Statements
Predecessor Company Financial Statements:
Report of Independent Registered Public Accounting Firm date February 13, 2017 of PricewaterhouseCoopers LLP
Consolidated Statements of Operations and Comprehensive Income for the Period January 1, 2016 to March 23, 2016 and the Years Ended
December 31, 2015 and 2014
Consolidated Statements of Cash Flows for the Period January 1, 2016 to March 23, 2016 and for the Years Ended December 31, 2015 and
2014 (Predecessor)
Consolidated Balance Sheet at December 31, 2015
Consolidated Statements of Changes in Equity for the Period January 1, 2016 to March 23, 2016 and for the Years Ended December 31,
2015 and 2014
Notes to Consolidated Financial Statements
2.
Successor Financial Statement Schedules:
Schedule II – Valuation and Qualifying Accounts—For the Period March 24, 2016 to December 31, 2016
Predecessor Financial Statement Schedules:
Schedule II – Valuation and Qualifying Accounts—For the Period January 1, 2016 to March 23, 2016 and For the Years Ended
December 31, 2015 and 2014
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
604
Table of Contents
Pepco Holdings LLC and Subsidiary Companies
Schedule II – Valuation and Qualifying Accounts
Column A
Description
Column B
Balance at
Beginning
of Period
Column C
Additions and adjustments
Charged to
Costs and
Expenses
Charged
to Other
Accounts
(in millions)
Column D
Column E
Deductions
Balance at
End
of Period
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
For the Year Ended December 31, 2015
(Predecessor)
Allowance for uncollectible accounts
Deferred tax valuation allowance
Reserve for obsolete materials
For the Year Ended December 31, 2014
(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.
65
—
1
16
—
—
59
—
—
46
—
—
$
$
$
$
5(a)
$
42(b)
$
(53)
—
—
(1)
2(a)
$
22(b)
$
—
—
—
—
5(a)
$
48(b)
$
2
—
—
—
9(a)
$
53(b)
$
40
—
—
—
80
10
2
52
63
—
56
63
—
40
61
—
$
$
$
$
52
63
—
56
63
—
40
61
—
38
21
—
$
$
$
$
605
Table of Contents
Pepco
1.
Financial Statements:
Potomac Electric Power Company
Report of Independent Registered Public Accounting Firm dated February 13, 2017 of PricewaterhouseCoopers LLP
Statements of Operations and Comprehensive Income for the Years Ended December 31, 2016, 2015 and 2014
Statements of Cash Flows for the Years Ended December 31, 2016, 2015 and 2014
Balance Sheets at December 31, 2016 and 2015
Statements of Changes in Shareholder’s Equity for the Years Ended December 31, 2016, 2015 and 2014
Notes to Consolidated Financial Statements
2.
Financial Statement Schedules:
Schedule II – Valuation and Qualifying Accounts
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
606
Table of Contents
Potomac Electric Power Company
Schedule II – Valuation and Qualifying Accounts
Column A
Description
Column B
Balance at
Beginning
of Period
Column C
Additions and adjustments
Charged to
Costs and
Expenses
Charged
to Other
Accounts
(in millions)
Column D
Column E
Deductions
Balance at
End
of Period
For the year ended December 31, 2016
Allowance for uncollectible accounts
Deferred tax valuation allowance
Reserve for obsolete materials
For the year ended December 31, 2015
Allowance for uncollectible accounts
Deferred tax valuation allowance
Reserve for obsolete materials
For the year ended December 31, 2014
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.
$
$
$
17
—
—
16
—
—
16
—
—
$
$
$
607
29
—
3
20
—
—
17
—
—
$
$
$
3(a)
—
—
1(a)
—
—
2(a)
—
—
$
$
$
20(b)
—
2
20(b)
—
—
19(b)
—
—
$
$
$
29
—
1
17
—
—
16
—
—
Table of Contents
DPL
1.
Financial Statements:
Delmarva Power & Light Company
Report of Independent Registered Public Accounting Firm dated February 13, 2017 of PricewaterhouseCoopers LLP
Statements of Operations and Comprehensive Income for the Years Ended December 31, 2016, 2015 and 2014
Statements of Cash Flows for the Years Ended December 31, 2016, 2015 and 2014
Balance Sheets at December 31, 2016 and 2015
Statements of Changes in Shareholder’s Equity for the Years Ended December 31, 2016, 2015 and 2014
Notes to Consolidated Financial Statements
2.
Financial Statement Schedules:
Schedule II – Valuation and Qualifying Accounts
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
608
Table of Contents
Delmarva Power & Light Company
Schedule II – Valuation and Qualifying Accounts
Column A
Description
Column B
Balance at
Beginning
of Period
Column C
Additions and adjustments
Charged to
Costs and
Expenses
Charged
to Other
Accounts
(in millions)
Column D
Column E
Deductions
Balance at
End
of Period
For the year ended December 31, 2016
Allowance for uncollectible accounts
Deferred tax valuation allowance
Reserve for obsolete materials
For the year ended December 31, 2015
Allowance for uncollectible accounts
Deferred tax valuation allowance
Reserve for obsolete materials
For the year ended December 31, 2014
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.
$
$
$
17
—
—
11
—
—
12
—
—
$
$
$
609
23
—
1
20
—
—
13
—
—
$
$
$
2(a)
—
—
2(a)
—
—
4(a)
—
—
$
$
$
18(b)
—
1
16(b)
—
—
18(b)
—
—
$
$
$
24
—
—
17
—
—
11
—
—
Table of Contents
ACE
1.
Financial Statements:
Atlantic City Electric Company and Subsidiary Company
Report of Independent Registered Public Accounting Firm dated February 13, 2017 of PricewaterhouseCoopers LLP
Consolidated Statements of Operations and Comprehensive Income for the Years Ended December 31, 2016, 2015 and 2014
Consolidated Statements of Cash Flows for the Years Ended December 31, 2016, 2015 and 2014
Consolidated Balance Sheets at December 31, 2016 and 2015
Consolidated Statements of Changes in Shareholder’s Equity for the Years Ended December 31, 2016, 2015 and 2014
Notes to Consolidated Financial Statements
2.
Financial Statement Schedules:
Schedule II – Valuation and Qualifying Accounts
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
610
Table of Contents
Atlantic City Electric Company and Subsidiary Company
Schedule II – Valuation and Qualifying Accounts
Column A
Description
Column B
Balance at
Beginning
of Period
Column C
Additions and adjustments
Charged to
Costs and
Expenses
Charged
to Other
Accounts
(in millions)
Column D
Column E
Deductions
Balance at
End
of Period
For the year ended December 31, 2016
Allowance for uncollectible accounts
Deferred tax valuation allowance
Reserve for obsolete materials
For the year ended December 31, 2015
Allowance for uncollectible accounts
Deferred tax valuation allowance
Reserve for obsolete materials
For the year ended December 31, 2014
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.
$
$
$
17
—
—
9
—
—
10
—
—
$
$
$
611
32
—
1
18
—
—
12
—
—
$
$
$
2(a)
—
—
2(a)
—
—
3(a)
—
—
$
$
$
24(b)
—
—
12(b)
—
—
16(b)
—
—
$
$
$
27
—
1
17
—
—
9
—
—
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.
2-1
Description
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).
2-2
2-3
2-4
2-5
2-6
2-7
2-8
2-9
2-10-1
2-10-2
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).
612
Table of Contents
Exhibit No.
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
Description
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 May 8, 2007 (File No. 001-16169, Form
10-Q for the quarter ended September 30, 2008, Exhibit 3-1-2).
Exelon Corporation Amended and Restated Bylaws, as amended on April 26, 2016 (File No. 001-16169, Form 8-K dated
April 29, 2016, Exhibit 4.1).
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)
613
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).
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
May 1, 1993
May 1, 1993
File
Reference
2-2881
2-2881
2-4863
2-5472
2-6821
2-13562
2-14020
2-34051
2-72802
2-72802
1-01401, 1984 Form 10-K
1-01401, 1992 Form 10-K
1-01401, March 31, 1993 Form 10-Q
1-01401, March 31, 1993 Form 10-Q
614
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
4(e)-88
4(e)-89
Table of Contents
Dated as
of
April 15, 2004
September 15, 2006
March 1, 2007
March 15, 2009
September 1, 2012
September 15, 2013
September 15, 2013
September 1, 2014
September 15, 2015
September 1, 2016
File
Reference
Exhibit
No.
0-6844, September 30, 2004 Form 10-Q 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 23, 2013
000-16169, Form 8-K dated
September 15, 2014
000-16844, Form 8-K dated October 5,
2015
000-16844, Form 8-K dated
September 21, 2016
4.1
4.1
4.1
4.1
4.1
4.1
4.1
4.1
4.1
4-2
4-3
Exelon Corporation Direct Stock Purchase Plan (Registration Statement No. 333-206474, Form S-3, Prospectus).
Mortgage of Commonwealth Edison Company to Illinois Merchants Trust Company, Trustee (BNY Mellon Trust Company of
Illinois, as current successor Trustee), dated July 1, 1923, as supplemented and amended by Supplemental Indenture thereto
dated August 1, 1944. (Registration No. 2-60201, Form S-7, Exhibit 2-1).
4-3-1
Supplemental Indentures to Commonwealth Edison Company Mortgage.
Dated as
of
August 1, 1946
April 1, 1953
March 31, 1967
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
File
Reference
2-60201, Form S-7
2-60201, Form S-7
2-60201, Form S-7
2-60201, Form S-7
2-60201, Form S-7
2-60201, Form S-7
2-60201, Form S-7
2-60201, Form S-7
2-60201, Form S-7
2-60201, Form S-7
2-60201, Form S-7
2-60201, Form S-7
2-60201, Form S-7
615
Exhibit
No.
2-1
2-1
2-1
2-1
2-1
2-1
2-1
2-1
2-1
2-1
2-1
2-1
2-1
Table of Contents
Dated as
of
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
September 15, 2006
March 1, 2007
August 30, 2007
December 20, 2007
March 10, 2008
July 12, 2010
August 22, 2011
September 17, 2012
August 1, 2013
January 2, 2014
October 28, 2014
February 18, 2015
November 4, 2015
June 15, 2016
File
Reference
2-60201, Form S-7
2-99665, Form S-3
2-99665, Form S-3
2-99665, Form S-3
2-99665, Form S-3
2-99665, Form S-3
2-99665, Form S-3
2-99665, Form S-3
2-99665, Form S-3
2-99665, Form S-3
33-6879, Form S-3
001-01839, Form 8-K dated
January 22, 2003
001-01839, Form 8-K dated March 6,
2006
001-01839, Form 8-K dated August 28,
2006
001-01839, Form 8-K dated October 2,
2006
001-01839, Form 8-K dated March 23,
2007
001-01839, Form 8-K dated
September 10, 2007
001-01839, Form 8-K dated January 16,
2008
001-01839, Form 8-K dated March 27,
2008
001-01839, Form 8-K dated August 2,
2010
001-01839, Form 8-K dated
September 7, 2011
001-01839, Form 8-K dated October 1,
2012
001-01839, Form 8-K dated August 19,
2013
001-01839, Form 8-K dated January 10,
2014
001-01839, Form 8-K dated
November 10, 2014
001-01839, Form 8-K dated March 2,
2015
001-01839, Form 8-K dated
November 19, 2015
001-01839, Form 8-K dated June 27,
2016
616
Exhibit
No.
2-1
4-3
4-3
4-3
4-3
4-3
4-3
4-3
4-3
4-3
4-9
4-4
4.1
4.1
4.1
4.1
4.1
4.1
4.1
4.1
4.1
4.1
4.1
4.1
4.1
4.1
4.1
4.1
Table of Contents
Exhibit No.
4-3-2
4-3-3
4-4
4-5
4-6
4-7
4-8
4-9
4-10
4-11
4-12
4-13
4-14
4-15
4-16
4-17
4-18
Description
Instrument of Resignation, Appointment and Acceptance dated as of February 20, 2002, under the provisions of the Mortgage
of Commonwealth Edison Company dated July 1, 1923, and Indentures Supplemental thereto, regarding corporate trustee (File
No. 1-1839, 2001 Form 10-K, Exhibit 4-4-2).
Instrument dated as of January 31, 1996, under the provisions of the Mortgage of Commonwealth Edison Company dated
July 1, 1923 and Indentures Supplemental thereto, regarding individual trustee (File No. 1-1839, 1995 Form 10-K, Exhibit
4-29).
Indenture 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).
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. 0-16844, June 30, 2003 Form 10-Q, Exhibit 4.1).
Form of 4.25% Senior Note due 2022 issued by Exelon Generation Company, LLC. (File 333-85496, Form 8-K dated June 18,
2012, Exhibit 4.1).
Form of 5.60% Senior Note due 2042 issued by Exelon Generation Company, LLC. (File 333-85496, Form 8-K dated June 18,
2012, Exhibit 4.2).
Form of 2.80% Senior Note due 2022 issued by Baltimore Gas and Electric Company. (File 1-1910, Form 8-K dated August 17,
2012, Exhibit 4.1).
Form of 3.35% Senior Note due 2023 Baltimore Gas and Electric Company. (File 1-1910, Form 8-K dated June 17, 2013,
Exhibit 4.1).
Form of 6.000% Senior Secured Notes due 2033 issued by Exelon Generation Company, LLC (File No. 333-85496, Form 8-K
dated September 30, 2013, Exhibit No. 4.2).
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. 0-16844, 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. 0-16844, 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).
617
Table of Contents
Exhibit No.
4-19
4-20
4-21
4-22
4-23
4-24
4-25
4-26
4-27
4-28
4-29
Description
Form of 4.00% Exelon Generation Company, LLC Senior Note due 2020 (File No. 333-85496, Form 8-K dated
September 30, 2010, Exhibit 4.1).
Form of 5.75% Exelon Generation Company, LLC Senior Note due 2041 (File No. 333-85496, Form 8-K dated
September 30, 2010, Exhibit 4.2).
Indenture between Constellation Energy Group, Inc. and the Bank of New York, Trustee dated as of March 24, 1999.
(Designated as Exhibit No. 4(a) to the Registration Statement on Form S-3 dated March 29, 1999, filed by Constellation
Energy Group, Inc., File No. 333-75217.)
First Supplemental Indenture between Constellation Energy Group, Inc. and the Bank of New York, Trustee dated as of
January 24, 2003. (Designated as Exhibit No. 4(b) to the Registration Statement on Form S-3 dated January 24, 2003,
filed by Constellation Energy Group, Inc., File No. 333-102723).
Indenture dated as of July 24, 2006 between Constellation Energy Group, Inc. and Deutsche Bank Trust Company
Americas, as trustee. (Designated as Exhibit No. 4(a) to the Registration Statement on Form S-3 filed July 24, 2006, filed
by Constellation Energy Group, Inc., File No. 333-135991).
First Supplemental Indenture between Constellation Energy Group, Inc. and Deutsche Bank Trust Company Americas, as
trustee, dated as of June 27, 2008. (Designated as Exhibit 4(a) to the Current Report on Form 8-K dated June 30, 2008,
filed by Constellation Energy Group, Inc., File No. 1-12869).
Indenture dated June 19, 2008 between Constellation Energy Group, Inc. and Deutsche Bank Trust Company Americas,
as trustee. (Designated as Exhibit No. 4(a) to the Quarterly Report on Form 10-Q for the quarter ended June 30, 2008,
filed by Constellation Energy Group, Inc., File Nos. 1-12869 and 1-1910).
Indenture, dated as of September 30, 2013, among Continental Wind, LLC, the guarantors party thereto and Wilmington
Trust, National Association, as trustee (File No. 333-85496, Form 8-K dated September 30, 2013, Exhibit No. 4.1).
Indenture dated July 1, 1985, between Baltimore Gas and Electric Company and The Bank of New York (Successor to
Mercantile-Safe Deposit and Trust Company), Trustee. (Designated as Exhibit 4(a) to the Registration Statement on Form
S-3, File No. 2-98443); as supplemented by Supplemental Indentures dated as of October 1, 1987 (Designated as Exhibit
4(a) to the Current Report on Form 8-K, dated November 13, 1987, File No. 1-1910) and as of January 26, 1993
(Designated as Exhibit 4(b) to the Current Report on Form 8-K, dated January 29, 1993, filed by Baltimore Gas and
Electric Company, File No. 1-1910).
Indenture and Security Agreement dated as of July 9, 2009, between Baltimore Gas and Electric Company and Deutsche
Bank Trust Company Americas, as trustee (including form of Baltimore Gas and Electric Company Officer’s Certificate and
form of Senior Secured Bond) (Designated as Exhibit Nos. 4(u) and 4(u)(1) 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).
618
Table of Contents
Exhibit No.
4-30
4-31
4-32
4-33
4-34
4-35
4-36
4-37
4-38
4-38-1
4-38-2
4-38-3
Description
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).
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).
Form of 2.50% Notes due 2024 (File No. 001-16169, Form 8-K dated June 23, 2014, Exhibit 4.1).
Purchase Contract and Pledge Agreement, between Exelon Corporation and The Bank of New York Mellon Trust Company,
N.A., as Purchase Contract Agent, Collateral Agent, Custodial Agent and Securities Intermediary. (File No. 001-16169, Form
8-K dated June 23, 2014, Exhibit 4.4).
619
Table of Contents
Exhibit No.
4-38-4
Description
Form of Remarketing Agreement (File No. 001-16169, Form 8-K dated June 23, 2014, Exhibit 4.5).
4-38-5
4-38-6
4-39
4-39-1
4-39-2
4-39-3
4-40
4-41
4-42
Form of Corporate Unit (File No. 001-16169, Form 8-K dated June 23, 2014, Exhibit 4.6).
Form of Treasury Unit (File No. 001-16169, Form 8-K dated June 23, 2014, Exhibit 4.7).
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)
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)
4-42-1
Supplemental Indentures to Potomac Electric Power Company Mortgage.
Dated as
of
December 10, 1939
July 15, 1942
October 15, 1947
December 31, 1948
December 31, 1949
February 15, 1951
February 16, 1953
File
Reference
Form 8-K, 1/3/40
2-5032, Amendment No 2. To Registration
Statement, 8/24/42
Form 8-K , 12/8/47
Form 10-K, 4/13/49
Form 8-K, 2/8/50
Form 8-K, 3/9/51
Form 8-K, 3/5/53
Exhibit
No.
B
B-1
A
A-2
(a)-1
(a)
(a)-1
March 15, 1954 and March 15, 1955
2-11627, Registration Statement, 5/2/55
4-B
March 15, 1956
Form 10-K, 4/4/56
C
620
Table of Contents
Dated as
of
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
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
File
Reference
Exhibit
No.
2-13884, Registration Statement, 2/5/58
2-14518, Registration Statement,
11/10/58
2-15027, Amendment No. 1 to
Registration Statement, 5/13/59
2-17286, Registration Statement, 11/9/60
Form 10-K, 4/24/61
2-21037, Registration Statement, 1/25/63
2-21961, Registration Statement,
12/19/63
2-22344, Registration Statement, 4/24/64
2-24655, Registration Statement, 3/16/66
Form 10-K, 4/11/67
2-26356, Post-Effective Amendment
No. 1 to Registration Statement, 5/3/67
2-28080, Registration Statement, 1/25/68
2-31896, Registration Statement, 2/28/69
2-36094, Registration Statement, 1/27/70
2-38038, Registration Statement, 7/27/70
2-45591, Registration Statement, 9/1/72
Amendment No. 1 to Form 8-A, 6/18/81
Form 8-A, 11/1/85
33-18229, Registration Statement,
10/30/87
33-29382, Registration Statement,
6/16/89
Form 10-K, 3/27/92
Form 10-K, 3/26/93
621
4-B
2-B
4-B
2-B
A-1
2-B
4-B
2-B
2-B
1
2-B
2-B
2-B
2-B
2-B
2-C
2
2B
4-B
4-C
4
4
Table of Contents
Exhibit No.
4-43
4-44
4-44-1
Dated as
of
September 1, 1992
November 1, 1992
July 1, 1993
February 10, 1994
February 11, 1994
October 2, 1997
November 17, 2003
March 16, 2004
May 24, 2005
April 1, 2006
November 13, 2007
March 24, 2008
December 3, 2008
March 28, 2012
March 11, 2013
November 14, 2013
March 11, 2014
March 9, 2015
Description
File
Reference
Form 10-K, 3/26/93
Form 10-K, 3/26/93
33-49973, Registration Statement,
8/11/93
Form 10-K, 3/25/94
Form 10-K, 3/25/94
001-01072, Form 10-K, 3/26/98
001-01072, Form 10-K, 3/11/04
001-01072, Form 8-K, 3/23/04
001-01072, Form 8-K, 5/26/05
001-01072, Form 8-K, 4/17/06
001-01072, Form 8-K, 11/15/07
001-01072, Form 8-K, 3/28/08
001-01072, Form 8-K, 12/8/08
001-01072, Form 8-K, 3/29/12
001-01072, Form 8-K, 3/12/13
001-01072, Form 8-K, 11/15/13
001-01072, Form 8-K, 3/12/14
001-01072, Form 8-K, 3/10/15
Exhibit
No.
4
4
4.4
4
4
4
4.1
4.3
4.2
4.1
4.2
4.1
4.2
4.2
4.2
4.2
4.2
4.3
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)
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 8-K dated March 2, 2009, Exhibit 4.3)
622
Table of Contents
Exhibit No.
4-45
Description
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)
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
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
File
Reference
Exhibit
No.
33-39756, Registration Statement,
4/03/91
33-24955, Registration Statement,
10/13/88
33-24955, Registration Statement,
10/13/88
33-24955, Registration Statement,
10/13/88
33-24955, Registration Statement,
10/13/88
33-24955, Registration Statement,
10/13/88
33-39756, Registration Statement,
4/03/91
33-39756, Registration Statement,
4/03/91
33-39756, Registration Statement,
4/03/91
4-B
4-B
4-B
4-B
4-B
4-B
4-D
4-E
4-F
33-46892, Registration Statement, 4/1/92 4-E
33-46892, Registration Statement, 4/1/92 4-F
33-49750, Registration Statement,
7/17/92
33-57652, Registration Statement,
1/29/93
33-63582, Registration Statement,
5/28/93
33-50453, Registration Statement,
10/1/93
33-53855, Registration Statement,
1/30/95
33-53855, Registration Statement,
1/30/95
33-53855, Registration Statement,
1/30/95
33-53855, Registration Statement,
1/30/95
623
4
4-G
4-H
99
4-J
4-K
4-L
4-M
Table of Contents
Dated as
of
October 1, 1994
January 1, 1995
June 1, 1995
January 1, 1996
January 1, 1997
January 1, 1998
January 1, 1999
January 1, 2000
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
September 22, 2009
January 1, 2010
January 1, 2011
File
Reference
33-53855, Registration Statement,
1/30/95
333-00505, Registration Statement,
1/29/96
333-00505, Registration Statement,
1/29/96
333-24059, Registration
Statement, 3/27/97
001-01405, Form 10-K, 2/24/12
001-01405, Form 10-K, 2/24/12
001-01405, Form 10-K, 2/24/12
333-145691-02, Post Effective
Amendment No. 1 to Registration
Statement, 11/18/08
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
001-01405, Form 8-K, 10/1/09
001-01405, Form 10-K, 2/25/11
001-01405, Form 10-Q, 8/3/11
624
Exhibit
No.
4-N
4-K
4-L
4-L
4.4
4.4
4.4
4.24(k)
4.4
4.4
4.4
4.4
4.4
4.4
4.4
4.4
4.4
4.4
4.4
4.2
Table of Contents
Exhibit No.
4-46
Dated as
of
May 2, 2011
January 1, 2012
June 19, 2012
January 1, 2013
November 7, 2013
January 1, 2014
June 2, 2014
January 1, 2015
May 4, 2015
January 1, 2016
December 5, 2016
Description
File
Reference
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
001-01405, Form 8-K, 11/8/13
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
Filed herewith.
Exhibit
No.
4.2
4.3
4.2
4.1
4.2
4.4
4.3
4.4
4.2
001-01405, Form 8-K, 12/12/16
4.2
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)
4-47
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))
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
File Reference
Exhibit No.
2-66280, Registration Statement,
12/21/79
2-66280, Registration Statement,
12/21/79
2-66280, Registration Statement,
12/21/79
2-66280, Registration Statement,
12/21/79
2-66280, Registration Statement,
12/21/79
2-66280, Registration Statement,
12/21/79
625
2(b)
2(b)
2(b)
2(b)
2(b)
2(b)
Table of Contents
Dated as of
March 1, 1955
January 1, 1957
April 1, 1958
April 1, 1959
March 1, 1961
July 1, 1962
March 1, 1963
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
File Reference
2-66280, Registration Statement,
12/21/79
2-66280, Registration Statement,
12/21/79
2-66280, Registration Statement,
12/21/79
2-66280, Registration Statement,
12/21/79
2-66280, Registration Statement,
12/21/79
2-66280, Registration Statement,
12/21/79
2-66280, Registration Statement,
12/21/79
2-66280, Registration Statement,
12/21/79
2-66280, Registration Statement,
12/21/79
2-66280, Registration Statement,
12/21/79
2-66280, Registration Statement,
12/21/79
2-66280, Registration Statement,
12/21/79
2-66280, Registration Statement,
12/21/79
2-66280, Registration Statement,
12/21/79
2-66280, Registration Statement,
12/21/79
2-66280, Registration Statement,
12/21/79
Form 10-K, 3/25/81
Form 10-Q, 8/10/81
Form 10-K, 3/30/84
Form 10-Q, 5/14/84
Form 10-Q, 8/13/84
Form 10-Q, 11/12/85
Form 10-Q, 5/12/86
Form 10-K, 3/28/88
Form 10-Q for quarter ended 9/30/89
626
Exhibit No.
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)
2(b)
2(b)
2(b)
4(e)
4(a)
4(d)
4(a)
4(a)
4
4
4(d)
4(a)
Table of Contents
Dated as of
March 1, 1991
May 1, 1992
January 1, 1993
August 1, 1993
September 1, 1993
November 1, 1993
June 1, 1994
October 1, 1994
November 1, 1994
March 1, 1997
April 1, 2004
August 10, 2004
March 8, 2006
November 6, 2008
March 29, 2011
August 18, 2014
December 1, 2015
File Reference
Form 10-K, 3/28/91
Exhibit No.
4(d)(1)
33-49279, Registration Statement, 1/6/93
4(b)
333-108861, Registration Statement,
9/17/03
Form 10-Q, 11/12/93
Form 10-Q, 11/12/93
Form 10-K, 3/29/94
Form 10-Q, 8/14/94
Form 10-Q, 11/14/94
Form 10-K, 3/21/95
001-03559, Form 8-K, 3/24/97
001-03559, Form 8-K, 4/6/04
001-03559, Form 10-Q, 11/8/04
001-03559, Form 8-K,
3/17/06
001-03559, Form 8-K, 11/10/08
001-03559, Form 8-K, 4/1/11
001-03559, Form 8-K, 8/19/14
001-03559, Form 8-K, 12/2/15
4.05(hh)
4(a)
4(b)
4(c)(1)
4(a)
4(a)
4(c)(1)
4(b)
4.3
4
4
4.2
4.2
4.2
4.2
Exhibit No.
4-48
4-49
4-50
4-51
4-52
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)
627
Table of Contents
Exhibit No.
4-53
4-54
4-55
4-56
4-57
10-1
10-1-1
10-2
10-3
10-4
10-5
10-6
10-7
10-8
10-9
10-10
10-11
10-12
10-13
Description
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 4.1)
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)
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).
Commonwealth Edison Company Retirement Plan for Directors, as amended *(Registration Statement No. 333-49780, Form
S-8, Exhibit 4-13).
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).
628
Table of Contents
Exhibit No.
10-14
10-15
10-16
10-17
10-18
10-19
10-20
10-21
Description
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
10-28
10-29
10-30
10-31
Form of Separation Agreement under Exelon Corporation Senior Management Severance Plan (As Amended and Restated
Effective November 1, 2015) * Filed herewith.
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).
Exelon Corporation Deferred Compensation Plan (As Amended and Restated Effective January 1, 2005) (File No. 1-16169,
2006 Form 10-K, Exhibit 10-56).
Exelon Corporation Stock Deferral Plan (As Amended and Restated Effective 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).
629
Table of Contents
Exhibit No.
10-32
Description
Restricted stock unit award agreement (File 1-16169, Form 8-K dated August 31, 2007, Exhibit 99.1).
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
10-42
10-43
10-44
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, 2011 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. 10-2).
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. 10-3).
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. 10-4).
Credit Agreement dated as of March 28, 2012 among Commonwealth Edison Company, Various Financial Institutions, as
Lenders, and JP Morgan Chase Bank, N.A., as Administrative Agent (File No. 001-01839, Form 8-K dated March 28, 2012,
Exhibit No. 99-1).
Amendment No. 3 to Credit Agreement dated as of March 23, 2011 among Exelon Corporation, as Borrower, the various
financial institutions named therein, as Lenders, and JPMorgan Chase Bank, N.A., as Administrative Agent (File
No. 001-16169, Form 8-K dated August 10, 2013, Exhibit No. 99-1).
Amendment No. 1 to Credit Agreement dated as of March 28, 2012 among Commonwealth Edison Company, as Borrower,
the various financial institutions named therein, as Lenders and JPMorgan Chase Bank, N.A., as Administrative Agent (File
No. 001-1839, Form 8-K dated August 10, 2013, Exhibit No. 99-2).
Amendment No. 1 to Credit Agreement, dated as of December 21, 2011, to the Credit Agreement dated as of March 23,
2011, among Exelon Generation Company, LLC, the lenders party thereto and JPMorgan Chase Bank, N.A., as
Administrative Agent (File No. 001-16169, Form 8-K dated March 14, 2012, Exhibit No. 4-6).
Constellation Energy Group, Inc. Nonqualified Deferred Compensation Plan, as amended and restated. * (Designated as
Exhibit No. 10(b) to the Constellation Annual Report on Form 10-K for the year ended December 31, 2008, filed by
Constellation Energy Group, Inc., File Nos. 1-12869 and 1-1910).
Constellation Energy Group, Inc. Deferred Compensation Plan for Non-Employee Directors, as amended and restated. *
(Designated as Exhibit No. 10(c) to the Constellation Annual Report on Form 10-K for the year ended December 31, 2008,
filed by Constellation Energy Group, Inc., File Nos. 1-12869 and 1-1910).
630
Table of Contents
Exhibit No.
10-45
10-46
10-47
10-48
10-49
10-50
10-51
10-52
10-53
10-54
10-55
10-56
Description
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).
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).
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).
631
Table of Contents
Exhibit No.
10-57
10-58
10-59
10-60
10-61
10-62
10-63
Description
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).
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
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).
632
Table of Contents
Exhibit No.
10-71-3
10-71-4
10-71-5
10-72-1
10-72-2
10-72-3
10-72-4
10-73
10-74
10-75
10-76
10-77
10-78
10-79
Description
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 10.6).
Confirmation of Base Issuer Forward Transaction, dated June 11, 2014, between Exelon Corporation and Barclays Capital, Inc.,
acting as Agent for Barclays Bank PLC (File No. 001-16169, Form 8-K dated June 17, 2014, Exhibit 10.1).
Confirmation of Base Issuer Forward Transaction, dated June 11, 2014, between Exelon Corporation and Goldman Sachs & Co.
(File No. 001-16169, Form 8-K dated June 17, 2014, Exhibit 10.2).
Confirmation of Additional Issuer Forward Transaction, dated June 13, 2014, between Exelon Corporation and Barclays Capital,
Inc., acting as Agent for Barclays Bank PLC (File No. 001-16169, Form 8-K dated June 17, 2014, Exhibit 10.3).
Confirmation of Additional Issuer Forward Transaction, dated June 13, 2014, between Exelon Corporation and Goldman Sachs &
Co. (File No. 001-16169, Form 8-K dated June 17, 2014, Exhibit 10.4).
Bondable Transition Property Sale Agreement, dated as of December 19, 2002, between ACE Funding and ACE (File
No. 333-59558, Form 8-K dated December 23, 2002, Exhibit 10.1)
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. 001-035559, 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)
633
Table of Contents
Exhibit No.
10-80
10-81
10-82
10-82-1
10-82-2
10-82-3
10-82-4
10-83
10-83-1
Description
First Amendment to Term Loan Agreement, dated as of October 29, 2015, by and among PHI, The Bank of Nova Scotia, as
Administrative Agent, and the lenders party thereto (File No. 001-31403, Form 8-K dated October 29, 2015, Exhibit 10.2)
$500,000,000 Term Loan Agreement by and among PHI, The Bank of Nova Scotia, as Administrative Agent, and the lenders
party thereto, dated January 13, 2016 (File No. 001-31403, Form 8-K dated January 14, 2016, Exhibit 10)
Second Amended and Restated Credit Agreement, dated as of August 1, 2011, by and among Pepco Holdings, Inc., Potomac
Electric Power Company, Delmarva Power & Light Company and Atlantic City Electric Company, the lenders party thereto, Wells
Fargo Bank, National Association, as agent, issuer and swingline lender, Bank of America, N.A., as syndication agent and issuer,
The Royal Bank of Scotland plc and Citicorp USA, Inc., as co-documentation agents, Wells Fargo Securities, LLC and Merrill
Lynch, Pierce, Fenner and Smith Incorporated, as active joint lead arrangers and joint book runners, and Citigroup Global
Markets Inc. and RBS Securities, Inc. as passive joint lead arrangers and joint book runners (File No. 001-31403, Form 10-Q
dated August 3, 2011, Exhibit 10.1)
First Amendment, dated as of August 2, 2012, to Second Amended and Restated Credit Agreement, dated as of August 1, 2011,
by and among Pepco Holdings, Inc., Potomac Electric Power Company, Delmarva Power & Light Company and Atlantic City
Electric Company, the various financial institutions party thereto, Wells Fargo Bank, National Association, as agent, issuer of
letters of credit and swingline lender, Bank of America, N.A., as syndication agent and issuer of letters of credit, and The Royal
Bank of Scotland plc and Citibank, N.A., as co-documentation agents (File No. 001-31403, Form 10-K dated March 1, 2013,
Exhibit 10.25.1)
Amendment and Consent to Second Amended and Restated Credit Agreement, dated as of May 20, 2014, by and among Pepco
Holdings, Inc., Potomac Electric Power Company, Delmarva Power & Light Company and Atlantic City Electric Company, the
various financial institutions from time to time party thereto, Bank of America, N.A. and Wells Fargo Bank, National Association
(File No. 001-31403, Form 8-K dated May 20, 2014, Exhibit 10.1)
Third Amendment to Second Amended and Restated Credit Agreement, dated as of May 1, 2015, by and among Pepco
Holdings, Inc., Potomac Electric Power Company, Delmarva Power & Light Company and Atlantic City Electric Company, the
various financial institutions from time to time party thereto, Bank of America, N.A. and Wells Fargo Bank, National Association
(File No. 001-31403, Form 8-K dated May 1, 2015, Exhibit 10.1)
Consent, dated as of October 29, 2015, by and among Pepco Holdings, Inc., Potomac Electric Power Company, Delmarva
Power & Light Company and Atlantic City Electric Company, the various financial institutions from time to time party thereto,
Bank of America, N.A. and Wells Fargo Bank, National Association (File No. 001-31403, Form 8-K dated October 29, 2015,
Exhibit 10.1)
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 9, 2000, Exhibit 10.1)
634
Table of Contents
Exhibit No.
10-83-2
10-84
10-85
10-86
10-87
10-88
10-89
10-90
10-91
10-92
10-93
12-1
12-2
12-3
Description
Amendment No. 1 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 9, 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 2)
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. 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. 6 to Credit Agreement, dated as of March 23, 2011, among PECO Energy Company, as Borrower, the various
financial institutions named therein, as Lenders, and JPMorgan Chase Bank, N.A., as Administrative Agent (File No. 000-16844,
Form 8-K dated May 27, 2016, Exhibit 99.4)
Amendment No. 5 to Credit Agreement, dated as of March 23, 2011, among Baltimore Gas and Electric Company, as Borrower,
the various financial institutions named therein, as Lenders, and JPMorgan Chase Bank, N.A., as Administrative Agent (File
No. 001-01910, Form 8-K dated May 27, 2016, Exhibit 99.5)
Fourth Amendment to Second Amended and Restated Credit Agreement, dated as of August 1, 2011, among Pepco Holdings
LLC, Potomac Electric Power Company, Delmarva Power & Light Company and Atlantic City Electric Company, as Borrowers,
the various financial institutions named therein, as Lenders, and Wells Fargo Bank, National Association, as Administrative Agent
(File No. 001-31403, Form 8-K dated May 27, 2016, Exhibit 99.6)
2016 Form of Exelon Corporation Change in Control Agreement (File No. 001-16169, Form 10-Q dated October 26, 2016, Exhibit
10.1)
Execution Version-ZEC Standard Contract by and between the NYSERDA and Nine Mile Point Nuclear Station, LLC dated Nov.
18, 2016 (File No. 001-16169, Form 8-K dated November 18, 2016, Exhibit 10.1)
Execution Version-ZEC Standard Contract by and between the NYSERDA and R. E. Ginna Nuclear Power Plant, LLC dated
Nov. 18, 2016 (File No. 001-16169, Form 8-K dated November 18, 2016, Exhibit 10.2)
Exelon Corporation Computation of Ratio of Earnings to Fixed Charges and Ratio of Earnings to Fixed Charges and Preferred
Stock Dividends.
Exelon Generation Company, LLC Computation of Ratio of Earnings to Fixed Charges.
Commonwealth Edison Company Computation of Ratio of Earnings to Fixed Charges.
635
Table of Contents
Exhibit No.
12-4
12-5
12-6
12-7
12-8
12-9
14
21-1
21-2
21-3
21-4
21-5
21-6
21-7
21-8
21-9
23-1
23-2
23-3
23-4
23-5
23-6
23-7
24-1
24-2
24-3
24-4
24-5
24-6
24-7
24-8
24-9
24-10
24-11
Description
PECO Energy Company Computation of Ratio of Earnings to Fixed Charges and Ratio of Earnings to Fixed Charges and
Preferred Stock Dividends.
Baltimore Gas and Electric Company Computation of Ratio of Earnings to Fixed Charges and Ratio of Earnings to Fixed
Charges and Preference Stock Dividends.
Pepco Holdings LLC Computation of Ratio of Earnings to Fixed Charges.
Potomac Electric Power Company Computation of Ratio of Earnings.
Delmarva Power & Light Company Computation of Ratio of Earnings to Fixed Charges.
Atlantic City Electric Company Computation of Ratio of Earnings to Fixed Charges.
Exelon Code of Conduct, as amended March 12, 2012 (File No. 1-16169, Form 8-K dated March 14, 2012, Exhibit No. 14-1).
Subsidiaries
Exelon Corporation
Exelon Generation Company, LLC
Commonwealth Edison Company
PECO Energy Company
Baltimore Gas and Electric Company
Pepco Holdings LLC
Potomac Electric Power Company
Delmarva Power & Light Company
Atlantic City Electric Company
Consent of Independent Registered Public Accountants
Exelon Corporation
Exelon Generation Company, LLC
Commonwealth Edison Company
PECO Energy Company
Baltimore Gas and Electric Company
Potomac Electric Power Company
Delmarva Power & Light Company
Power of Attorney (Exelon Corporation)
Anthony K. Anderson
Ann C. Berzin
Christopher M. Crane
Yves C. de Balmann
Nicholas DeBenedictis
Nancy L. Gioia
Linda P. Jojo
Paul Joskow
Robert J. Lawless
Richard W. Mies
Reserved.
636
Table of Contents
Exhibit No.
24-12
24-13
24-14
24-15
24-16
24-17
24-18
24-19
24-20
24-21
24-22
24-23
24-24
24-25
24-26
24-27
24-28
24-29
24-30
24-31
24-32
24-33
24-34
24-35
24-36
24-37
24-38
24-39
24-40
24-41
24-42
24-43
24-44
24-45
24-46
Description
John W. Rogers, Jr.
Mayo A. Shattuck III
Stephen D. Steinour
Power of Attorney (Commonwealth Edison Company)
James W. Compton
Christopher M. Crane
A. Steven Crown
Nicholas DeBenedictis
Peter V. Fazio, Jr.
Michael H. Moskow
Denis P. O’Brien
Anne R. Pramaggiore
Jesse H. Ruiz
Reserved.
Power of Attorney (PECO Energy Company)
Craig L. Adams
Christopher M. Crane
M. Walter D’Alessio
Nicholas DeBenedictis
Nelson A. Diaz
Rosemarie B. Greco
Charisse R. Lillie
Denis P. O’Brien
Ronald Rubin
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.
Denis P. O’Brien
Michael D. Sullivan
Maria Harris Tildon
Power of Attorney (Pepco Holdings LLC)
Christopher M. Crane
Linda Cropp
Michael E. Cryor
Ernest Dianastasis
637
Table of Contents
Exhibit No.
24-47
24-48
24-49
24-50
24-51
24-52
24-53
24-54
24-55
24-56
24-57
24-58
31-1
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
32-1
32-2
Description
Debra DiLorenzo
Denis P. O’Brien
David M. Velazquez
Power of Attorney (Potomac Electric Power Company)
J. Tyler Anthony
Christopher M. Crane
Donna J. Kinzel
Kevin M. McGowan
Denis P. O’Brien
Kenneth J. Parker
David M. Velazquez
Power of Attorney (Delmarva Power & Light Company)
Denis P. O’Brien
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, 2016 filed by the following officers for the following registrants:
Filed by Christopher M. Crane for Exelon Corporation
Filed by Jonathan W. Thayer 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 Anne R. Pramaggiore for Commonwealth Edison Company
Filed by Joseph R. Trpik, Jr. for Commonwealth Edison Company
Filed by Craig L. Adams for PECO Energy Company
Filed by Phillip S. Barnett 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 Donna J. Kinzel for Pepco Holdings LLC
Filed by David M. Velazquez for Potomac Electric Power Company
Filed by Donna J. Kinzel for Potomac Electric Power Company
Filed by David M. Velazquez for Delmarva Power & Light Company
Filed by Donna J. Kinzel for Delmarva Power & Light Company
Filed by David M. Velazquez for Atlantic City Electric Company
Filed by Donna J. Kinzel 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, 2016 filed by the following officers for the following registrants:
Filed by Christopher M. Crane for Exelon Corporation
Filed by Jonathan W. Thayer for Exelon Corporation
638
Table of Contents
Exhibit No.
32-3
Description
Filed by Kenneth W. Cornew for Exelon Generation Company, LLC
32-4
32-5
32-6
32-7
32-8
32-9
32-10
32-11
32-12
32-13
32-14
32-15
32-16
32-17
32-18
Filed by Bryan P. Wright for Exelon Generation Company, LLC
Filed by Anne R. Pramaggiore for Commonwealth Edison Company
Filed by Joseph R. Trpik, Jr. for Commonwealth Edison Company
Filed by Craig L. Adams for PECO Energy Company
Filed by Phillip S. Barnett 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 Donna J. Kinzel for Pepco Holdings LLC
Filed by David M. Velazquez for Potomac Electric Power Company
Filed by Donna J. Kinzel for Potomac Electric Power Company
Filed by David M. Velazquez for Delmarva Power & Light Company
Filed by Donna J. Kinzel for Delmarva Power & Light Company
Filed by David M. Velazquez for Atlantic City Electric Company
Filed by Donna J. Kinzel for Atlantic City Electric Company
101.INS
XBRL Instance
101.SCH
XBRL Taxonomy Extension Schema
101.CAL
101.DEF
101.LAB
101.PRE
XBRL Taxonomy Extension Calculation
XBRL Taxonomy Extension Definition
XBRL Taxonomy Extension Labels
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.
639
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.
640
Table of Contents
S IGNATURES
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 13th day of February, 2017.
EXELON CORPORATION
By:
Name:
Title:
/ S / C HRISTOPHER M. C RANE
Christopher M. Crane
President and Chief Executive Officer
Pursuant to the requirements of the Securities Exchange Act of 1934, this report has been signed by the following persons on behalf of the
registrant and in the capacities indicated on the 13th day of February, 2017.
Signature
Title
/ S / C HRISTOPHER M. C RANE
Christopher M. Crane
President and Chief Executive Officer (Principal Executive Officer)
and Director
/ S / J ONATHAN W. T HAYER
Jonathan W. Thayer
/ S / D UANE M. D ES P ARTE
Duane M. DesParte
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’Neil, Attorney-in-Fact, on behalf of the following Directors on the date
indicated:
Anthony K. Anderson
Ann C. Berzin
Christopher M. Crane
Yves C. de Balmann
Nicholas DeBenedictis
Nancy L. Gioia
Linda P. Jojo
Paul Joskow
Robert J. Lawless
Richard W. Mies
John W. Rogers, Jr.
Mayo A. Shattuck III
Stephen D. Steinour
By:
Name:
/ S / T HOMAS S. O’N EILL
Thomas S. O’Neill
February 13, 2017
641
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 13th day of February, 2017.
EXELON GENERATION COMPANY, LLC
By:
Name:
Title:
/ S / K ENNETH W. C ORNEW
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 13th day of February, 2017.
Signature
Title
/ S / K ENNETH W. C ORNEW
Kenneth W. Cornew
/ S / B RYAN P. W RIGHT
Bryan P. Wright
/ S / M ATTHEW N. B AUER
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)
642
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 13th day of February, 2017.
COMMONWEALTH EDISON COMPANY
By:
Name:
Title:
/ S / A NNE R. P RAMAGGIORE
Anne R. Pramaggiore
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 13th day of February, 2017.
Signature
Title
/ S / A NNE R. P RAMAGGIORE
Anne R. Pramaggiore
/ S / J OSEPH R. T RPIK , J R .
Joseph R. Trpik, Jr.
/ S / G ERALD J. K OZEL
Gerald J. Kozel
/ S / C HRISTOPHER M. C RANE
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 Anne R. Pramaggiore, 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
Denis P. O’Brien
Jesse H. Ruiz
By:
Name:
/ S / A NNE R. P RAMAGGIORE
Anne R. Pramaggiore
February 13, 2017
643
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 13th day of February, 2017.
PECO ENERGY COMPANY
By:
Name:
Title:
/ S / C RAIG L. A DAMS
Craig L. Adams
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 13th day of February, 2017.
Signature
Title
/ S / C RAIG L. A DAMS
Craig L. Adams
/ S / P HILLIP S. B ARNETT
Phillip S. Barnett
/ S / S COTT A. B AILEY
Scott A. Bailey
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)
/ S / C HRISTOPHER M. C RANE
Christopher M. Crane
Chairman and Director
This annual report has also been signed below by Craig L. Adams, 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 / C RAIG L. A DAMS
Craig L. Adams
Rosemarie B. Greco
Charisse R. Lillie
Denis P. O’Brien
Ronald Rubin
644
February 13, 2017
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 13th day of February, 2017.
BALTIMORE GAS AND ELECTRIC COMPANY
By:
Name:
Title:
/ S / C ALVIN G. B UTLER , J R .
Calvin G. Butler, Jr.
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 13th day of February, 2017.
Signature
Title
/ S / C ALVIN G. B UTLER , J R .
Calvin G. Butler, Jr.
/ S / D AVID M. V AHOS
David M. Vahos
/ S / A NDREW W. H OLMES
Andrew W. Holmes
Chief Executive Officer (Principal Executive Officer)
Senior Vice President, Chief Financial Officer and Treasurer
(Principal Financial Officer)
Vice President and Controller (Principal Accounting Officer)
/ S / C HRISTOPHER M. C RANE
Christopher M. Crane
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 / C ALVIN G. B UTLER , J R .
Calvin G. Butler, Jr.
Joseph Haskins, Jr.
Denis P. O’Brien
Michael D. Sullivan
Maria Harris Tildon
645
February 13, 2017
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 13th day of February, 2017.
PEPCO HOLDINGS LLC
By:
Name:
Title:
/ S / D AVID M. V ELAZQUEZ
David M. Velazquez
President and Chief Executive Officer
Pursuant to the requirements of the Securities Exchange Act of 1934, this report has been signed by the following persons on behalf of the
registrant and in the capacities indicated on the 13th day of February, 2017.
Signature
Title
/ S / D AVID M. V ELAZQUEZ
David M. Velazquez
/ S / D ONNA J. K INZEL
Donna J. Kinzel
/ S / R OBERT M. A IKEN
Robert M. Aiken
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)
/ S / C HRISTOPHER M. C RANE
Christopher M. Crane
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 Cropp
Michael E. Cryor
By:
Name:
/ S / D AVID M. V ELAZQUEZ
David M. Velazquez
Ernest Dianastasis
Debra P. DiLorenzo
Denis P. O’Brien
646
February 13, 2017
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 13th day of February, 2017.
POTOMAC ELECTRIC POWER COMPANY
By:
Name:
Title:
/ S / D AVID M. V ELAZQUEZ
David M. Velazquez
President and Chief Executive Officer
Pursuant to the requirements of the Securities Exchange Act of 1934, this report has been signed by the following persons on behalf of the
registrant and in the capacities indicated on the 13th day of February, 2017.
Signature
Title
/ S / D AVID M. V ELAZQUEZ
David M. Velazquez
/ S / D ONNA J. K INZEL
Donna J. Kinzel
/ S / R OBERT M. A IKEN
Robert M. Aiken
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)
/ S / C HRISTOPHER M. C RANE
Christopher M. Crane
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
Christopher M. Crane
Donna J. Kinzel
By:
Name:
/ S / D AVID M. V ELAZQUEZ
David M. Velazquez
Kevin M. McGowan
Denis P. O’Brien
Kenneth J. Parker
647
February 13, 2017
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 13th day of February, 2017.
DELMARVA POWER & LIGHT COMPANY
By:
Name:
Title:
/ S / D AVID M. V ELAZQUEZ
David M. Velazquez
President and Chief Executive Officer
Pursuant to the requirements of the Securities Exchange Act of 1934, this report has been signed by the following persons on behalf of the
registrant and in the capacities indicated on the 13th day of February, 2017.
Signature
Title
/ S / D AVID M. V ELAZQUEZ
David M. Velazquez
/ S / D ONNA J. K INZEL
Donna J. Kinzel
/ S / R OBERT M. A IKEN
Robert M. Aiken
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)
/ S / C HRISTOPHER M. C RANE
Christopher M. Crane
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:
Denis P. O’Brien
By:
Name:
/ S / D AVID M. V ELAZQUEZ
David M. Velazquez
648
February 13, 2017
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 13th day of February, 2017.
ATLANTIC CITY ELECTRIC COMPANY
By:
Name:
Title:
/ S / D AVID M. V ELAZQUEZ
David M. Velazquez
President and Chief Executive Officer
Pursuant to the requirements of the Securities Exchange Act of 1934, this report has been signed by the following persons on behalf of the
registrant and in the capacities indicated on the 13th day of February, 2017.
Signature
Title
/ S / D AVID M. V ELAZQUEZ
David M. Velazquez
/ S / D ONNA J. K INZEL
Donna J. Kinzel
/ S / R OBERT M. A IKEN
Robert M. Aiken
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)
/ S / C HRISTOPHER M. C RANE
Christopher M. Crane
Chairman
649
Exhibit 4.45.1
This Instrument Prepared By:
/s/ Christie D. Cannon
Christie D. Cannon
Delmarva Power & Light Company
Mailstop 92DC42
500 N. Wakefield Drive
Newark, DE 19702-5440
DELMARVA POWER & LIGHT COMPANY
TO
THE BANK OF NEW YORK MELLON,
Trustee.
ONE HUNDRED AND SEVENTEENTH SUPPLEMENTAL
INDENTURE
Dated as of January 1, 2016
(but executed on the dates shown on the execution page)
1
This ONE HUNDRED AND SEVENTEENTH SUPPLEMENTAL INDENTURE , dated as of the first day of January, 2016 (but executed on the dates
hereinafter shown), made and entered into by and between DELMARVA POWER & LIGHT COMPANY, a corporation of the State of Delaware and the
Commonwealth of Virginia, hereinafter called the Company and THE BANK OF NEW YORK MELLON, a New York banking corporation, hereinafter called the
Trustee;
WITNESSETH:
WHEREAS, the Company heretofore executed and delivered its Indenture of Mortgage and Deed of Trust (hereinafter in this One Hundred and Seventeenth
Supplemental Indenture called the “Original Indenture”), dated as of October 1, 1943, to The New York Trust Company, a corporation of the State of New York, as
Trustee, to which The Bank of New York Mellon is successor Trustee, to secure the First Mortgage Bonds of the Company, unlimited in aggregate principal
amount and issuable in series, from time to time, in the manner and subject to the conditions set forth in the Original Indenture granted and conveyed unto the
Trustee, upon the trusts, uses and purposes specifically therein set forth, certain real estate, franchises and other property therein described, including property
acquired after the date thereof, except as therein otherwise provided; and
WHEREAS, the Original Indenture has been supplemented by one hundred and sixteen supplemental indentures specifically subjecting to the lien of the
Original Indenture as though included in the granting clause thereof certain property in said supplemental indentures specifically described and amending and
modifying the provisions of the Original Indenture (the Original Indenture, as amended, modified and supplemented by all of the indentures supplemental thereto,
including this One Hundred and Seventeenth Supplemental Indenture, is hereinafter in this One Hundred and Seventeenth Supplemental Indenture called the
“Indenture”); and
WHEREAS, the execution and delivery of this One Hundred and Seventeenth Supplemental Indenture has been duly authorized by Unanimous Written
Consent of the Board of Directors of the Company, and all conditions and requirements necessary to make this One Hundred and Seventeenth Supplemental
Indenture a valid, binding and legal instrument in accordance with its terms, for the purposes herein expressed, and the execution and delivery hereof, have been in
all respects duly authorized; and
WHEREAS, it is provided in and by the Original Indenture, inter alia, as follows:
“IT IS HEREBY AGREED by the Company that all the property, rights and franchises acquired by the Company after the date hereof (except any
hereinbefore or hereinafter expressly excepted) shall (subject to the provisions of Section 9.01 hereof and to the extent permitted by law) be as fully
embraced within the lien hereof as if such property, rights and franchises were now owned by the Company and/or specifically described herein and
conveyed hereby;”
and
WHEREAS, the Company has acquired certain other property, real, personal and mixed, which heretofore has not been specifically conveyed to the Trustee;
NOW, THEREFORE, this ONE HUNDRED AND SEVENTEENTH SUPPLEMENTAL INDENTURE WITNESSETH that for and in consideration of the
premises and in pursuance of the provisions of the Indenture, the Company has granted, bargained, sold, released, conveyed, assigned, transferred, mortgaged,
pledged, set over and confirmed, and by these presents does grant, bargain, sell, release, convey, assign, transfer, mortgage, pledge, set over and confirm unto the
Trustee and to its successors in the trust in the Indenture created, to its and their assigns forever, all the following described properties of the Company, and does
confirm that the Company will not cause or consent to a partition, either voluntary or through legal proceedings, of property, whether herein described or
2
heretofore or hereafter acquired, in which its ownership shall be as tenant in common, except as permitted by, and in conformity with, the provisions of the
Indenture and particularly of Article IX thereof:
DELAWARE
Sussex County
Property Name
Midway Substation
MARYLAND
Harford County
Property Name
Instrument
Date
Liber
11/17/2015 4472
Deed Records
Folio
4
Tax Map No.
334-06.00-497.00
Instrument
Date
Deed Records
Liber Folio
Tax Map No.
Prospect Road Land Purchase - DPL MD CAP H1 [Paul J.
Madden & Brittany Madden]
12/29/2015 11602 414
TM 18, Parcel 304
MARYLAND
Wicomico County
Property Name
Chesapeake Substation
Instrument
Date
Liber
12/29/2015 3945
Deed Records
Folio
465
Tax Map No.
Map 38 Parcel 103 & Map 38 Parcel 369 Lot 27
Together with all other property, real, personal and mixed, tangible and intangible (except such property as in said Indenture expressly excepted from the lien
and operation thereof), acquired by the Company on or prior to December 31, 2015, and not heretofore specifically subjected to the lien of the Indenture.
3
Also without limitation of the generality of the foregoing, the easements and rights-of-way and other rights in or relating to real estate or the occupancy of
the same owned by the Company, and whether used or not used in connection with the Company’s operations, which are conveyed to the Company and recorded in
the following Real Property Deed Records to which reference is made for a more particular description, to wit:
DELAWARE
New Castle County
Instrument Date
01/30/2015
02/17/2015
02/25/2015
03/24/2015
03/26/2015
05/05/2015
05/06/2015
05/12/2015
05/13/2015
07/14/2015
07/14/2015
08/03/2015
08/05/2015
08/05/2015
08/11/2015
09/14/2015
09/15/2015
09/16/2015
09/29/2015
10/01/2015
10/02/2015
10/09/2015
10/09/2015
10/09/2015
10/13/2015
10/15/2015
10/15/2015
10/19/2015
10/19/2015
10/30/2015
11/10/2015
11/23/2015
11/25/2015
12/15/2015
01/04/2016
Instrument No.
20150227-0009102
20150320-0012858
20150311-0011350
20150331-0014740
20150406-0015639
20150611-0028549
20150527-0024976
20150528-0025500
20150528-0025501
20150819-0042053
20150819-0042054
20150818-0041630
20150819-0042052
20150825-0043084
20150825-0043051
20151006-0051092
20151006-0051093
20160119-0002254
20160119-0002253
20151016-0053150
20151110-0058220
20151020-0053692
20151020-0053691
20151020-0053690
20160119-0002252
20151028-0055310
20160119-0002250
20151028-0055311
20151201-0061397
20151211-0063727
20151201-0061396
20160119-0002249
20151211-0063726
20160129-0004536
20160119-0002251
Tax ID No.
1401100072
2602930254, 2602930261
1502000074
1102300025
611500141
1501100121
1501000121
1104100014
804510252
1301100047M001
1301100009
1301300148
0901100065
1401500262
0611000003
0804000019
0702700119
0804220028
2602610035
0611200012
0604600159
0605200247
0613100019
0605200248
0902400030
0605700142
1003500022, 1003500025, 1003500026
0901700076
1300300001, 1300300002, 1300700020, 1300700021, 1300800001, 1300800002
1101300015
1301100165
0803910138
0615000306
0801310209, 0801310210, 0801310234, 0801310282
0702900036
4
Instrument Date
01/05/2016
01/07/2015
01/07/2015
07/17/2014
07/17/2014
07/17/2014
07/29/2014
08/27/2014
07/18/2014
07/18/2014
07/18/2014
11/19/2014
01/26/2015
02/05/2015
02/05/2015
02/05/2015
02/05/2015
02/05/2015
01/29/2015
10/30/2014
DELAWARE
Kent County
Instrument Date
11/23/2014
12/23/2014
01/14/2015
04/21/2015
05/18/2015
05/18/2015
05/27/2015
06/09/2015
07/21/2015
07/21/2015
09/23/2015
Instrument No.
20160119-0002248
20150116-0002216
20150016-0002217
20150116-0002439
20150116-0002440
20150116-0002441
20150116-0002442
20150116-0002443
20150116-0002438
20150116-0002437
20150116-0002436
20150116-0002444
20150127-0003924
20150219-0007706
20150219-0007707
20150219-0007708
20150219-0007709
20150219-0007710
20150219-0007967
20150211-0006654
Instrument Number
2015-269001
2015-270213
2015-269325
2015-275053
2015-276538
2015-276539
2015-276540
2015-277709
2015-279352
2015-279353
2015-284125
Tax ID No.
1103620042, 1103620073, 1103640073, 1103640188, 1103710037, 1103710040,
1103730220, 1103730226
0607100248, 0607100249, 0607100250, 0607100255, 0607100256, 0607100257
0607100260, 0607100264, 0605800457
0607100156, 0607100157, 0607100259, 0607100261
0801700003
0801700120
0801700034
0801710001
0802340091
0801100002
0801700031
0801700002
2603540058
1300900057
0604600047
0603500244
0604600248
0604600249
0604600250
1401100073
1101300015
Tax ID No.
6-00-15900-01-2809-00001
6-00-17900-02-0100-00001
6-00-14800-01-4100-00001
5-00-17200-02-2000-00001
3-00-04600-02-1504-00001
3-00-04600-02-1504-00001
4-03-0469.00-01-07.27000
7-00-10200-02-2300-00001
2-00-07500-01-1203-00001
2-00-07500-01-1205-00001
3-00-01600-01-1101-00001
5
DELAWARE
Sussex County
Instrument Date
Deed Records
Tax ID No.
06/11/2014
12/17/2014
01/14/2015
01/22/2015
02/03/2015
04/26/2015
05/11/2015
05/12/2015
05/18/2015
05/23/2015
06/11/2015
06/24/2015
07/20/2015
07/20/2015
09/10/2015
09/12/2015
09/29/2015
10/02/2015
10/30/2015
11/10/2015
12/17/2015
MARYLAND
Caroline County
Instrument Date
02/16/2015
07/08/2015
08/24/2015
10/10/2015
09/28/2015
Book
4345
4357
4362
4362
4371
4398
4406
4420
4420
4406
4420
4422
4440
4440
4460
4460
4458
4458
4469
4480
4496
Page
159
151
33
30
273
256
298
24
22
296
26
333
141
139
68
70
334
320
21
220
308
334-10.00-30.26
334-10.00-30.27
533-18.00-84.00
234-33.00-23.02
334-13.00-325.37
234-50.02-08
432-7.00-25.01
433-6.15-44.00-PARK
33450015204
533-11.00-18.02
134-23.12-62.00
334-60.06-609
334-10.00-73.00
334-10.00-74.00
530-9.00-47.00
234-5.00-46.03
331-2.00-15.00
132-13.00-7.00
234-32.00-110.00
334-5.00-88.00
5-32-13.00-32.01
334-13.00-325.18
134-20.08-5500
Deed Records
Page
Book
233
1151
180
1165
464
1172
461
1177
459
1177
6
Map
53
23
14
100
59
Parcel
84
105
47
1165
82
Lot
2
1-24
2
MARYLAND
Cecil County
Instrument Date
12/02/2014
12/02/2014
03/27/2015
04/02/2015
04/10/2015
04/10/2015
04/10/2015
04/15/2015
04/15/2015
04/27/2015
05/02/2015
05/14/2015
08/12/2015
08/24/2015
08/29/2015
11/06/2015
11/06/2015
11/20/2015
12/04/2015
12/10/2015
12/22/2014
01/10/2015
01/10/2015
MARYLAND
Dorchester County
Instrument Date
09/14/2014
02/19/2015
06/01/2015
01/15/2015
09/08/2014
01/16/2015
01/20/2015
01/27/2015
Deed Records
Page
303
309
191
232
234
236
240
238
242
189
307
13
301
348
249
390
393
7
404
402
475
477
479
Book
3770
3770
3727
3724
3724
3724
3724
3724
3724
3727
3770
3732
3770
3779
3783
3818
3818
3824
3832
3832
3674
3674
3674
Deed Records
Folio
364
497
188
189
193
326
32
298
Liber
1248
1256
1309
1247
1247
1247
1249
1251
7
Map
30
30
25
6
38
38
38
38
38
25
38
13
38
31
14
20
18
19
19
52
42
11
11
Map
31
6
32
33
31
33
400
6
Parcel
116
3 &97
719
28
13
12
192
20
208
325
9
497
379
47
462
123
432
505
159
18
73
9
9
Lot
1
Parcel
Lot
135
87
76
10
135
10
589
130
MARYLAND
Harford County
Instrument Date
05/09/2015
02/04/2015
Instrument Date
MARYLAND
Kent County
11/12/2014
11/30/2014
12/05/2014
12/05/2014
12/08/2014
12/12/2014
12/20/2014
12/23/2014
01/06/2015
01/29/2015
01/29/2015
01/29/2015
03/06/2015
04/06/2015
04/06/2015
04/06/2015
04/09/2015
05/01/2015
05/04/2015
05/08/2015
05/11/2015
05/14/2015
05/15/2015
05/19/2015
05/27/2015
05/28/2015
06/03/2015
06/03/2015
06/25/2015
07/13/2015
09/01/2015
09/02/2015
09/02/2015
Deed Records
Folio
482
39
Liber
11276
11129
Map
17
12
Parcel
268
34
Lot
Deed Records
Folio
285
349
353
130
351
136
132
134
128
70
72
74
455
343
340
346
478
200
493
496
481
436
433
490
484
487
426
429
423
27
339
314
316
Liber
815
826
826
818
826
818
818
818
818
820
820
820
822
826
826
826
834
829
834
834
834
829
829
834
834
834
835
835
835
837
818
841
841
8
Map
Parcel
Lot
42
53
53
53
53
53
53
36
42
48
53
48
44
53
53
53
53
44
53
53
53
201
4
53
53
53
53
53
48
47
53
55
55
21
52
8
54
3
9
45
169
154
20
14
78
308
20
14
78
3
231
29
53
6
399
173
24
9
18
48
31
54
83
2
55
55
1
3
4
Instrument Date
09/02/2015
09/02/2015
Deed Records
Liber
841
841
MARYLAND
Queen Anne’s County
Instrument Date
Deed Records
09/24/2014
12/17/2014
12/17/2014
12/19/2014
01/14/2015
01/22/2015
01/24/2015
02/02/2015
02/11/2015
03/25/2015
03/25/2015
03/25/2015
03/26/2015
04/30/2015
05/18/2015
06/10/2015
06/19/2015
06/19/2015
06/19/2015
06/22/2015
06/24/2015
06/30/2015
08/11/2015
08/19/2015
08/20/2015
08/31/2015
09/18/2015
09/21/2015
09/22/2015
09/25/2015
10/12/2015
11/02/2015
11/17/2015
12/01/2015
12/04/2015
Liber
2366
2361
2361
2366
2368
2375
2375
2379
2377
2437
2437
2437
2393
2437
2413
2437
2437
2437
2437
2437
2437
2437
2449
2458
2453
2477
2466
2466
2485
2466
2487
2485
2487
2492
2499
9
Folio
318
320
Folio
474
54
51
471
298
33
29
139
257
358
362
366
180
370
109
383
374
377
380
353
78
82
7
399
502
1
84
452
405
449
395
402
391
437
183
Map
55
55
Map
58D
58D
58E
58D
64
10
10
64
45
63
63
63
48
63
65
63
58H
65
65
44
68
29
51
73
58D
64
36
35
56
17
44B
058E
581
58E
7
Parcel
55
73
Lot
5
Parcel
Lot
420
419
427
425
60 & 31
88
13
32
46
28
27
27
42
85
30
41
201
45
46
33
1
4
29
12
73
1
62
178
50
58
963
57
369
57
3
3
4
1
1-5
3
2
MARYLAND
Somerset County
Instrument Date
Deed Records
Liber
893
893
903
890
892
895
901
901
907
907
912
Folio
157
155
403
551
575
32
69
67
311
316
161
12/04/2014
12/05/2014
12/12/2014
01/07/2015
01/30/2015
03/04/2015
05/27/2015
05/27/2015
07/22/2015
07/22/2015
10/20/2015
MARYLAND
Talbot County
Map
65
57
41
7
101
79
58
58
19
19
200
Instrument Date
Deed Records
Map
03/04/2015
03/04/2015
03/26/2015
03/31/2015
03/31/2015
03/31/2015
03/31/2015
04/08/2015
04/10/2015
04/21/2015
05/20/2015
05/21/2015
05/28/2015
06/01/2015
06/12/2015
06/12/2015
06/12/2015
06/13/2015
06/30/2015
06/30/2015
07/17/2015
07/21/2015
07/22/2015
07/23/2015
Liber
2250
2251
2250
2270
2270
2270
2270
2270
2270
2270
2278
2268
2270
2270
2278
2278
2278
2278
2278
2287
2287
2287
2290
2287
Folio
219
1
223
274
282
286
290
262
266
270
73
307
258
278
68
63
59
55
51
111
127
131
156
123
53
53
59
59
59
59
59
59
53
59
53
59
59
59
62
62
62
62
62
53
59
62
59
59
10
Parcel
Lot
34
604
46
209
340
20
64
13
332
345
16
Parcel
119
166
125
45
61
67
81
41
167
20
105
40&43
91
107
69
82
63
77
7
119
56
8
119
114
Lot
9
2
2
5
Instrument Date
Deed Records
Map
Liber
2290
2290
2290
2290
2290
2290
2293
2287
2287
2290
2307
2307
2307
2299
2299
2299
2326
Folio
152
160
164
168
172
176
450
115
119
180
34
38
42
69
73
77
378
07/24/2015
07/27/2015
07/27/2015
07/27/2015
07/27/2015
07/29/2015
08/07/2015
08/10/2015
08/10/2015
08/10/2015
08/24/2015
08/24/2015
08/27/2015
09/18/2015
09/18/2015
09/18/2015
01/07/2016
MARYLAND
Wicomico County
Instrument Date
Deed Records
01/14/2015
03/11/2015
03/14/2015
03/17/2015
03/30/2015
04/09/2015
04/20/2015
04/20/2015
04/20/2015
04/21/2015
04/22/2015
05/11/2015
05/13/2015
05/14/2015
05/18/2015
05/18/2015
05/19/2015
Liber
6533
3873
6533
3832
3832
3843
3843
3843
3843
3843
3843
3851
3873
3873
3861
3861
3873
Folio
1
452
9
195
192
141
152
155
138
148
145
238
458
447
0-20
0-15
465
11
59
59
59
59
59
62
22
59
59
11
59
59
59
59
59
59
59
Map
27
39
27
37
37
104
48
48
107
5
70
48
33
39
106
111
31
Lot
1&2
3
4
Lot
5
1&2
Parcel
119
6
7
111
135
06&28
348
23
95
289
119
119
42
17
24
104
108
Parcel
632
181
632
116
120
1344
63
317
1088
1089
1090
1091
1092
10
16
319
50
719
1191
1114
107
Instrument Date
Deed Records
Map
Parcel
Lot
06/09/2015
06/09/2015
09/02/2015
09/02/2015
09/02/2015
09/11/2015
09/23/2015
10/05/2015
10/09/2015
10/12/2015
10/19/2015
10/28/2015
10/28/2015
11/10/2015
12/10/2015
12/11/2015
12/15/2015
12/15/2015
12/15/2015
12/15/2015
12/19/2015
12/09/2014
01/05/2015
01/14/2015
01/28/2015
Liber
3861
3873
841
3902
3902
3906
3909
3921
3913
3923
3923
3933
3933
3933
3942
3964
3950
3950
3950
3950
3950
3791
3800
3803
3810
MARYLAND
Worcester County
Instrument Date
Deed Records
10/28/2014
11/19/2014
12/29/2014
02/06/2015
02/23/2015
02/28/2015
03/25/2015
03/27/2015
03/31/2015
04/03/2015
05/17/2015
Liber
6532
6500
6500
6521
6524
6597
6561
6536
6566
6560
6569
12
Folio
248
461
322
150
153
475
316
163
30
1
6
118
121
124
171
114
286
282
278
274
270
500
266
368
362
Folio
469
50
391
9
375
110
279
271
115
172
29
10
10
773
773
103
61
600
49
30
301
113
63
29
29
54
101
31
48
48
48
48
30
49
115
107
106
Map
301
115
15
27
56
110
63
115
9
7
7
804
804
371
82
315
22
1453
1126
532
9
338
14
5484
5485
460
729
306
321
310
105
65
2937
1887
1306
Parcel
1707
1114A
131
249
83
2797
153
9346
165
4,5,6,7
7
Lot
Instrument Date
Deed Records
05/20/2015
05/20/2015
05/20/2015
05/20/2015
05/20/2015
05/21/2015
06/24/2015
07/03/2015
07/03/2015
07/23/2015
07/23/2015
08/06/2015
08/06/2015
10/17/2015
11/02/2015
11/17/2015
12/04/2015
12/08/2015
12/15/2015
12/16/2015
Liber
6577
6577
6577
6577
6577
6572
6597
6609
6609
6609
6609
6618
6623
6662
6676
6684
6689
6689
6703
6703
Folio
227
230
233
236
239
17
107
429
437
407
426
477
188
45
215
267
375
378
31
28
Map
111
111
111
111
111
9
26
Parcel
5749
5754
5755
5756
5757
386
201
Lot
10
4
5
6
Elliott Bayside Partnership –
Deed of Easement and Release of Rights
Elliott Bayside Partnership - Supplemental
Use and Maintenance Agreement
Seaside Village Commercial Land
Condominium - Deed of Easement and
Release of Rights
Seaside Village Commercial Land
Condominium - Declaration of Easement
Use Limitations
49
49
27
79
49
27
110
20
10
10
6837
637
215
144
466
3894
167
The following is a schedule of bonds issued under the Eighty-Eighth Supplemental Indenture and Credit Line Deed of Trust, effective as of October 1, 1994,
that can be designated as First Mortgage Bonds, Series I, which may also be designated as Secured Medium Term Notes, Series I; and First Mortgage Bonds,
Pledged Series I.
First Mortgage Bonds, Series I/Secured Medium Term Notes, Series I
Issuance Date
06/19/95
06/19/95
11/25/08
First Mortgage Bonds, Pledged Series I
Issuance Date
10/12/94
Total Bonds Issued:
Tranche
7.71% Bonds
6.95% Amortizing Bonds
6.40% Bonds
Maturity
06/01/25
06/01/08
12/01/13
Principal
$100,000,000
$ 25,800,000
$250,000,000
Tranche
1994
Maturity
10/01/29
Principal
$ 33,750,000
$409,550,000
13
As supplemented and amended by this One Hundred and Seventeenth Supplemental Indenture, the Original Indenture and all indentures supplemental thereto
are in all respects ratified and confirmed and the Original Indenture and the aforesaid supplemental indentures and this One Hundred and Seventeenth
Supplemental Indenture shall be read, taken and construed as one and the same instrument.
This One Hundred and Seventeenth Supplemental Indenture shall be simultaneously executed in several counterparts, and all such counterparts executed and
delivered, each as an original, shall constitute but one and the same instrument.
The recitals of fact contained herein shall be taken as the statements of the Company, and the Trustee assumes no responsibility for the correctness of the
same.
The debtor and its mailing address are Delmarva Power & Light Company, Mailstop 92DC42, 500 N. Wakefield Drive, Newark, Delaware 19702-5440. The
secured party and its address, from which information concerning the security interest hereunder may be obtained, is The Bank of New York Mellon, 500 Ross
Street, 12 th Floor, Pittsburgh, Pennsylvania 15262, Attn: Corporate Trust Administration.
The Company acknowledges that it received a true and correct copy of this One Hundred and Seventeenth Supplemental Indenture.
14
This One Hundred and Seventeenth Supplemental Indenture is executed and delivered pursuant to the provisions of Section 5.11 and paragraph (a) of
Section 17.01 of the Indenture for the purpose of conveying, transferring and assigning to the Trustee and of subjecting to the lien of the Indenture with the same
force and effect as though included in the granting clause thereof the above described property so acquired by the Company on or prior to the date of execution, and
not heretofore specifically subject to the lien of the Indenture; but nothing contained in this One Hundred and Seventeenth Supplemental Indenture shall be deemed
in any manner to affect (except for such purposes) or to impair the provisions, terms and conditions of the Original Indenture, or of any indenture supplemental
thereto and the provisions, terms and conditions thereof are hereby expressly confirmed.
[REMAINDER OF PAGE INTENTIONALLY LEFT BLANK]
15
IN WITNESS WHEREOF, the Company has caused this instrument to be signed in its name and behalf by its President, and its corporate seal to be hereunto
affixed and attested by its Assistant Secretary and the Trustee has caused this instrument to be signed in its name and behalf by a Vice President and its corporate
seal to be hereunto affixed and attested by an authorized officer, effective as of the 1st day of January, 2016.
Date of Execution
April 7, 2016
STATE OF DELAWARE
COUNTY OF NEW CASTLE
)
) SS
)
DELMARVA POWER & LIGHT COMPANY
By /s/ David M. Velazquez
David M. Velazquez, President
Attest:
/s/ Jeffery E. Snyder [SEAL]
Jeffery E. Snyder, Assistant Secretary
BE IT REMEMBERED that as of the 7 th day of April, 2016, personally came before me, a notary public for the State of Delaware, David M. Velazquez,
President of DELMARVA POWER & LIGHT COMPANY, a corporation of the State of Delaware and the Commonwealth of Virginia (the “Company”), party to
the foregoing instrument, known to me personally to be such, and acknowledged the instrument to be his own act and deed and the act and deed of the Company;
that his signature is in his own proper handwriting; that the seal affixed is the common or corporate seal of the Company; and that his act of signing, sealing,
executing and delivering such instrument was duly authorized by resolution of the Board of Directors of the Company.
GIVEN under my hand and official seal the day and year aforesaid.
/s/ Julia P. Reilly
Notary Public, State of Delaware
My commission expires .
[SEAL]
Julia P. Reilly
Notary Public
State of Delaware
My Commission Expires:
April 3, 2017
16
Date of Execution
April 7, 2016
STATE OF NEW YORK
COUNTY OF NEW YORK
)
) SS.
)
THE BANK OF NEW YORK MELLON,
as Trustee
By /s/ Francine J. Kincaid
Francine J. Kincaid, Vice President
Attest:
/s/ Arsala Kidwai
Arsala Kidwai, Vice President
BE IT REMEMBERED that on this 7 th day of April, 2016, personally came before me, a Notary Public for the State of New York, Francine J. Kincaid, Vice
President of THE BANK OF NEW YORK MELLON, a New York banking corporation (the “Trustee”), party to the foregoing instrument, known to me personally
to be such, and acknowledged the instrument to be her own act and deed and the act and deed of the Trustee; that his signature is her own proper handwriting; that
the seal affixed is the common or corporate seal of the Trustee; and that her act of signing, sealing, executing and delivering said instrument was duly authorized by
resolution of the Board of Directors of the Trustee.
GIVEN under my hand and official seal the day and year aforesaid.
/s/ Christopher J. Traina
Notary Public, State of New York
My commission expires .
Christopher J. Traina
Notary Public-State of New York
No. 01TR6297825
Qualified in Queen’s County
Qualified in New York County
My Commission Expires March 03, 2018
[SEAL]
17
CERTIFICATE OF RESIDENCE
THE BANK OF NEW YORK MELLON, successor Trustee to the Trustee within named, hereby certifies that it has a residence at 101 Barclay Street, in the
Borough of Manhattan, in The City of New York, in the State of New York.
THE BANK OF NEW YORK MELLON
By /s/ Francine J. Kincaid
Name: Francine J. Kincaid
Title: Vice President
18
Certification
This document was prepared under the supervision of an attorney admitted to practice before the Court of Appeals of Maryland, or by or on behalf of one of
the parties named in the within instrument.
/s/ Christie D. Cannon
Christie D. Cannon
19
CONFIDENTIAL SEPARATION AGREEMENT
Exhibit 10.22
THIS CONFIDENTIAL SEPARATION AGREEMENT (this “ Agreement
”) is entered into as of between Exelon Corporation (“Exelon”),
(“Subsidiary”, and, collectively with Exelon, the “ Company
”) and (the “ Executive
”).
WHEREAS, the Executive is separating from all positions with Exelon, Subsidiary and their respective affiliates.
W I T N E S S E T H:
NOW, THEREFORE, in consideration of the mutual promises and agreements contained herein, the adequacy and sufficiency of which are hereby
acknowledged, the Company and the Executive agree as follows:
1. Resignation; Termination of Employment . The Executive’s employment with Subsidiary will be terminated, and Executive hereby resigns, each effective
as of the close of business on (the “ Termination
Date
”), as Vice President of Subsidiary and from all other positions as an officer or director of Exelon and
its subsidiaries and affiliates.
2. Payment of Accrued Amounts . The Company shall pay to the Executive not later than the second payroll date after the Termination Date the following
amounts:
(a) the portion of his or her annual salary that has accrued but is unpaid as of the Termination Date; and
(b) an additional amount representing the Executive’s accrued but unused vacation days as of the Termination Date, if any.
3. Severance Payments . The Company shall pay to the Executive:
(a) cash severance payments in an aggregate amount equal to $ which is equal to 1. times the sum of (i) the Executive’s base salary of $
plus (ii) the Executive’s 201_ target annual incentive award of $ . Payment shall commence not later than forty-five days following the
Termination Date, in substantially equal regular payroll installments over a period of fifteen months; and
(b) Executive shall remain eligible to receive a pro-rated annual incentive award for 201_ based on actual performance results determined in a manner
consistent with peer executives, payable at the time such awards (if any) are paid to active executives (but not later than March 15, 201_), and such payment shall
be considered a short-term deferral for purposes of section 409A of the Code.
4. Tax Withholding . The Company shall deduct from the amounts payable to the Executive pursuant to this Agreement the amount of all required federal,
state and local withholding taxes in accordance with the Executive’s Form W-4 on file with the Company and
1
all applicable social security and Medicare taxes. The Company shall be entitled to withhold from any shares of common stock of the Company to be delivered to
the Executive pursuant to Sections 6(a), (b) and (c) a number of shares of common stock of the Company having a value (based upon the closing price of a share of
the Company’s common stock as reported on the New York Stock Exchange on the applicable valuation date) equal to the minimum amount of all required federal,
state and local withholding taxes and all applicable social security and Medicare taxes with respect to the lapse of forfeiture conditions applicable to the vesting of
performance shares or the exercise of options.
5. Outplacement Assistance and Financial Counseling . During the twelve-month period following the Termination Date, the Company shall reimburse the
Executive for reasonable fees incurred for services rendered to the Executive by a professional outplacement organization selected by the Executive and acceptable
to the Company to provide individual outplacement services, and Executive also shall be eligible to receive financial counseling services consistent with the terms
and conditions applicable to active peer executives under Exelon’s executive perquisite policy.
6. Long Term Incentive Awards . Subject to Executive’s timely execution of (and not revoking) the Waiver and Release,
(a) each of Executive’s options to purchase common stock of Exelon granted pursuant to the Exelon Corporation Long-Term Incentive Plan shall (i) to
the extent exercisable on the Termination Date, remain exercisable for ninety days following the Termination Date (or until the option expiration date, if earlier),
and (ii) to the extent not exercisable as of the Termination Date, be forfeited as of the Termination Date;
(b) Executive shall remain eligible to receive (i) full long-term [performance share / cash] awards under Exelon’s long-term incentive program for the
201_-201_ and 201_-201_ performance cycles, the respective amounts (if any) of which shall be determined based on actual performance results for such
respective periods, and all such awards shall be payable at the time or times such respective awards are paid to active executives; and
(c) the non-vested portion of Executive’s [restricted stock unit / cash unit] awards granted on January __, 201_, January __, 201_ and January __, 201_
under Exelon’s long term incentive program shall become fully vested as of the Termination Date.
All such awards payable in shares shall be subject to the Company’s applicable resale restrictions, if any.
7. Supplemental Executive Retirement Benefits . The Executive shall be eligible for a retirement benefit under the Exelon applicable supplemental
management retirement plan in which Executive is a participant (the “ SERP
”) in accordance with the terms and conditions thereof, except that in determining such
benefit, the Executive shall, subject to the Executive’s timely execution of the Waiver and Release, be credited with months additional service calculated as
though he or she received the severance benefits specified in Section 3(a) as regular salary incentive pay over such period (and limited in its application to the
amounts of such payments that exceed the compensation limitations applicable to qualified pension plans under the Code). Such benefit shall be paid as provided in
Section 8(b).
2
8. Employee and Other Benefits .
(a) During the period commencing on the Termination Date and ending months after the Termination Date (the “ Severance
Period
”) and in
satisfaction of COBRA continuation coverage during such period with respect to healthcare benefits, (i) the Executive (and his or her participating dependents)
shall be eligible to participate in, and shall receive benefits under Exelon’s welfare benefit plans (including medical, dental, vision and hearing) in which the
Executive (and his or her eligible dependents) were participating immediately prior to the Termination Date, and (ii) the Executive shall be eligible to participate in
the life insurance programs in which he or she was a participant immediately prior to the Termination Date, in each case on the same basis as if the Executive had
remained actively employed during the Severance Period.
(b) Following the Severance Period, the Executive (and his or her eligible dependents) shall be eligible for continued health care coverage at
Executive’s sole expense for any remaining period required by COBRA.
(c) The Company shall pay to the Executive, in the time and manner specified in the terms and conditions of such plans and any distribution elections
by the Executive in effect thereunder, his or her account balances (if any) under Exelon’s deferred compensation plans, as adjusted by all applicable earnings and
losses on such account balances.
(d) The Executive shall be entitled to purchase the computer furnished by the Company for his or her use, subject to removal of data and programs as
determined by the Company. The Executive shall be responsible for payment of expenses incurred after the Termination Date with respect to the Company-owned
cellular phone furnished for his or her use.
(e) If the Executive is entitled to any benefit under any employee benefit plan of the Company that is accrued and vested on the Termination Date and
that is not expressly referred to in this Agreement, such benefit shall be provided to the Executive in accordance with the terms of such employee benefit plan.
(f) Notwithstanding Section 8(e) or anything else contained in this Agreement to the contrary, the Executive acknowledges and agrees that he or she is
not and shall not be entitled to benefits under any other severance or change in control plan, program, agreement or arrangement, and that the benefits provided
under this Agreement shall be the sole and exclusive benefits to which the Executive may become entitled upon his or her termination of employment. In the event
the Executive dies prior to executing the Waiver and Release (as described in Section 9 below) attached hereto, neither he or she, his or her estate, nor any other
person shall be entitled to any further compensation or benefits under this Agreement, unless and until the executor of the Executive’s estate (and/or such other
heirs or representatives as may be requested by the Company) executes upon Company request and does not revoke such a Waiver and Release.
3
9. Waiver and Release . Notwithstanding anything herein to the contrary, Executive’s right to the payments and benefits under this Agreement shall be
contingent upon (a) Executive having executed and delivered to the Company a waiver and general release provided by the Company (the “ Waiver
and
Release
”)
not earlier than the Termination Date and not later than the date set forth in the release (but in no event more than days after the Termination Date) (the
“Consideration Period”), (b) Executive not revoking such release in accordance with the terms of the release and (c) Executive not violating any of Executive’s on-
going obligations under this Agreement; provided, however, that the Company has the discretion to pay such benefits prior to receipt of the Waiver and Release
and/or the expiration of the revocation period; provided further that if Executive does not execute and deliver the Waiver and Release to the Company prior to the
expiration of the Consideration Period or if the Executive revokes the Waiver and Release in accordance with its terms, Executive shall pay to the Company within
10 days following the expiration of the Consideration Period or the date such release was revoked, a lump sum payment of all payments received by Executive to
date hereunder.
10. Restrictive Covenants . The Executive acknowledges and agrees that he or she is bound by, and subject to, the Restrictive Covenants and the Waiver and
Release. The Executive shall comply with, and observe, the Restrictive Covenants including, without limitation, the confidential information, non-solicitation and
intellectual property provisions and related covenants contained therein, all of which are hereby incorporated by reference. In the event the Company determines
that Executive has breached any of the Restrictive Covenants or the Waiver and Release or has engaged in conduct during his or her employment with the
Company that would constitute ground for termination for Cause, benefits under this Agreement shall terminate immediately, and Executive shall reimburse Exelon
for any benefits received.
11. Certain Tax Matters .
(a) If it is determined by Exelon’s independent auditors that any severance payment, benefit or enhancement that is provided to the Executive pursuant
to the terms of the this Agreement is or will become subject to any excise tax under section 4999 of the Internal Revenue Code of 1986, as amended, or any similar
tax payable under any United States federal, state, local, foreign or other law (“ Excise
Taxes
”), then such payment, benefit or enhancement shall be reduced to the
largest amount which would not cause any such Excise Tax to by payable by the Executive and not cause a loss of the related income tax deduction by the
Company.
(b) The parties intend this Agreement to comply with section 409A of the Code. In the event the timing of any payment or benefit under this
Agreement would result in any tax or penalty under section 409A of the Code, the Company may reasonably adjust the timing of such payment or benefit if doing
so will eliminate or materially reduce such tax or penalty and amend this Agreement accordingly. Executive acknowledges that Executive has been advised to
consult Executive’s personal tax advisor concerning this Agreement, and has not relied on the Company or Subsidiary for tax advice.
12. Non-disparagement . The Executive shall not (a) make any written or oral statement that brings the Company or any of its affiliates or the employees,
officers, directors or agents of the Company or any of its affiliates into disrepute, or tarnishes any of their images or
4
reputations or (b) publish, comment upon or disseminate any statements suggesting or accusing the Company or any of its affiliates, employees, officers, directors
or agents of any misconduct or unlawful behavior. The provisions of this Section 12 shall not apply to truthful testimony as a witness, compliance with other legal
obligations, assertion of or defense against any claim of breach of this Agreement, or any activity that otherwise may be required by the lawful order of a court or
agency of competent jurisdiction, and shall not require the Executive to make false statements or disclosures.
13. Publicity . Executive shall not issue or cause the publication of any press release or other announcement with respect to the terms or provisions of this
Agreement, nor disclose the contents hereof to any third party (other than to members of his or her immediate family or to tax, financial and legal advisors),
without obtaining the consent of Exelon, except where such release, announcement or disclosure shall be required by applicable law or administrative regulation or
agency or other legal process.
14. Other Employment; Other Plans . The Executive shall not be obligated to seek other employment or take any other action by way of mitigation of the
amounts payable to the Executive under any provision of this Agreement. The amounts payable hereunder shall not be reduced by any payments received by the
Executive from any other employer; provided
, however
, that any continued welfare benefits provided for by Section 8(a) shall not duplicate any benefits that are
provided to the Executive and his or her family by such other employer and shall be secondary to any coverage provided by Medicare.
15. Cooperation by the Executive . During the Severance Period, the Executive shall (a) be reasonably available to the Company to respond to requests by
them for information pertaining to or relating to matters which may be within the knowledge of the Executive and (b) cooperate with the Company in connection
with any existing or future litigation or other proceedings brought by or against the Company, its subsidiaries or affiliates, to the extent Exelon reasonably deems
the Executive’s cooperation necessary, including truthful testimony in any related proceeding.
16. Successors; Binding Agreement . This Agreement shall inure to the benefit of and binding upon the Company and its successors, and by the Executive,
his or her spouse, personal or legal representatives, executors, administrators and heirs. This Agreement, being personal, may not be assigned by Executive.
17. Governing Law; Validity . This Agreement shall be interpreted, construed and enforced in accordance with the terms of the Exelon Corporation Senior
Management Severance Plan, and the applicable provisions of the Employee Retirement Income Security Act of 1974, as amended, and section 409A of the Code.
18. Entire Agreement . This Agreement and the Waiver and Release constitute the entire agreement and understanding between the parties with respect to the
subject matter hereof and supersede and preempt any other understandings, agreements or representations by or between the parties, written or oral, which may
have related in any manner to the subject matter hereof. Executive acknowledges that the Company has made no representations regarding the tax consequences of
payments under this Agreement and has had the opportunity to consult Executive’s tax advisor.
5
19. Counterparts . This Agreement may be executed in two counterparts, each of which shall be deemed to be an original and both of which together shall
constitute one and the same instrument.
20. Miscellaneous . No provision of this Agreement may be modified or waived unless such modification or waiver is agreed to in writing and executed by
the Executive and by a duly authorized officer of the Company. No waiver by either party hereto at any time of any breach by the other party hereto of, or
compliance with, any condition or provision of this Agreement to be performed by such other party shall be deemed a waiver of similar or dissimilar provisions or
conditions at the same or at any prior or subsequent time. Failure by the Executive or the Company to insist upon strict compliance with any provision of this
Agreement or to assert any right which the Executive or the Company may have hereunder shall not be deemed to be a waiver of such provision or right or any
other provision or right of this Agreement.
21. Beneficiary . If the Executive dies prior to receiving all of the amounts payable hereunder (other than amounts payable under any plan referenced in
Section 8(d), which shall be governed by any beneficiary designation in effect thereunder) but after executing the Waiver and Release, such amounts shall be paid,
except as may be otherwise expressly provided herein or in the applicable plans, to the beneficiary (“ Beneficiary
”) designated with respect to this Agreement by
the Executive in writing to the Vice President, Corporate Compensation of the Company during his or her lifetime, which the Executive may change from time to
time by new designation filed in like manner without the consent of any Beneficiary; or if no such Beneficiary is designated, to his or her surviving spouse, and if
there be none, to his or her estate.
22. Nonalienation of Benefits . Benefits payable under this Agreement shall not be subject in any manner to anticipation, alienation, sale, transfer,
assignment, pledge, encumbrance, charge, prior to actually being received by the Executive, and any such attempt to dispose of any right to benefits payable
hereunder shall be void.
23. Severability . If all or any part of this Agreement is declared by any court or governmental authority to be unlawful or invalid, such unlawfulness or
invalidity shall not serve to invalidate any portion of this Agreement not declared to be unlawful or invalid, except that in the event a determination is made that the
Restrictive Covenants as applied to the Executive are invalid or unenforceable in whole or in part, then this Agreement shall be void and the Company shall have
no obligation to provide benefits hereunder. Any paragraph or part of a paragraph so declared to be unlawful or invalid shall, if possible, be construed in a manner
which will give effect to the terms of such paragraph or part of a paragraph to the fullest extent possible while remaining lawful and valid.
24. Communications . Nothing in this Agreement or the Waiver and Release shall be construed to prohibit or limit the Executive from filing a charge with, or
reporting possible violations of law or regulation to any governmental agency or entity, including but not limited to the National Labor Relations Board, Nuclear
Regulatory Commission, U.S. Equal Opportunity Commission, the Department of Labor, the Department of Justice, the Securities Exchange
6
Commission, the Congress, and any agency Inspector General, or making other disclosures that are protected under the whistleblower provisions of applicable law
or regulation, or taking any other action protected under section 211 of the Energy Reorganization Act. The Executive does not need the prior authorization of the
Company to make any such charges, reports or disclosures, and is not required to notify the Company that Executive has made such charges reports or disclosures,
and no such report or disclosure shall be considered a violation of Section 12 of this Agreement or the Waiver and Release. In addition, neither this Agreement nor
the Waiver and Release limits the Executive’s ability to receive a monetary award from a government-administered whistleblower award program for providing
any such reports or disclosures directly to a governmental agency. Executive acknowledges, however, that the Waiver and Release requires Executive to
specifically waive all rights to recover any monetary damages from the Company, including but not limited to lost wages and benefits, lost pay, damages for
emotional distress, punitive damages, reinstatement, and attorneys’ fees and costs.
25. Sections . Except where otherwise indicated by the context, any reference to a “Section” shall be to a Section of this Agreement.
IN WITNESS WHEREOF, Exelon and Subsidiary have caused this Agreement to be executed by their duly authorized officers and the Executive has
executed this Agreement as of the day and year first above written.
EXELON CORPORATION
By:
Vice President, Corporate Compensation
SUBSIDIARY
By:
Vice President, Human Resources
7
EXECUTIVE
WAIVER AND RELEASE
UNDER
CONFIDENTIAL SEPARATION AGREEMENT
In consideration for the Executive’s receiving severance benefits under the Separation Agreement (as defined below), (the “Executive”) hereby
agrees as follows:
1. Release. Except with respect to the Company’s obligations under the Confidential Separation Agreement by and between Exelon Corporation,
, (collectively, the “ Company
”) and the Executive dated as of (the “ Separation
Agreement
”), the Executive, on behalf of Executive and
his or her heirs, executors, assigns, agents, legal representatives and personal representatives, hereby releases, acquits and forever discharges the Company, its
agents, subsidiaries, affiliates, and their respective officers, directors, agents, servants, employees, attorneys, shareholders, successors, assigns and affiliates, of and
from any and all claims, liabilities, demands, causes of action, costs, expenses, attorneys fees, damages, indemnities and obligations of every kind and nature, in
law, equity, or otherwise, known and unknown, foreseen or unforeseen, disclosed and undisclosed, suspected and unsuspected, arising out of or in any way related
to agreements, events, acts or conduct at any time prior to the day of execution of this Waiver and Release, including but not limited to any and all such claims and
demands directly or indirectly arising out of or in any way connected with the Executive’s employment or other service with the Company, or any of its
Subsidiaries or affiliates; the Executive’s termination of employment and other service with the Company or any of its subsidiaries or affiliates; claims or demands
related to salary, bonuses, commissions, stock, stock options, restricted stock or any other ownership interests in the Company or any of its subsidiaries and
affiliates, vacation pay, fringe benefits, expense reimbursements, sabbatical benefits, severance, change in control or other separation benefits, or any other form of
compensation or equity; and claims pursuant to any federal, state, local law, statute, ordinance, common law or other cause of action including but not limited to,
the federal Civil Rights Act of 1964, as amended; the federal Age Discrimination in Employment Act of 1967, as amended; the federal Americans with Disabilities
Act of 1990; the Employee Retirement Income Security Act of 1974, as amended, tort law; contract law; wrongful discharge; discrimination; fraud; defamation;
harassment; emotional distress; or breach of the covenant of good faith and fair dealing. This Waiver and Release does not apply to the payment of any benefits to
which the Executive may be entitled under a Company-sponsored tax qualified retirement or savings plan or Executives’s entitlement to indemnification with
respect to his service as an officer, director, employee or agent of the Company in accordance with Article VII of the Exelon Corporation Amended and Restated
Bylaws.
2. No Inducement . The Executive agrees that no promise or inducement to enter into this Waiver or Release has been offered or made except as set forth in
this Waiver and Release and the Separation Agreement, that the Executive is entering into this Waiver and Release without any threat or coercion and without
reliance on any statement or representation made on behalf of the Company or any of its subsidiaries or affiliates, or by any person employed by or representing the
Company or any of its subsidiaries or affiliates, except for the written provisions and promises contained in this Waiver and Release and the Separation Agreement.
1
3. Advice of Counsel; Time to Consider; Revocation . The Executive acknowledges the following:
(a) The Executive has read this Waiver and Release, and understands its legal and binding effect, including that by signing and not revoking
this Waiver and Release the Executive waives and releases any and all claims under the Age Discrimination in Employment Act of 1967, as
amended, including but not limited to the Older Workers Benefits Protection Act. The Executive is acting voluntarily and of the Executive’s
own free will in executing this Waiver and Release.
(b) The Executive has been advised to seek and has had the opportunity to seek legal counsel in connection with this Waiver and Release.
(c) The Executive was given at least twenty-one (21) days to consider the terms of this Waiver and Release before signing it.
(d) At the time Executive was given this Waiver and Release, Executive was informed that his or her termination was not part of a group
separation.
The Executive understands that, if the Executive signs the Waiver and Release, the Executive may revoke it within seven (7) days after signing it,
provided that Executive will not receive any severance benefits under the Separation Agreement. The Executive understands that this Waiver and
Release will not be effective until after the seven-day period has expired and no consideration will be due the Executive.
4. Severability . If all or any part of this Waiver and Release is declared by any court or governmental authority to be unlawful or invalid, such unlawfulness
or invalidity shall not invalidate any other portion of this Waiver and Release. Any Section or a part of a Section declared to be unlawful or invalid shall, if
possible, be construed in a manner which will give effect to the terms of the Section to the fullest extent possible while remaining lawful and valid.
5. Amendment . This Waiver and Release shall not be altered, amended, or modified except by written instrument executed by the Company and the
Executive. A waiver of any portion of this Waiver and Release shall not be deemed a waiver of any other portion of this Waiver and Release.
6. Applicable Law . The provisions of this Waiver and Release shall be interpreted and construed in accordance with the laws of the State of Illinois without
regard to its choice of law principles.
IN WITNESS WHEREOF, the Executive has executed this Waiver and Release as of the date specified below.
EXECUTIVE
DATE:
2
Exelon Corporation
Ratio of Earnings to Fixed Charges
Exhibit 12.1
Pre-tax income from continuing operations
Plus: Loss (income) from equity investees
Less: Capitalized interest
Pre-tax income from continuing operations after adjustment for income or loss from equity investees and
capitalized interest
Fixed Charges:
Interest expensed and capitalized, amortization of debt discount and premium on all indebtedness
Interest component of rental expense (a)
Total fixed charges
Pre-tax income from continuing operations after adjustment for income or loss from equity investees and
capitalized interest plus fixed charges
Ratio of earnings to fixed charges
Years Ended December 31,
2013
2014
2016
2012
1,798 2,773 2,486 3,330 1,989
20 — —
(99) (142)
(79)
(10)
(67)
91
(75)
2015
1,814 2,696 2,427 3,231 1,847
1,021 1,436 1,110 1,107 1,651
310 269 288 300 259
1,331 1,705 1,398 1,407 1,910
3,145 4,401 3,825 4,638 3,757
2.0
2.6
2.4
2.7
3.3
(a)
Represents one-third of rental expense relating to operating leases, which is a reasonable approximation of the interest factor.
Exelon Corporation
Ratio of Earnings to Fixed Charges and Preferred Stock Dividends
Pre-tax income from continuing operations
Plus: Loss (income) from equity investees
Less: Capitalized interest
Preference security dividend requirements
Pre-tax income from continuing operations after adjustment for income or loss from equity investees, capitalized
Years Ended December 31,
2013
2014
2015
2012
2016
1,798 2,773 2,486 3,330 1,989
20 — —
(99) (142)
(79)
(13)
(19)
(18)
(10)
(67)
(32)
91
(75)
(26)
interest and preference security dividend requirements
1,788 2,664 2,409 3,212 1,834
Fixed Charges:
Interest expensed and capitalized, amortization of debt discount and premium on all indebtedness
Interest component of rental expense (a)
Preference security dividend requirements of consolidated subsidiaries
Total fixed charges
Pre-tax income from continuing operations after adjustment for income or loss from equity investees, capitalized
interest and preference security dividend requirements plus fixed charges
Ratio of earnings to fixed charges and preferred stock dividends
1,021 1,436 1,110 1,107 1,651
310 269 288 300 259
13
1,357 1,737 1,416 1,426 1,923
32
26
18
19
3,145 4,401 3,825 4,638 3,757
2.0
2.3
3.3
2.5
2.7
(a)
Represents one-third of rental expense relating to operating leases, which is a reasonable approximation of the interest factor.
Exelon Generation Company, LLC
Ratio of Earnings to Fixed Charges
Exhibit 12.2
Pre-tax income from continuing operations
Plus: Loss (income) from equity investees
Less: Capitalized interest
Pre-tax income from continuing operations after adjustment for income or loss from equity investees and
capitalized interest
Fixed Charges:
Interest expensed and capitalized, amortization of debt discount and premium on all indebtedness
Interest component of rental expense (a)
Total fixed charges
Pre-tax income from continuing operations after adjustment for income or loss from equity investees and
capitalized interest plus fixed charges
Ratio of earnings to combined fixed charges
Years Ended December 31,
2013
2014
2016
2012
1,058 1,675 1,226 1,850 873
20 — —
(79) (107)
(63)
(10)
(54)
91
(67)
2015
1,082 1,611 1,183 1,771 766
402 445 396 427 454
291 248 269 284 222
693 693 665 711 676
1,775 2,304 1,848 2,482 1,442
2.1
3.5
2.8
2.6
3.3
(a)
Represents one-third of rental expense relating to operating leases, which is a reasonable approximation of the interest factor.
Commonwealth Edison Company
Ratio of Earnings to Fixed Charges
Exhibit 12.3
Pre-tax income from continuing operations
Less:Capitalized interest
Pre-tax income from continuing operations after adjustment for income or loss from equity investees and capitalized
Years Ended December 31,
2015
2016
2012 2013 2014
618 401 676 706 679
(8)
(4)
(2)
(3)
(5)
interest
615 396 674 702 671
Fixed Charges:
Interest expensed and capitalized, amortization of debt discount and premium on all indebtedness
Interest component of rental expense (a)
Total fixed charges
Pre-tax income from continuing operations after adjustment for income or loss from equity investees, capitalized interest
297 575 311 331 465
5
303 580 316 335 470
4
5
6
5
plus fixed charges
Ratio of earnings to fixed charges
918 976 990 1,037 1,141
2.4
3.0 1.7 3.1
3.1
(a)
Represents one-third of rental expense relating to operating leases, which is a reasonable approximation of the interest factor.
PECO Energy Company
Ratio of Earnings to Fixed Charges
Exhibit 12.4
Pre-tax income from continuing operations
Less: Capitalized interest
Pre-tax income from continuing operations after adjustment for income or loss from equity investees and capitalized interest
Fixed Charges:
Interest expensed and capitalized, amortization of debt discount and premium on all indebtedness
Interest component of rental expense (a)
Total fixed charges
Pre-tax income from continuing operations after adjustment for income or loss from equity investees and capitalized interest
Years Ended December 31,
2012 2013 2014 2015 2016
508 557 466 521 587
(3)
506 555 464 519 584
(2)
(2)
(2)
(2)
122 114 112 114 125
2
131 121 117 117 127
5
7
3
9
plus fixed charges
Ratio of earnings to combined fixed charges
637 676 581 636 711
4.9 5.6 5.0 5.4 5.6
(a)
Represents one-third of rental expense relating to operating leases, which is a reasonable approximation of the interest factor.
PECO Energy Company
Ratio of Earnings to Fixed Charges and Preferred Stock Dividends
Pre-tax income from continuing operations
Less: Capitalized interest
Preference security dividend requirements
Pre-tax income from continuing operations after adjustment for income or loss from equity investees, capitalized interest and
Years Ended December 31,
2012 2013 2014 2015 2016
508 557 466 521 587
(2)
(3)
(2)
(5) (10) — — —
(2)
(2)
preference security dividend requirements
501 545 464 519 584
Fixed Charges:
Interest expensed and capitalized, amortization of debt discount and premium on all indebtedness
Interest component of rental expense (a)
Preference security dividend requirements
Total fixed charges
Pre-tax income from continuing operations after adjustment for income or loss from equity investees, capitalized interest and
122 114 112 114 125
9
2
5
5 10 — — —
136 131 117 117 127
3
7
preference security dividend requirements plus fixed charges
Ratio of earnings to fixed charges and preferred stock dividends
637 676 581 636 711
4.7 5.2 5.0 5.4 5.6
(a)
Represents one-third of rental expense relating to operating leases, which is a reasonable approximation of the interest factor.
BGE
Ratio of Earnings to Fixed Charges
Pre-tax income from continuing operations
Less: Capitalized interest
Pre-tax income from continuing operations after adjustment for income or loss from equity investees and capitalized interest
Fixed Charges:
Interest expensed and capitalized, amortization of debt discount and premium on all indebtedness
Interest component of rental expense (a)
Total fixed charges
Pre-tax income from continuing operations after adjustment for income or loss from equity investees, capitalized interest and
Exhibit 12.5
Years Ended December 31,
2012 2013 2014 2015 2016
11 344 351 477 468
(5)
(6) (12) (14) (11)
6 338 339 463 457
149 127 118 113 115
7
153 131 122 124 122
4 11
4
4
preference security dividend requirements plus fixed charges
Ratio of earnings to fixed charges
159 469 461 587 579
1.0 3.6 3.8 4.7 4.7
(a)
Represents one-third of rental expense relating to operating leases, which is a reasonable approximation of the interest factor.
BGE
Ratio of Earnings to Fixed Charges and Preference Stock Dividends
Pre-tax income from continuing operations
Less: Capitalized interest
Preference security dividend requirements
Pre-tax income from continuing operations after adjustment for income or loss from equity investees and capitalized
interest
Years Ended December 31,
2012
11
(5)
(20)
2013 2014 2015 2016
344 351 477 468
(6) (12) (14) (11)
(21) (22) (22) (13)
(14)
317 317 441 444
Fixed Charges:
Interest expensed and capitalized, amortization of debt discount and premium on all indebtedness
Interest component of rental expense (a)
Preference security dividend requirements
Total fixed charges
Pre-tax income from continuing operations after adjustment for income or loss from equity investees, capitalized interest
149
4
20
173
4
127 118 113 115
7
21 22 22 13
152 144 146 135
4 11
and preference security dividend requirements plus fixed charges
Ratio of earnings to fixed charges and preferred stock dividends
159
469 461 587 579
0.9(b) 3.1 3.2 4.0 4.3
(a)
(b)
Represents one-third of rental expense relating to operating leases, which is a reasonable approximation of the interest factor.
The ratio coverage was less than 1:1. The registrant must generate additional earnings of $14 million to achieve a coverage ratio of 1:1.
Pepco Holdings LLC and Subsidiary Companies
Ratio of Earnings to Fixed Charges
Exhibit 12.6
Pre-tax income from continuing operations
Plus: (Income) loss from equity investees
Less: Capitalized interest
Pre-tax income from continuing operations after adjustment for income or loss
Years Ended December 31,
Predecessor
2012
344
(1)
(3)
2013
304
(2)
(2)
2014
380
—
(3)
2015
481
—
(2)
January 1, 2016
to
March 23, 2016
36
—
(3)
Successor
March 24, 2016
to
December 31, 2016
(58)
—
(12)
from equity investees and capitalized interest
340
300
377
479
Fixed Charges:
Interest expensed and capitalized, amortization of debt discount and premium on
all indebtedness
Interest component of rental expense (a)
Total fixed charges
Pre-tax income from continuing operations after adjustment for income or loss
from equity investees and capitalized interest plus fixed charges
Ratio of earnings to fixed charges
265
21
286
279
22
301
276
24
300
288
24
312
626
2.2
601
2.0
677
2.3
791
2.5
33
69
4
73
106
1.5
(70)
210
16
226
156
0.7(b)
(a)
(b)
Represents one-third of rental expense relating to operating leases, which is a reasonable approximation of the interest factor.
The ratio coverage was less than 1:1. The registrant must generate additional earnings of $70 million to achieve a coverage ratio of 1:1.
Potomac Electric Power Company
Ratio of Earnings to Fixed Charges
Exhibit 12.7
Pre-tax income from continuing operations
Less: Capitalized interest
Pre-tax income from continuing operations after adjustment for income or loss from equity investees and capitalized interest
Fixed Charges:
Interest expensed and capitalized, amortization of debt discount and premium on all indebtedness
Interest component of rental expense (a)
Total fixed charges
Pre-tax income from continuing operations after adjustment for income or loss from equity investees and capitalized interest
Years Ended December 31,
2012 2013 2014 2015 2016
193 235 264 289 83
(1) (10)
191 234 262 288 73
(2)
(2)
(1)
106 114 121 130 137
3
113 121 128 137 140
7
7
7
7
plus fixed charges
Ratio of earnings to fixed charges
304 355 390 425 213
2.7 2.9 3.0 3.1 1.5
(a)
Represents one-third of rental expense relating to operating leases, which is a reasonable approximation of the interest factor.
Delmarva Power & Light Company
Ratio of Earnings to Fixed Charges
Pre-tax income from continuing operations
Less: Capitalized interest
Pre-tax income from continuing operations after adjustment for income or loss from equity investees and capitalized
interest
Fixed Charges:
Interest expensed and capitalized, amortization of debt discount and premium on all indebtedness
Interest component of rental expense (a)
Total fixed charges
Pre-tax income from continuing operations after adjustment for income or loss from equity investees and capitalized
interest plus fixed charges
Ratio of earnings to fixed charges
Exhibit 12.8
Years Ended December 31,
2012
118
—
2013
146
—
2014
169
—
2015 2016
13
125
(2)
—
118
146
169
125
11
49
3
52
52
3
55
49
4
53
50
4
54
51
5
56
170
3.3
201
3.7
222
4.2
179
3.3
67
1.2
(a)
Represents one-third of rental expense relating to operating leases, which is a reasonable approximation of the interest factor.
Atlantic City Electric Company and Subsidiary Company
Ratio of Earnings to Fixed Charges
Pre-tax income from continuing operations
Less: Capitalized interest
Pre-tax income from continuing operations after adjustment for income or loss from equity investees and capitalized
interest
Fixed Charges:
Interest expensed and capitalized, amortization of debt discount and premium on all indebtedness
Interest component of rental expense (a)
Total fixed charges
Pre-tax income from continuing operations after adjustment for income or loss from equity investees and capitalized
interest plus fixed charges
Ratio of earnings to fixed charges
Exhibit 12.9
Years Ended December 31,
2012
52
—
2013
78
—
2014
76
—
2015 2016
(46)
73
(3)
—
52
78
76
73
(49)
71
4
75
68
4
72
64
4
68
65
4
69
64
4
68
127
1.7
150
2.1
144
2.1
142
2.1
19
0.3(b)
(a)
(b)
Represents one-third of rental expense relating to operating leases, which is a reasonable approximation of the interest factor.
The ratio coverage was less than 1:1. The registrant must generate additional earnings of $49 million to achieve a coverage ratio of 1:1.
Exhibit 21.1
Exelon Corporation (50% and Greater)
12/31/2016
Name
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
AgriWind LLC
AgriWind Project L.L.C.
Albany Green Energy, LLC
American Energy Corporation
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
Annova LNG, LLC, Series A Units
Annova LNG, LLC, Series B Units
Annova LNG, LLC, Series C Units
Annova LNG, LLC, Series Z Units
APS Constellation, LLC
ATE Investment, Inc.
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 Capital Trust II
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
Braidwood 1 NQF, LLC
Braidwood 2 NQF, LLC
Butter Creek Power, LLC
Byron 1 NQF, LLC
Byron 2 NQF, LLC
California PV Energy 2, LLC
California PV Energy, LLC
Calvert Cliffs Nuclear Power Plant, LLC
Cassia Gulch Wind Park LLC
Cassia Wind Farm LLC
CD Panther I, Inc.
Jurisdiction
Delaware
Delaware
Delaware
Delaware
Delaware
Pennsylvania
Illinois
Delaware
Georgia
Delaware
Delaware
Delaware
Delaware
Delaware
Delaware
Delaware
Delaware
Delaware
Delaware
Delaware
Delaware
Delaware
New Jersey
Delaware
New Jersey
New Jersey
Delaware
Delaware
Maryland
Minnesota
Delaware
Delaware
Idaho
Delaware
Delaware
Delaware
Oregon
Minnesota
Minnesota
Delaware
Delaware
Delaware
Delaware
Delaware
Nevada
Nevada
Oregon
Nevada
Nevada
Delaware
Delaware
Maryland
Idaho
Idaho
Maryland
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 CHC, LLC
CEU CoLa, LLC
CEU Development, 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 Offshore I, LLC
CEU Ohio Shale, LLC
CEU Paradigm, LLC
CEU Pinedale, LLC
CEU Plymouth, LLC
CEU Simplicity, LLC
CEU Trenton, LLC
CEU W&D, LLC
Chesapeake HVAC, Inc.
Chester Transmission Construction Canada, Inc.
Christoffer Wind Energy I LLC
Christoffer Wind Energy II LLC
Christoffer Wind Energy III LLC
Christoffer Wind Energy IV LLC
CII Solarpower I, Inc.
Cisco Wind Energy LLC
Clinton Battery Utility, LLC
Clinton NQF, 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 I Power, LLC
Colorado Bend II Power, LLC
Colorado Bend Services, LLC
ComEd Financing III
Commonwealth Edison Company
Commonwealth Edison Company of Indiana, Inc.
Compass Energy Gas Services, LLC
Compass Energy Services, Inc.
Conectiv Communications, Inc.
Conectiv Energy Supply, Inc.
Conectiv North East, LLC
Conectiv Properties and Investments, Inc.
Conectiv Services, Inc.
Conectiv Solutions LLC
Conectiv Thermal Systems, Inc.
Delaware
Delaware
Maryland
Maryland
Maryland
Delaware
Delaware
Delaware
Delaware
Delaware
Delaware
Delaware
Delaware
Delaware
Delaware
Delaware
Delaware
Delaware
Delaware
Delaware
Delaware
Delaware
Delaware
Delaware
Delaware
Delaware
Delaware
Delaware
Canada
Minnesota
Minnesota
Minnesota
Minnesota
Maryland
Minnesota
Delaware
Nevada
Pennsylvania
Kentucky
Delaware
Delaware
Delaware
Delaware
Delaware
Delaware
Delaware
Delaware
Illinois
Indiana
Virginia
Virginia
Delaware
Delaware
Delaware
Delaware
Delaware
Delaware
Delaware
Conectiv, 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 Partners Holdings, LLC
Constellation Energy Power Choice, LLC
Constellation Energy Projects & Services Group Advisors, LLC
Constellation Energy Projects and Services Canada, Inc.
Constellation Energy Resources, LLC
Constellation Energy Services—Natural Gas, LLC
Constellation Energy Services of New York, Inc.
Constellation Energy Services, Inc.
Constellation Energy Upstream Holdings, LLC
Constellation ESCO, LLC
Constellation Holdings, 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 Maryland II, LLC
Constellation Solar Maryland MC, LLC
Constellation Solar Maryland, LLC
Constellation Solar Massachusetts, 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, 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
Delaware
Delaware
Delaware
Ontario
Delaware
Delaware
Maryland
Delaware
Delaware
Delaware
Alberta
Delaware
Delaware
New York
Wisconsin
Delaware
Delaware
Maryland
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
Maryland
Maryland
Missouri
Maryland
Minnesota
Missouri
Criterion Power Partners, LLC
Delaware Operating Services Company, LLC
Delmarva Power & Light Company
Denver Airport Solar, LLC
Distributed Generation Partners, LLC
Dresden 1 NQF, LLC
Dresden 2 NQF, LLC
Dresden 3 NQF, LLC
Eastern Landfill Gas, LLC
Energy Performance Services, Inc.
ETT Canada, Inc.
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 Framingham, LLC
Exelon Fulton, LLC
Exelon Generation Acquisitions, LLC
Exelon Generation Company, LLC
Exelon Generation Consolidation, LLC
Exelon Generation Finance Company, LLC
Exelon Generation International, LLC
Exelon Generation Limited
Exelon Mechanical, LLC
Exelon Microgrid, LLC
Exelon New Boston, LLC
Exelon New England Holdings, LLC
Exelon Nuclear Partners International S.a r.l.
Exelon Nuclear Partners, LLC
Exelon Nuclear Security, LLC
Exelon PowerLabs, LLC
Exelon Solar Chicago LLC
Exelon Transmission Company, 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
Ex-FM, Inc.
Ex-FME, Inc.
ExGen Energy, S. de R.L. de C.V.
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
Delaware
Delaware
Delaware & Virginia
Delaware
Delaware
Nevada
Nevada
Nevada
Delaware
Pennsylvania
New Brunswick
Minnesota
Delaware
Delaware
Delaware
Delaware
Pennsylvania
Delaware
Delaware
Delaware
Pennsylvania
Nevada
Delaware
Pennsylvania
United Kingdom
Delaware
Delaware
Delaware
Delaware
Luxembourg
Delaware
Delaware
Pennsylvania
Delaware
Delaware
Delaware
Delaware
Texas
Texas
Texas
Texas
Texas
Texas
Texas
Texas
Texas
Texas
Texas
Canada
Delaware
Delaware
New York
Delaware
Mexico
Delaware
Delaware
Delaware
Delaware
Delaware
Delaware
ExGen Renewables IV, LLC
ExGen Renewables Partners, LLC
ExGen Texas II Power Holdings, LLC
ExGen Texas II Power, LLC
ExGen Texas Power Holdings, LLC
ExGen Texas Power Services, LLC
ExGen Texas Power, LLC
ExGen Ventures International Holdings II Limited
ExGen Ventures International Holdings Limited
ExTel Corporation, LLC
F & M Holdings Company, L.L.C.
Fair Wind Power Partners, LLC
Fauquier Landfill Gas, L.L.C.
Four Corners Windfarm, LLC
Four Mile Canyon Windfarm, LLC
Fourmile Wind Energy, LLC
Friendly Skies, Inc.
Grande Prairie Generation, Inc.
Greensburg Wind Farm, LLC
Handley Power, 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
K & D Energy LLC
KC Energy LLC
KSS Turbines LLC
La Salle 1 NQF, LLC
La Salle 2 NQF, LLC
Lake Houston Power, LLC
LaPorte Power, LLC
Las Vegas District Energy, LLC
Limerick 1 NQF, LLC
Limerick 2 NQF, LLC
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
Millennium Account Services, LLC
Minergy LLC
Mohave Sunrise Solar I, LLC
Mountain Creek Power, LLC
Mountain Top Wind Power, LLC
Nine Mile Point Nuclear Station, LLC
North Shore District Energy, LLC
Northwind Thermal Technologies Canada Inc.
Oregon Trail Windfarm, LLC
Outback Solar, LLC
Oyster Creek NQF, LLC
Delaware
Delaware
Delaware
Delaware
Delaware
Delaware
Delaware
United Kingdom
United Kingdom
Delaware
Delaware
Delaware
Delaware
Oregon
Oregon
Maryland
Virgin Islands, U.S.
Alberta
Delaware
Delaware
Maryland
Delaware
Michigan
Idaho
Texas
Delaware
Idaho
Minnesota
Minnesota
Minnesota
Nevada
Nevada
Delaware
Delaware
Delaware
Nevada
Nevada
Missouri
Minnesota
Minnesota
Minnesota
Minnesota
Minnesota
Minnesota
Delaware
Delaware
Delaware
Delaware
Wisconsin
Arizona
Delaware
Maryland
Delaware
Delaware
New Brunswick
Oregon
Oregon
Nevada
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 Energy Corporation
PCI Engine Trading Ltd.
PCI Ever, Inc.
Peach Bottom 1 NQF, LLC
Peach Bottom 2 NQF, LLC
Peach Bottom 3 NQF, LLC
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 Services, Inc.
Pepco Energy Solutions LLC
Pepco Government Services LLC
Pepco Holdings LLC
PH Holdco LLC
PHI Service Company
Pinedale Energy, LLC
POM Holdings, Inc.
Potomac Capital Investment Corporation
Potomac Delaware Leasing Corporation
Potomac Electric Power Company
Potomac Leasing Associates, L.P.
Potomac Power Resources, LLC
Prairie Wind Power LLC
Quad Cities 1 NQF, LLC
Quad Cities 2 NQF, LLC
R.E. Ginna Nuclear Power Plant, LLC
Ramp Investments, L.L.C.
Renewable Power Generation Holdings, LLC
Renewable Power Generation, LLC
Residential Solar Holding, LLC
Residential Solar II, LLC
RF HoldCo LLC
RITELine Illinois, LLC
RITELine Indiana, LLC
RITELine Transmission Development, LLC
Rolling Hills Landfill Gas, LLC
RSB BondCo LLC
Sacramento PV Energy, LLC
Salem 1 NQF, LLC
Salem 2 NQF, LLC
Sand Ranch Windfarm, LLC
Scherer Holdings 1, LLC
Scherer Holdings 2, LLC
Scherer Holdings 3, LLC
Sendero Wind Energy, LLC
Severn Construction Services, L.L.C.
Oregon
Delaware
Delaware
Delaware
Nevada
Delaware
Delaware
Bermuda
Delaware
Nevada
Nevada
Nevada
Pennsylvania
Delaware
Delaware
Delaware
Delaware
Pennsylvania
Delaware
California
Delaware
Delaware
Delaware
Delaware
Delaware
Delaware
Delaware
Delaware
Colorado
Delaware
Delaware
Delaware
District of Columbia & Virginia
Delaware
Delaware
Minnesota
Nevada
Nevada
Maryland
Delaware
Delaware
Delaware
Delaware
Delaware
Delaware
Illinois
Indiana
Delaware
Delaware
Delaware
Delaware
Nevada
Nevada
Oregon
Delaware
Delaware
Delaware
Delaware
Delaware
Shooting Star Wind Project, LLC
Sky Valley, LLC
SolGen Holding, LLC
SolGen, LLC
Sugar Beet Wind, LLC
Sunnyside Cogeneration Associates
Sunnyside II, Inc.
Sunnyside II, L.P.
Sunnyside III, Inc.
Sunnyside Properties, LLC
Threemile Canyon Wind I, LLC
Titan STC, LLC
TMI NQF, LLC
Tuana Springs Energy, LLC
UII, LLC
Vineland Cogeneration Limited Partnership
Vineland General, Inc.
Vineland Ltd., Inc.
Volta Energy Technologies, LLC
W&D Gas Partners, LLC
W.A. Chester Corporation
W.A. Chester, L.L.C.
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
Wibaux Wind, LLC
Wildcat Finance, LLC
Wildcat Wind LLC
Wind Capital Holdings, LLC
Wolf Hollow I Power, LLC
Wolf Hollow II Power, LLC
Wolf Hollow Services, LLC
Zion 1 NQF, LLC
Zion 2 NQF, LLC
Delaware
Delaware
Delaware
Delaware
Delaware
Utah
Delaware
Delaware
Delaware
Utah
Oregon
Delaware
Nevada
Idaho
Illinois
Delaware
Delaware
Delaware
Delaware
Delaware
Delaware
Delaware
Oregon
Delaware
Delaware
Oregon
Delaware
Delaware
Delaware
Delaware
Delaware
New Mexico
Missouri
Delaware
Delaware
Delaware
Nevada
Nevada
Exhibit 21.2
Exelon Generation Company, LLC
(50% and greater)
12/31/2016
Name
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
AgriWind LLC
AgriWind Project L.L.C.
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
Annova LNG, LLC, Series A Units
Annova LNG, LLC, Series B Units
Annova LNG, LLC, Series C Units
Annova LNG, LLC, Series Z Units
APS Constellation, LLC
ATE Investment, Inc.
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
Braidwood 1 NQF, LLC
Braidwood 2 NQF, LLC
Butter Creek Power, LLC
Byron 1 NQF, LLC
Byron 2 NQF, LLC
California PV Energy 2, 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
Jurisdiction
Delaware
Delaware
Delaware
Delaware
Delaware
Pennsylvania
Illinois
Delaware
Georgia
Delaware
Delaware
Delaware
Delaware
Delaware
Delaware
Delaware
Delaware
Delaware
Delaware
Delaware
New Jersey
Delaware
Minnesota
Delaware
Delaware
Idaho
Delaware
Delaware
Oregon
Minnesota
Minnesota
Delaware
Delaware
Delaware
Delaware
Delaware
Nevada
Nevada
Oregon
Nevada
Nevada
Delaware
Delaware
Maryland
Idaho
Idaho
Maryland
Delaware
Delaware
Maryland
Maryland
Maryland
Delaware
Delaware
CER Generation, LLC
CEU Arkoma West, LLC
CEU CHC, LLC
CEU CoLa, LLC
CEU Development, 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 Offshore I, LLC
CEU Ohio Shale, LLC
CEU Paradigm, LLC
CEU Pinedale, LLC
CEU Plymouth, LLC
CEU Simplicity, LLC
CEU Trenton, LLC
CEU W&D, LLC
Chesapeake HVAC, Inc.
Chester Transmission Construction Canada, Inc.
Christoffer Wind Energy I LLC
Christoffer Wind Energy II LLC
Christoffer Wind Energy III LLC
Christoffer Wind Energy IV LLC
CII Solarpower I, Inc.
Cisco Wind Energy LLC
Clinton Battery Utility, LLC
Clinton NQF, 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 I Power, LLC
Colorado Bend II Power, LLC
Colorado Bend Services, LLC
Compass Energy Gas Services, LLC
Compass Energy Services, Inc.
Conectiv Energy Supply, Inc.
Conectiv North East, LLC
Conectiv Thermal Systems, Inc.
Conectiv, 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 Partners Holdings, LLC
Constellation Energy Power Choice, LLC
Constellation Energy Projects & Services Group Advisors, LLC
Constellation Energy Projects and Services Canada, Inc.
Constellation Energy Resources, LLC
Delaware
Delaware
Delaware
Delaware
Delaware
Delaware
Delaware
Delaware
Delaware
Delaware
Delaware
Delaware
Delaware
Delaware
Delaware
Delaware
Delaware
Delaware
Delaware
Delaware
Delaware
Canada
Minnesota
Minnesota
Minnesota
Minnesota
Maryland
Minnesota
Delaware
Nevada
Pennsylvania
Kentucky
Delaware
Delaware
Delaware
Delaware
Delaware
Delaware
Delaware
Virginia
Virginia
Delaware
Delaware
Delaware
Delaware
Delaware
Delaware
Ontario
Delaware
Delaware
Maryland
Delaware
Delaware
Delaware
Alberta
Delaware
Constellation Energy Services—Natural Gas, LLC
Constellation Energy Services of New York, Inc.
Constellation Energy Services, Inc.
Constellation Energy Upstream Holdings, LLC
Constellation ESCO, LLC
Constellation Holdings, 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 Maryland II, LLC
Constellation Solar Maryland MC, LLC
Constellation Solar Maryland, LLC
Constellation Solar Massachusetts, 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, 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
Delaware Operating Services Company, LLC
Denver Airport Solar, LLC
Distributed Generation Partners, LLC
Dresden 1 NQF, LLC
Dresden 2 NQF, LLC
Dresden 3 NQF, LLC
Eastern Landfill Gas, LLC
Energy Performance Services, Inc.
Ewington Energy Systems LLC
Exelon AVSR Holding, LLC
Exelon AVSR, LLC
Exelon Framingham, LLC
Exelon Fulton, LLC
Exelon Generation Acquisitions, LLC
Exelon Generation Company, LLC
Delaware
New York
Wisconsin
Delaware
Delaware
Maryland
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
Maryland
Maryland
Missouri
Maryland
Minnesota
Missouri
Delaware
Delaware
Delaware
Delaware
Nevada
Nevada
Nevada
Delaware
Pennsylvania
Minnesota
Delaware
Delaware
Delaware
Delaware
Delaware
Pennsylvania
Exelon Generation Consolidation, LLC
Exelon Generation Finance Company, LLC
Exelon Generation International, LLC
Exelon Generation Limited
Exelon New Boston, LLC
Exelon New England Holdings, LLC
Exelon Nuclear Partners International S.a r.l.
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
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 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 Holdings, LLC
ExGen Texas Power Services, LLC
ExGen Texas Power, LLC
ExGen Ventures International Holdings II Limited
ExGen Ventures International Holdings Limited
Fair Wind Power Partners, LLC
Fauquier Landfill Gas, L.L.C.
Four Corners Windfarm, LLC
Four Mile Canyon Windfarm, LLC
Fourmile Wind Energy, LLC
Grande Prairie Generation, Inc.
Greensburg Wind Farm, LLC
Handley Power, 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
Nevada
Delaware
Pennsylvania
United Kingdom
Delaware
Delaware
Luxembourg
Delaware
Delaware
Pennsylvania
Delaware
Delaware
Delaware
Texas
Texas
Texas
Texas
Texas
Texas
Texas
Texas
Texas
Texas
Texas
Canada
Delaware
Delaware
Mexico
Delaware
Delaware
Delaware
Delaware
Delaware
Delaware
Delaware
Delaware
Delaware
Delaware
Delaware
Delaware
Delaware
United Kingdom
United Kingdom
Delaware
Delaware
Oregon
Oregon
Maryland
Alberta
Delaware
Delaware
Maryland
Delaware
Michigan
Idaho
Texas
Delaware
Idaho
K & D Energy LLC
KC Energy LLC
KSS Turbines LLC
La Salle 1 NQF, LLC
La Salle 2 NQF, LLC
Lake Houston Power, LLC
LaPorte Power, LLC
Las Vegas District Energy, LLC
Limerick 1 NQF, LLC
Limerick 2 NQF, LLC
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 Creek Power, LLC
Mountain Top Wind Power, LLC
Nine Mile Point Nuclear Station, LLC
North Shore District Energy, LLC
Oregon Trail Windfarm, LLC
Outback Solar, LLC
Oyster Creek NQF, LLC
Pacific Canyon Windfarm, LLC
Panther Creek Holdings, Inc.
Panther Creek Partners
Peach Bottom 1 NQF, LLC
Peach Bottom 2 NQF, LLC
Peach Bottom 3 NQF, LLC
Pegasus Power Company, Inc.
Pepco Building Services Inc.
Pepco Energy Cogeneration LLC
Pepco Energy Services, Inc.
Pepco Energy Solutions LLC
Pepco Government Services LLC
Pinedale Energy, LLC
Potomac Capital Investment Corporation
Potomac Power Resources, LLC
Prairie Wind Power LLC
Quad Cities 1 NQF, LLC
Quad Cities 2 NQF, LLC
R.E. Ginna Nuclear Power Plant, LLC
Renewable Power Generation Holdings, LLC
Renewable Power Generation, LLC
Residential Solar Holding, LLC
Residential Solar II, LLC
Rolling Hills Landfill Gas, LLC
Sacramento PV Energy, LLC
Salem 1 NQF, LLC
Salem 2 NQF, LLC
Sand Ranch Windfarm, LLC
Sendero Wind Energy, LLC
Severn Construction Services, L.L.C.
Shooting Star Wind Project, LLC
Minnesota
Minnesota
Minnesota
Nevada
Nevada
Delaware
Delaware
Delaware
Nevada
Nevada
Missouri
Minnesota
Minnesota
Minnesota
Minnesota
Minnesota
Minnesota
Delaware
Delaware
Delaware
Wisconsin
Arizona
Delaware
Maryland
Delaware
Delaware
Oregon
Oregon
Nevada
Oregon
Delaware
Delaware
Nevada
Nevada
Nevada
California
Delaware
Delaware
Delaware
Delaware
Delaware
Colorado
Delaware
Delaware
Minnesota
Nevada
Nevada
Maryland
Delaware
Delaware
Delaware
Delaware
Delaware
Delaware
Nevada
Nevada
Oregon
Delaware
Delaware
Delaware
Sky Valley, LLC
SolGen Holding, LLC
SolGen, LLC
Sugar Beet Wind, LLC
Sunnyside Cogeneration Associates
Sunnyside II, Inc.
Sunnyside II, L.P.
Sunnyside III, Inc.
Sunnyside Properties, LLC
Threemile Canyon Wind I, LLC
Titan STC, LLC
TMI NQF, LLC
Tuana Springs Energy, LLC
Vineland Cogeneration Limited Partnership
Vineland General, Inc.
Vineland Ltd., Inc.
Volta Energy Technologies, LLC
W&D Gas Partners, LLC
W.A. Chester Corporation
W.A. Chester, L.L.C.
Wagon Trail, LLC
Ward Butte Windfarm, LLC
Water & Energy Savings Company, LLC
Whitetail Wind Energy, LLC
Wibaux Wind, LLC
Wildcat Finance, LLC
Wildcat Wind LLC
Wind Capital Holdings, LLC
Wolf Hollow I Power, LLC
Wolf Hollow II Power, LLC
Wolf Hollow Services, LLC
Zion 1 NQF, LLC
Zion 2 NQF, LLC
Delaware
Delaware
Delaware
Delaware
Utah
Delaware
Delaware
Delaware
Utah
Oregon
Delaware
Nevada
Idaho
Delaware
Delaware
Delaware
Delaware
Delaware
Delaware
Delaware
Oregon
Oregon
Delaware
Delaware
Delaware
Delaware
New Mexico
Missouri
Delaware
Delaware
Delaware
Nevada
Nevada
Commonwealth Edison Company
12/31/2016
Subsidiary
ComEd Financing III
Commonwealth Edison Company of Indiana, Inc.
RITELine Illinois, LLC
Jurisdiction
Delaware
Indiana
Illinois
Exhibit 21.3
PECO Energy Company
12/31/2016
Subsidiary
ATNP Finance Company
ExTel Corporation, LLC
PEC Financial Services, LLC
PECO Energy Capital Corp.
PECO Energy Capital, L.P.
PECO Energy Capital Trust III
PECO Energy Capital Trust IV
PECO Wireless, LLC
Jurisdiction
Delaware
Delaware
Pennsylvania
Delaware
Delaware
Delaware
Delaware
Delaware
Exhibit 21.4
Baltimore Gas and Electric Company
12/31/2016
Subsidiary
BGE Capital Trust II
RSB BondCo LLC
Jurisdiction
Delaware
Delaware
Exhibit 21.5
Pepco Holdings LLC
12/31/2016
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.
Jurisdiction
New Jersey
Delaware
Delaware & Virginia
Delaware
Delaware
District of Columbia & Virginia
Delaware
Exhibit 21.6
Potomac Electric Power Company
12/31/2016
Subsidiary
POM Holdings, Inc.
Jurisdiction
Delaware
Exhibit 21.7
Delmarva Power & Light Company
12/31/2016
Subsidiary
N/A
Jurisdiction
Exhibit 21.8
Atlantic City Electric Company
12/31/2016
Subsidiary
Atlantic City Electric Transition Funding LLC
Jurisdiction
Delaware
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), Form S-4 (No. 333-209209) and on Form S-8
(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 13, 2017 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 13, 2017
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 13, 2017 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 13, 2017
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 13, 2017 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 13, 2017
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 13, 2017 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 13, 2017
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 13, 2017 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 13, 2017
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 13, 2017, relating to the financial statements and financial statement schedule, which appears in this Form 10-K.
Exhibit 23.6
/s/ PricewaterhouseCoopers LLP
Washington, D.C.
February 13, 2017
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 13, 2017, relating to the financial statements and financial statement schedule, which appears in this Form 10-K.
Exhibit 23.7
/s/ PricewaterhouseCoopers LLP
Washington, D.C.
February 13, 2017
POWER OF ATTORNEY
Exhibit 24.1
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 2016 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/ ANTHONY K. ANDERSON
Anthony K. Anderson
DATE: January 31, 2017
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 2016 of Exelon Corporation, together
with any amendments thereto, to be filed with the Securities and Exchange Commission, and generally to do and perform all things necessary to be done in the
premises as fully and effectually in all respects as I could do if personally present.
/s/ ANN C. BERZIN
Ann C. Berzin
DATE: January 31, 2017
POWER OF ATTORNEY
Exhibit 24.3
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 2016 of Exelon Corporation, together with any amendments thereto, to be
filed with the Securities and Exchange Commission, and generally to do and perform all things necessary to be done in the premises as fully and effectually in all
respects as I could do if personally present.
/s/ CHRISTOPHER M. CRANE
Christopher M. Crane
DATE: January 31, 2017
POWER OF ATTORNEY
Exhibit 24.4
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 2016 of Exelon Corporation,
together with any amendments thereto, to be filed with the Securities and Exchange Commission, and generally to do and perform all things necessary to be done in
the premises as fully and effectually in all respects as I could do if personally present.
/s/ YVES C. DE BALMANN
Yves C. de Balmann
DATE: January 31, 2017
POWER OF ATTORNEY
Exhibit 24.5
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 2016 of Exelon Corporation,
together with any amendments thereto, to be filed with the Securities and Exchange Commission, and generally to do and perform all things necessary to be done in
the premises as fully and effectually in all respects as I could do if personally present.
/s/ NICHOLAS DEBENEDICTIS
Nicholas DeBenedictis
DATE: January 31, 2017
POWER OF ATTORNEY
Exhibit 24.6
KNOW ALL MEN BY THESE PRESENTS that I, Nancy L. Gioia , 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 2016 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/ NANCY L. GIOIA
Nancy L. Gioia
DATE: January 31, 2017
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 2016 of Exelon Corporation, together
with any amendments thereto, to be filed with the Securities and Exchange Commission, and generally to do and perform all things necessary to be done in the
premises as fully and effectually in all respects as I could do if personally present.
/s/ LINDA P. JOJO
Linda P. Jojo
DATE: January 31, 2017
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 2016 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 JOSKOW
Paul Joskow
DATE: January 31, 2017
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 2016 of Exelon Corporation,
together with any amendments thereto, to be filed with the Securities and Exchange Commission, and generally to do and perform all things necessary to be done in
the premises as fully and effectually in all respects as I could do if personally present.
/s/ ROBERT J. LAWLESS
Robert J. Lawless
DATE: January 31, 2017
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 2016 of Exelon Corporation,
together with any amendments thereto, to be filed with the Securities and Exchange Commission, and generally to do and perform all things necessary to be done in
the premises as fully and effectually in all respects as I could do if personally present.
/s/ RICHARD W. MIES
Richard W. Mies
DATE: January 31, 2017
POWER OF ATTORNEY
Exhibit 24.12
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 2016 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: January 31, 2017
POWER OF ATTORNEY
Exhibit 24.13
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 2016 of Exelon Corporation,
together with any amendments thereto, to be filed with the Securities and Exchange Commission, and generally to do and perform all things necessary to be done in
the premises as fully and effectually in all respects as I could do if personally present.
/s/ MAYO A. SHATTUCK III
Mayo A. Shattuck III
DATE: January 31, 2017
POWER OF ATTORNEY
Exhibit 24.14
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 2016 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/ STEPHEN D. STEINOUR
Stephen D. Steinour
DATE: January 31, 2017
POWER OF ATTORNEY
Exhibit 24.15
KNOW ALL MEN BY THESE PRESENTS that I, James W. Compton , do hereby appoint Anne R. Pramaggiore 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 2016 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 2, 2017
POWER OF ATTORNEY
Exhibit 24.16
KNOW ALL MEN BY THESE PRESENTS that I, Christopher M. Crane , do hereby appoint Anne R. Pramaggiore 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 2016 of Commonwealth
Edison Company, together with any amendments thereto, to be filed with the Securities and Exchange Commission, and generally to do and perform all things
necessary to be done in the premises as fully and effectually in all respects as I could do if personally present.
/s/ CHRISTOPHER M. CRANE
Christopher M. Crane
DATE: January 31, 2017
POWER OF ATTORNEY
Exhibit 24.17
KNOW ALL MEN BY THESE PRESENTS that I, A. Steven Crown , do hereby appoint Anne R. Pramaggiore 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 2016 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 6, 2017
POWER OF ATTORNEY
Exhibit 24.18
KNOW ALL MEN BY THESE PRESENTS that I, Nicholas DeBenedictis , do hereby appoint Anne R. Pramaggiore 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 2016 of Commonwealth
Edison Company, together with any amendments thereto, to be filed with the Securities and Exchange Commission, and generally to do and perform all things
necessary to be done in the premises as fully and effectually in all respects as I could do if personally present.
/s/ NICHOLAS DEBENEDICTIS
Nicholas DeBenedictis
DATE: January 31, 2017
POWER OF ATTORNEY
Exhibit 24.19
KNOW ALL MEN BY THESE PRESENTS that I, Peter V. Fazio, Jr. , do hereby appoint Anne R. Pramaggiore 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 2016 of Commonwealth
Edison Company, together with any amendments thereto, to be filed with the Securities and Exchange Commission, and generally to do and perform all things
necessary to be done in the premises as fully and effectually in all respects as I could do if personally present.
/s/ PETER V. FAZIO, JR.
Peter V. Fazio, Jr.
DATE: January 31, 2017
POWER OF ATTORNEY
Exhibit 24.20
KNOW ALL MEN BY THESE PRESENTS that I, Michael H. Moskow , do hereby appoint Anne R. Pramaggiore 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 2016 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 4, 2017
POWER OF ATTORNEY
Exhibit 24.21
KNOW ALL MEN BY THESE PRESENTS that I, Denis P. O’Brien , do hereby appoint Anne R. Pramaggiore 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 2016 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/ DENIS P. O’BRIEN
Denis P. O’Brien
DATE: January 31, 2017
POWER OF ATTORNEY
Exhibit 24.22
KNOW ALL MEN BY THESE PRESENTS that I, Anne R. Pramaggiore , 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 2016 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, 2017
POWER OF ATTORNEY
Exhibit 24.23
KNOW ALL MEN BY THESE PRESENTS that I, Jesse H. Ruiz , do hereby appoint Anne R. Pramaggiore 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 2016 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/ JESSE H. RUIZ
Jesse H. Ruiz
DATE: February 2, 2017
POWER OF ATTORNEY
Exhibit 24.25
KNOW ALL MEN BY THESE PRESENTS that I, Craig L. Adams , 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 2016 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/ CRAIG L. ADAMS
Craig L. Adams
DATE: January 31, 2017
POWER OF ATTORNEY
Exhibit 24.26
KNOW ALL MEN BY THESE PRESENTS that I, Christopher M. Crane , do hereby appoint Craig L. Adams 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 2016 of PECO Energy
Company, together with any amendments thereto, to be filed with the Securities and Exchange Commission, and generally to do and perform all things necessary to
be done in the premises as fully and effectually in all respects as I could do if personally present.
/s/ CHRISTOPHER M. CRANE
Christopher M. Crane
DATE: January 31, 2017
POWER OF ATTORNEY
Exhibit 24.27
KNOW ALL MEN BY THESE PRESENTS that I, M. Walter D’Alessio , do hereby appoint Craig L. Adams 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 2016 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 6, 2017
POWER OF ATTORNEY
Exhibit 24.28
KNOW ALL MEN BY THESE PRESENTS that I, Nicholas DeBenedictis , do hereby appoint Craig L. Adams 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 2016 of PECO Energy
Company, together with any amendments thereto, to be filed with the Securities and Exchange Commission, and generally to do and perform all things necessary to
be done in the premises as fully and effectually in all respects as I could do if personally present.
/s/ NICHOLAS DEBENEDICTIS
Nicholas DeBenedictis
DATE: January 31, 2017
POWER OF ATTORNEY
Exhibit 24.29
KNOW ALL MEN BY THESE PRESENTS that I, Nelson A. Diaz , do hereby appoint Craig L. Adams 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 2016 of PECO Energy Company, together
with any amendments thereto, to be filed with the Securities and Exchange Commission, and generally to do and perform all things necessary to be done in the
premises as fully and effectually in all respects as I could do if personally present.
/s/ NELSON A. DIAZ
Nelson A. Diaz
DATE: February 6, 2017
POWER OF ATTORNEY
Exhibit 24.30
KNOW ALL MEN BY THESE PRESENTS that I, Rosemarie B. Greco , do hereby appoint Craig L. Adams 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 2016 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 10, 2017
POWER OF ATTORNEY
Exhibit 24.31
KNOW ALL MEN BY THESE PRESENTS that I, Charisse R. Lillie , do hereby appoint Craig L. Adams 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 2016 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 8, 2017
POWER OF ATTORNEY
Exhibit 24.32
KNOW ALL MEN BY THESE PRESENTS that I, Denis P. O’Brien , do hereby appoint Craig L. Adams 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 2016 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/ DENIS P. O’BRIEN
Denis P. O’Brien
DATE: January 31, 2017
POWER OF ATTORNEY
Exhibit 24.33
KNOW ALL MEN BY THESE PRESENTS that I, Ronald Rubin , do hereby appoint Craig L. Adams 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 2016 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/ RONALD RUBIN
Ronald Rubin
DATE: February 6, 2017
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 Daniel P. Gahagan, 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 2016 of Baltimore Gas & Electric
Company, together with any amendments thereto, to be filed with the Securities and Exchange Commission, and generally to do and perform all things necessary to
be done in the premises as fully and effectually in all respects as I could do if personally present.
/s/ ANN C. BERZIN
Ann C. Berzin
DATE: January 31, 2017
POWER OF ATTORNEY
Exhibit 24.35
KNOW ALL MEN BY THESE PRESENTS that I, Calvin G. Butler, Jr., do hereby appoint Daniel P. Gahagan 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 2016 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 4, 2017
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 Daniel P. Gahagan, 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 2016 of Baltimore Gas &
Electric Company, together with any amendments thereto, to be filed with the Securities and Exchange Commission, and generally to do and perform all things
necessary to be done in the premises as fully and effectually in all respects as I could do if personally present.
/s/ CHRISTOPHER M. CRANE
Christopher M. Crane
DATE: January 31, 2017
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 Daniel P. Gahagan, 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 2016 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 3, 2017
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 Daniel P. Gahagan, 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 2016 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 9, 2017
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 Daniel P. Gahagan, 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 2016 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 8, 2017
POWER OF ATTORNEY
Exhibit 24.40
KNOW ALL MEN BY THESE PRESENTS that I, Denis P. O’Brien , do hereby appoint Calvin G. Butler, Jr. and Daniel P. Gahagan, 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 2016 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/ DENIS P. O’BRIEN
Denis P. O’Brien
DATE: January 31, 2017
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 Daniel P. Gahagan, 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 2016 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 9, 2017
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 Daniel P. Gahagan, 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 2016 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 10, 2017
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 2016 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 2, 2017
POWER OF ATTORNEY
Exhibit 24.44
KNOW ALL MEN BY THESE PRESENTS that I, Linda 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 2016 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 Cropp
Linda Cropp
Date: February 8, 2017
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 2016 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 3, 2017
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 2016 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 6, 2017
POWER OF ATTORNEY
Exhibit 24.47
KNOW ALL MEN BY THESE PRESENTS that I, Debra 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 2016 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 DiLorenzo
Debra DiLorenzo
Date: February 6, 2017
POWER OF ATTORNEY
Exhibit 24.48
KNOW ALL MEN BY THESE PRESENTS that I, Denis P. O’Brien , 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 2016 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/ DENIS P. O’BRIEN
Denis P. O’Brien
Date: February 2, 2017
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 2016 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 8, 2017
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 2016 of Potomac Electric Power
Company, together with any amendments thereto, to be filed with the Securities and Exchange Commission, and generally to do and perform all things necessary to
be done in the premises as fully and effectually in all respects as I could do if personally present.
/s/ J. TYLER ANTHONY
J. Tyler Anthony
DATE: January 30, 2017
POWER OF ATTORNEY
Exhibit 24.51
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 2016 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 2, 2017
POWER OF ATTORNEY
Exhibit 24.52
KNOW ALL MEN BY THESE PRESENTS that I, Donna J. Kinzel , 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 2016 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 / DONNA J. KINZEL
Donna J. Kinzel
DATE: February 9, 2017
POWER OF ATTORNEY
Exhibit 24.53
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 2016 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 3, 2017
POWER OF ATTORNEY
Exhibit 24.54
KNOW ALL MEN BY THESE PRESENTS that I, Denis P. O’Brien , 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 2016 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/ DENIS P. O’BRIEN
Denis P. O’Brien
DATE: February 2, 2017
POWER OF ATTORNEY
Exhibit 24.55
KNOW ALL MEN BY THESE PRESENTS that I, Kenneth J. Parker , 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 2016 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/ KENNETH J. PARKER
Kenneth J. Parker
DATE: February 9, 2017
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 2016 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 8, 2017
POWER OF ATTORNEY
Exhibit 24.57
KNOW ALL MEN BY THESE PRESENTS that I, Denis P. O’Brien , 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 2016 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/ DENIS P. O’BRIEN
Denis P. O’Brien
DATE: February 2, 2017
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 2016 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 8, 2017
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.
2.
3.
4.
I have reviewed this annual report on Form 10-K of Exelon Corporation;
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;
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;
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)
(b)
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
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.
/ S / C HRISTOPHER M. C RANE
President and Chief Executive Officer
(Principal Executive Officer)
Date: February 13, 2017
Exhibit 31-2
CERTIFICATION PURSUANT TO RULE 13a-14(a) AND 15d-14(a) OF THE SECURITIES
AND EXCHANGE ACT OF 1934
I, Jonathan W. Thayer, certify that:
1.
2.
3.
4.
I have reviewed this annual report on Form 10-K of Exelon Corporation;
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;
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;
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)
(b)
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
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.
/ S / J ONATHAN W. T HAYER
Senior Executive Vice President and Chief
Financial Officer
(Principal Financial Officer)
Date: February 13, 2017
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.
2.
3.
4.
I have reviewed this annual report on Form 10-K of Exelon Generation Company, LLC;
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;
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;
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)
(b)
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
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.
/ S / K ENNETH W. C ORNEW
President and Chief Executive Officer
(Principal Executive Officer)
Date: February 13, 2017
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.
2.
3.
4.
I have reviewed this annual report on Form 10-K of Exelon Generation Company, LLC;
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;
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;
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)
(b)
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
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.
/ S / B RYAN P. W RIGHT
Senior Vice President and Chief Financial Officer
(Principal Financial Officer)
Date: February 13, 2017
CERTIFICATION PURSUANT TO RULE 13a-14(a) AND 15d-14(a) OF THE
SECURITIES AND EXCHANGE ACT OF 1934
Exhibit 31-5
I, Anne R. Pramaggiore, certify that:
1.
2.
3.
4.
I have reviewed this annual report on Form 10-K of Commonwealth Edison Company;
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;
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;
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)
(b)
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
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.
/ S / A NNE R. P RAMAGGIORE
President and Chief Executive Officer
(Principal Executive Officer)
Date: February 13, 2017
CERTIFICATION PURSUANT TO RULE 13a-14(a) AND 15d-14(a) OF THE
SECURITIES AND EXCHANGE ACT OF 1934
Exhibit 31-6
I, Joseph R. Trpik, Jr., certify that:
1.
2.
3.
4.
I have reviewed this annual report on Form 10-K of Commonwealth Edison Company;
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;
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;
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)
(b)
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
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.
/ S / J OSEPH R. T RPIK , J R .
Senior Vice President, Chief Financial Officer and
Treasurer
(Principal Financial Officer)
Date: February 13, 2017
CERTIFICATION PURSUANT TO RULE 13a-14(a) AND 15d-14(a) OF THE
SECURITIES AND EXCHANGE ACT OF 1934
Exhibit 31-7
I, Craig L. Adams, certify that:
1.
2.
3.
4.
I have reviewed this annual report on Form 10-K of PECO Energy Company;
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;
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;
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)
(b)
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
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.
/ S / C RAIG L. A DAMS
President and Chief Executive Officer
(Principal Executive Officer)
Date: February 13, 2017
CERTIFICATION PURSUANT TO RULE 13a-14(a) AND 15d-14(a) OF THE
SECURITIES AND EXCHANGE ACT OF 1934
Exhibit 31-8
I, Phillip S. Barnett, certify that:
1.
2.
3.
4.
I have reviewed this annual report on Form 10-K of PECO Energy Company;
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;
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;
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)
(b)
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
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.
/ S / P HILLIP S. B ARNETT
Senior Vice President, Chief Financial Officer
and Treasurer
(Principal Financial Officer)
Date: February 13, 2017
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.
2.
3.
4.
I have reviewed this annual report on Form 10-K of Baltimore Gas and Electric Company;
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;
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;
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)
(b)
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
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.
/ S / C ALVIN G. B UTLER , J R .
Chief Executive Officer
(Principal Executive Officer)
Date: February 13, 2017
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.
2.
3.
4.
I have reviewed this annual report on Form 10-K of Baltimore Gas and Electric Company;
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;
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;
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)
(b)
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
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.
/ S / D AVID M. V AHOS
Senior Vice President, Chief Financial Officer
and Treasurer
(Principal Financial Officer)
Date: February 13, 2017
Exhibit 31-11
CERTIFICATION PURSUANT TO RULE 13a-14(a) AND 15d-14(a) OF THE SECURITIES
AND EXCHANGE ACT OF 1934
I, David M. Velazquez, certify that:
1.
2.
3.
4.
I have reviewed this annual report on Form 10-K of Pepco Holdings LLC;
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;
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;
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)
(b)
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
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.
/ S / D AVID M. V ELAZQUEZ
President and Chief Executive Officer
(Principal Executive Officer)
Date: February 13, 2017
Exhibit 31-12
CERTIFICATION PURSUANT TO RULE 13a-14(a) AND 15d-14(a) OF THE SECURITIES
AND EXCHANGE ACT OF 1934
I, Donna J. Kinzel, certify that:
1.
2.
3.
4.
I have reviewed this annual report on Form 10-K of Pepco Holdings LLC;
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;
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;
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)
(b)
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
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.
/ S / D ONNA J. K INZEL
Senior Vice President, Chief Financial Officer and Treasurer
(Principal Financial Officer)
Date: February 13, 2017
Exhibit 31-13
CERTIFICATION PURSUANT TO RULE 13a-14(a) AND 15d-14(a) OF THE SECURITIES
AND EXCHANGE ACT OF 1934
I, David M. Velazquez, certify that:
1.
2.
3.
4.
I have reviewed this annual report on Form 10-K of Potomac Electric Power Company;
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;
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;
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)
(b)
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
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.
/ S / D AVID M. V ELAZQUEZ
President and Chief Executive Officer
(Principal Executive Officer)
Date: February 13, 2017
Exhibit 31-14
CERTIFICATION PURSUANT TO RULE 13a-14(a) AND 15d-14(a) OF THE SECURITIES
AND EXCHANGE ACT OF 1934
I, Donna J. Kinzel, certify that:
1.
2.
3.
4.
I have reviewed this annual report on Form 10-K of Potomac Electric Power Company;
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;
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;
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)
(b)
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
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.
/ S / D ONNA J. K INZEL
Senior Vice President, Chief Financial Officer and Treasurer
(Principal Financial Officer)
Date: February 13, 2017
Exhibit 31-15
CERTIFICATION PURSUANT TO RULE 13a-14(a) AND 15d-14(a) OF THE SECURITIES
AND EXCHANGE ACT OF 1934
I, David M. Velazquez, certify that:
1.
2.
3.
4.
I have reviewed this annual report on Form 10-K of Delmarva Power & Light Company;
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;
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;
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)
(b)
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
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.
/ S / D AVID M. V ELAZQUEZ
President and Chief Executive Officer
(Principal Executive Officer)
Date: February 13, 2017
Exhibit 31-16
CERTIFICATION PURSUANT TO RULE 13a-14(a) AND 15d-14(a) OF THE SECURITIES
AND EXCHANGE ACT OF 1934
I, Donna J. Kinzel, certify that:
1.
2.
3.
4.
I have reviewed this annual report on Form 10-K of Delmarva Power & Light Company;
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;
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;
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)
(b)
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
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.
/ S / D ONNA J. K INZEL
Senior Vice President, Chief Financial Officer and Treasurer
(Principal Financial Officer)
Date: February 13, 2017
Exhibit 31-17
CERTIFICATION PURSUANT TO RULE 13a-14(a) AND 15d-14(a) OF THE SECURITIES
AND EXCHANGE ACT OF 1934
I, David M. Velazquez, certify that:
1.
2.
3.
4.
I have reviewed this annual report on Form 10-K of Atlantic City Electric Company;
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;
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;
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)
(b)
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
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.
/ S / D AVID M. V ELAZQUEZ
President and Chief Executive Officer
(Principal Executive Officer)
Date: February 13, 2017
Exhibit 31-18
CERTIFICATION PURSUANT TO RULE 13a-14(a) AND 15d-14(a) OF THE SECURITIES
AND EXCHANGE ACT OF 1934
I, Donna J. Kinzel, certify that:
1.
2.
3.
4.
I have reviewed this annual report on Form 10-K of Atlantic City Electric Company;
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;
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;
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)
(b)
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
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.
/ S / D ONNA J. K INZEL
Senior Vice President, Chief Financial Officer and Treasurer
(Principal Financial Officer)
Date: February 13, 2017
Certificate Pursuant to Section 1350 of Chapter 63 of Title 18 United States Code
Exhibit 32-1
The undersigned officer hereby certifies, as to the Report on Form 10-K of Exelon Corporation for the year ended December 31, 2016, 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.
/ S / C HRISTOPHER M. C RANE
Christopher M. Crane
President and Chief Executive Officer
Date: February 13, 2017
Certificate Pursuant to Section 1350 of Chapter 63 of Title 18 United States Code
Exhibit 32-2
The undersigned officer hereby certifies, as to the Report on Form 10-K of Exelon Corporation for the year ended December 31, 2016, 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.
/ S / J ONATHAN W. T HAYER
Jonathan W. Thayer
Senior Executive Vice President and Chief Financial Officer
Date: February 13, 2017
Certificate Pursuant to Section 1350 of Chapter 63 of Title 18 United States Code
Exhibit 32-3
The undersigned officer hereby certifies, as to the Report on Form 10-K of Exelon Generation Company, LLC for the year ended
December 31, 2016, 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.
/ S / K ENNETH W. C ORNEW
Kenneth W. Cornew
President and Chief Executive Officer
Date: February 13, 2017
Certificate Pursuant to Section 1350 of Chapter 63 of Title 18 United States Code
Exhibit 32-4
The undersigned officer hereby certifies, as to the Report on Form 10-K of Exelon Generation Company, LLC for the year ended
December 31, 2016, 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.
/ S / B RYAN P. W RIGHT
Bryan P. Wright
Senior Vice President and Chief Financial Officer
Date: February 13, 2017
Certificate Pursuant to Section 1350 of Chapter 63 of Title 18 United States Code
Exhibit 32-5
The undersigned officer hereby certifies, as to the Report on Form 10-K of Commonwealth Edison Company for the year ended December 31,
2016, 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.
/ S / A NNE R. P RAMAGGIORE
Anne R. Pramaggiore
President and Chief Executive Officer
Date: February 13, 2017
Certificate Pursuant to Section 1350 of Chapter 63 of Title 18 United States Code
Exhibit 32-6
The undersigned officer hereby certifies, as to the Report on Form 10-K of Commonwealth Edison Company for the year ended December 31,
2016, 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.
/ S / J OSEPH R. T RPIK , J R .
Joseph R. Trpik, Jr.
Senior Vice President, Chief Financial Officer and Treasurer
Date: February 13, 2017
Certificate Pursuant to Section 1350 of Chapter 63 of Title 18 United States Code
Exhibit 32-7
The undersigned officer hereby certifies, as to the Report on Form 10-K of PECO Energy Company for the year ended December 31, 2016,
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.
/ S / C RAIG L. A DAMS
Craig L. Adams
President and Chief Executive Officer
Date: February 13, 2017
Certificate Pursuant to Section 1350 of Chapter 63 of Title 18 United States Code
Exhibit 32-8
The undersigned officer hereby certifies, as to the Report on Form 10-K of PECO Energy Company for the year ended December 31, 2016,
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.
/ S / P HILLIP S. B ARNETT
Phillip S. Barnett
Senior Vice President, Chief Financial Officer and Treasurer
Date: February 13, 2017
Certificate Pursuant to Section 1350 of Chapter 63 of Title 18 United States Code
Exhibit 32-9
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, 2016, 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.
/ S / C ALVIN G. B UTLER , J R .
Calvin G. Butler, Jr.
Chief Executive Officer
Date: February 13, 2017
Certificate Pursuant to Section 1350 of Chapter 63 of Title 18 United States Code
Exhibit 32-10
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, 2016, 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.
/ S / D AVID M. V AHOS
David M. Vahos
Senior Vice President, Chief Financial Officer and Treasurer
Date: February 13, 2017
Certificate Pursuant to Section 1350 of Chapter 63 of Title 18 United States Code
Exhibit 32-11
The undersigned officer hereby certifies, as to the Report on Form 10-K of Pepco Holdings LLC for the year ended December 31, 2016, 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.
/ S / D AVID M. V ELAZQUEZ
David M. Velazquez
President and Chief Executive Officer
Date: February 13, 2017
Certificate Pursuant to Section 1350 of Chapter 63 of Title 18 United States Code
Exhibit 32-12
The undersigned officer hereby certifies, as to the Report on Form 10-K of Pepco Holdings LLC for the year ended December 31, 2016, 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.
/ S / D ONNA J. K INZEL
Donna J. Kinzel
Senior Vice President, Chief Financial Officer and Treasurer
Date: February 13, 2017
Certificate Pursuant to Section 1350 of Chapter 63 of Title 18 United States Code
Exhibit 32-13
The undersigned officer hereby certifies, as to the Report on Form 10-K of Potomac Electric Power Company for the year ended December 31,
2016, 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.
/ S / D AVID M. V ELAZQUEZ
David M. Velazquez
President and Chief Executive Officer
Date: February 13, 2017
Certificate Pursuant to Section 1350 of Chapter 63 of Title 18 United States Code
Exhibit 32-14
The undersigned officer hereby certifies, as to the Report on Form 10-K of Potomac Electric Power Company for the year ended December 31,
2016, 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.
/ S / D ONNA J. K INZEL
Donna J. Kinzel
Senior Vice President, Chief Financial Officer and Treasurer
Date: February 13, 2017
Certificate Pursuant to Section 1350 of Chapter 63 of Title 18 United States Code
Exhibit 32-15
The undersigned officer hereby certifies, as to the Report on Form 10-K of Delmarva Power & Light Company for the year ended
December 31, 2016, 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.
/ S / D AVID M. V ELAZQUEZ
David M. Velazquez
President and Chief Executive Officer
Date: February 13, 2017
Certificate Pursuant to Section 1350 of Chapter 63 of Title 18 United States Code
Exhibit 32-16
The undersigned officer hereby certifies, as to the Report on Form 10-K of Delmarva Power & Light Company for the year ended
December 31, 2016, 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.
/ S / D ONNA J. K INZEL
Donna J. Kinzel
Senior Vice President, Chief Financial Officer and Treasurer
Date: February 13, 2017
Certificate Pursuant to Section 1350 of Chapter 63 of Title 18 United States Code
Exhibit 32-17
The undersigned officer hereby certifies, as to the Report on Form 10-K of Atlantic City Electric Company for the year ended December 31,
2016, 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.
/ S / D AVID M. V ELAZQUEZ
David M. Velazquez
President and Chief Executive Officer
Date: February 13, 2017
Certificate Pursuant to Section 1350 of Chapter 63 of Title 18 United States Code
Exhibit 32-18
The undersigned officer hereby certifies, as to the Report on Form 10-K of Atlantic City Electric Company for the year ended December 31,
2016, 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.
/ S / D ONNA J. K INZEL
Donna J. Kinzel
Senior Vice President, Chief Financial Officer and Treasurer
Date: February 13, 2017